SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
June 2006
GENERAL INFORMATION
A
INTRODUCTION
___________________________________________________________________________________________________________________________
INTRODUCTION TO THE DRILLING MANUAL
1.0
OBJECTIVES
2.0
CONTENTS
2.1 Source of Information
2.2 Ownership
2.3 Confidentiality
2.4 Contributors
3.0
REVISIONS
4.0
MEDIA
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
June 2006
GENERAL INFORMATION
A
INTRODUCTION
___________________________________________________________________________________________________________________________
INTRODUCTION TO THE DRILLING MANUAL
1.0
OBJECTIVES
This comprehensive manual has been compiled for the main purpose of serving as
a guide to Drilling Operations personnel and a reference to new Drilling Engineers.
Most common Saudi Aramco drilling rig operations have been presented in this
manual to familiarize the reader with the actual step-by-step procedures required to
execute the job. This manual is written in such a way that it is clear, easy to follow,
uses acceptable oilfield terminology, and the information is current and very
specific to Saudi Aramco’s operations.
2.0
CONTENTS
2.1
Source of Information
The information contained in this manual has been collected from many
different sources. These include: Saudi Aramco drilling guideline and
instruction letters, Service Company manuals and catalogues, field
experience, Saudi Aramco’s Completion & Workover training manual, oil
industry recognized standards (e.g. API), and other sources.
2.2
Ownership
Saudi Aramco is the sole owner of the information in this manual. Any
alterations or future updates of this manual shall be done only by the
Workover Engineering and Technical Service Division personnel.
2.3
Confidentiality
The information in this manual has been prepared for Saudi Aramco. Even
though the information is not highly confidential, yet discretion should be
exercised when copying pages for non-Saudi Aramco personnel.
2.4
Contributors
Drilling and Workover staff, along with Laboratory Research and
Development Center personnel have been instrumental in compiling the
information in this manual.
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SAUDI ARAMCO
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
A
DRILLING MANUAL
June 2006
GENERAL INFORMATION
INTRODUCTION
___________________________________________________________________________________________________________________________
3.0
REVISIONS
As in every manual, information has to be periodically updated to reflect changing
field conditions and the application of new technology. Suggested changes should
be forwarded to the General Supervisor of Workover Engineering and Technical
Services Division for review and inclusion in the next update of the manual.
Chapter 1, Section B provides detailed procedures for revising this manual.
4.0
MEDIA
The Drilling Manual will be available on different media to meet user requirements.
These are:
A)
B)
C)
Hard copy.
Electronically, on Drilling & Workover servers.
CD-ROM disc with key word search capability.
Initially, the manual will be available in hard copy format and electronically, on the
servers. Eventually, a CD-ROM version will be distributed to those who require it.
2 of 2
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
B
June 2006
GENERAL INFORMATION
DRILLING MANUAL ORIGINAL ISSUE
AND REVISION GUIDELINES
___________________________________________________________________________________________________________________________
DRILLING MANUAL ORIGINAL ISSUE & REVISION GUIDELINES
1.0
ORIGINAL DOCUMENT ISSUE
1.1 Document Format
1.2 Media
1.3 Distribution
1.3.1 List
1.3.2 Manual Numbering
1.3.3 Responsibility
2.0
REVISIONS
2.1 Frequency
2.2 Revision Format
2.3 Responsibilities
2.3.1 Manual Modification
2.3.2 Manual Distribution
2.4 Distribution Instructions
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
B
June 2006
GENERAL INFORMATION
DRILLING MANUAL ORIGINAL ISSUE
AND REVISION GUIDELINES
___________________________________________________________________________________________________________________________
DRILLING MANUAL ORIGINAL ISSUE & REVISION GUIDELINES
1.0
ORIGINAL DOCUMENT ISSUE
1.1
Document Format
1.1.1
A common format has been developed to maintain structure
uniformity since the manual has been authored by a number of
individuals. Future revisions should utilize the same structure in order
for the Drilling Manual to maintain its organization and appearance.
1.1.2
The Drilling Manual has been prepared using Microsoft Word. Each
chapter will consist of an index page, followed by text. Headings, text
fonts, bullets and indentations will vary throughout the chapter but will
conform to the following guidelines:
A)
Page Set-up:
i)
ii)
iii)
iv)
Margins
Top : 0.5”
Bottom : 0.88”
Left : 1.25”
Right : 1.25”
Header : 0.5”
Footer : 0.19”
Paper Size
Paper Size : Letter
Width : 8.5”
Height : 11”
Orientation : Portrait (checked)
Paper Source
First Page : Default Tray
Other Pages : Default Tray
Layout
Section Start : New Page
Header & Footer : Different Odd & Even (checked)
Different First Page (checked)
Vertical Alignment : Top
1 of 5
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
B
June 2006
GENERAL INFORMATION
DRILLING MANUAL ORIGINAL ISSUE
AND REVISION GUIDELINES
___________________________________________________________________________________________________________________________
B)
Index:
i)
ii)
iii)
iv)
v)
vi)
vii)
C)
Text
i)
ii)
iii)
iv)
v)
vi)
vii)
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Header : ‘As shown above’
Section Heading: Title, Arial 14, Bold, Italic, Centered, Red
First Subheading: Title, Arial 11, Bold, First text indent at
0”, Hanging text indent at 3/8”, Teal
Second Subheading: Title, Arial 11, Bold, First text indent
at 6/8”, Hanging text indent at 1-1/8”, Black
Third Subheading: Title, Arial 11, Bold, First text Indent at
1-1/8”, Hanging text indented at 1-5/8”, Black
The subheadings numbering sequence should be as
follows:
1.0 First subheading
1.1 Second subheading
1.1.1 Third subheading
Page Numbering: None
Section Heading : Title, Arial 14, Bold, Italic, Centered,
Red
First Subheading : Heading 1, Arial 11, Bold, First text
indent at 0”, Hanging text indent at 3/8”, Teal
Second Subheading : Heading 2, Arial 11, Bold, First text
indent at 3/8”, Hanging text indent at 6/8’, Dark Red
Third Subheading : Heading 3, Arial 11, First text indent at
6/8”, Hanging text indent at 1-2/8”, Only number or title
Blue and bolded
Forth Subheading : Body text, Arial 11, First text indent at
1-2/8”, Hanging text indent at 1-5/8”, Black
Fifth Subheading : Body text, Arial 11, First text indent at 15/8”, Hanging text indent at 2”
The subheading numbering sequence should be as
follows:
1.0 First Subheading
1.1 Second Subheading
1.1.1 Third Subheading
A) Fourth Subheading
i)
Fifth Subheading
The First Subheading numbering sequence cannot be
changed. However, subsequent Subheadings can be
altered to Bullets or Lettering, depending on context and
flow of text.
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
B
June 2006
GENERAL INFORMATION
DRILLING MANUAL ORIGINAL ISSUE
AND REVISION GUIDELINES
___________________________________________________________________________________________________________________________
viii) Main Text : Body Text, Arial 11, Text alignment Justify.
ix) Page Numbering: 1 of xx, 2 of xx, etc, the page number
location will alternate between the lower right and left hand
corners.
1.2
Media
The Drilling Manual will be available on three different media to meet user
requirements. These are:
A) Hard copy (3-ring binder).
B) Electronically, on Drilling & Workover servers.
C) CD-ROM disc with key word search capability.
1.3
Distribution
1.3.1
List
Hard copies of the Drilling Manual will be distributed based on need
and accessibility to the LAN servers. A copy of the Drilling Manual will
be stored in electronic form on the LAN server for easy access;
consequently, hard copy distribution will be minimized. The hard copy
distribution of the Manual will be as follows:
A)
B)
C)
D)
E)
F)
G)
General Manager, D&W
Managers, D&W
Rig Superintendents, D&W
General Supervisors, DWOED
Supervisors, DWOED
Rig Foremen, D&W
Loss Prevention Representative
Additional copies of the Drilling Manual requested by individuals other
than those listed above will be considered on a case-by-case basis
and will be decided by the custodian of the Manual, General
Supervisor of Workover Engineering and Technical Services Division.
1.3.2
Manual Numbering
Each hard copy of the Drilling Manual will be numbered to insure the
document is traceable. It will be properly marked, both on the outside
of the binder and on the fist page of the document. A record will be
kept of the Manual numbered and the recipient name.
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SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
B
June 2006
GENERAL INFORMATION
DRILLING MANUAL ORIGINAL ISSUE
AND REVISION GUIDELINES
___________________________________________________________________________________________________________________________
1.3.3
Responsibility
A)
B)
C)
2.0
A designated person will be responsible for distributing all hard
copies of the Drilling Manual to the recipients.
The responsible person will ask each recipient, prior to delivery,
his preference of the Drilling Manual media; hard copy, CD-ROM
(when available) or none.
Copies of the Drilling Manual will be hand-delivered to each
recipient and their initials obtained to verify receipt of the
manual.
REVISIONS
2.1
Frequency
The Drilling Manual will be updated no later than once every two years. The
duration of the revision should not exceed two months since majority of the
changes will be minor.
2.2
Format
The same format as the original Drilling Manual will be followed. All changes
and addendums will be highlighted on a separate page and inserted in the
inside cover of the manual for quick reference. The updated sections or
paragraphs within the Manual will have a line on the side of the page, as
shown to the right of this paragraph. It is also important to change the date of
the updated section in the upper right hand corner of the document.
2.3
Responsibilities
2.3.1
Manual Modification
The General Supervisor of Workover Engineering and Technical
Services will assign a person to undertake the task of modifying the
Drilling Manual. The assigned person will collect all pertinent
information related to updating the Manual, evaluate the proposed
changes/additions, prepare them in a draft form, and circulate to
Management for approval. Once approved, he will modify the Manual
and highlight the changes as described in Section 2.2 above.
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SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
B
June 2006
GENERAL INFORMATION
DRILLING MANUAL ORIGINAL ISSUE
AND REVISION GUIDELINES
___________________________________________________________________________________________________________________________
2.3.2
Manual Distribution
The person designated to modify the Manual will also be responsible
for distribution of copies of the Manual. He may seek the help of a
technician to deliver the Manual to the rig sites if necessary.
2.4 Distribution Instructions
Using the original Drilling Manual distribution list, either inserts, page
replacements or complete Manual replacements will be hand delivered to the
Manual recipients. Old Manuals that have been replaced will new ones will
be destroyed to avoid inadvertent use. When all Manuals have been
delivered, the issue list will be updated to reflect the up-to-date Manual
recipients.
5 of 5
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
C
June 2006
GENERAL INFORMATION
ORGANIZATION AND RESPONSIBILITES
___________________________________________________________________________________________________________________________
ORGANIZATION AND RESPONSIBILITES
1.0
ORGANIZATION CHART
2.0
RESPONSIBILITIES
2.1 Drilling Foreman
2.1.1 Well and Comp Location
2.1.2 Rig Move
2.1.3 Program Execution
2.1.4 Communication
2.1.5 Rig Operations
2.1.6 Record Keeping
2.1.7 Miscellaneous
2.2
Drilling Engineer
2.2.1 Drilling Programs
2.2.2 Communication
2.2.3 Rig Surveillance
2.2.4 Completion Report
2.2.5 Training, Seminars, Forums and Courses
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
C
June 2006
GENERAL INFORMATION
ORGANIZATION AND RESPONSIBILITIES
___________________________________________________________________________________________________________________________
ORGANIZATION CHART AND RESPONSIBILITIES
1.0
ORGANIZATION CHART
1.1
Figure 1-C-1 is the most current organization chart of Drilling & Workover.
Due to periodic reorganization and restructuring of Drilling & Workover, this
chart maybe replaced the next time the manual is due for an update.
DRILLING & WORKOVER
DRILLING & WORKOVER
GENERAL MANAGER
PLANNING & ACCOUNTING
SERVICES UNIT
SUPERVISOR
DRILLING & WORKOVER
SERVICES DEPT.
MANAGER
DRILLING & WORKOVER
ENGINEERING DEPT.
MANAGER
DEVELOPMENT DRILLING
& OFFSHORE WORKOVER
DEPT. MANAGER
DEEP DRILLING
& ONSHORE WORKOVER
DEPT. MANAGER
Material Acquisition
& Forecasting Unit
Supervisor
Drilling Engrg.
Division 1
General Supervisor
Drilling Division 1
Superintendent
Drilling Division 1
Superintendent
Drilling Rig
Support Division
Superintendent
Drilling Engrg.
Division 2
General Supervisor
Drilling Division 2
Superintendent
Drilling Division 2
Superintendent
Dril. Equip. & Water
Well Maint. Div.
Superintendent
Workover Engrg.
& Tech. Srvcs. Div.
General Supervisor
Drilling Division 3
Superintendent
Drilling Division 3
Superintendent
Wellsites Division
Superintendent
Drilling Division 4
Superintendent
Drilling Division 4
Superintendent
Special Projects
Superintendent
Drilling Division 5
Superintendent
Figure 1-C-1
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SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
C
June 2006
GENERAL INFORMATION
ORGANIZATIONS AND RESPONSIBILITIES
___________________________________________________________________________________________________________________________
2.0
RESPONSIBILITIES
2.1
Drilling Foreman
The Drilling Foreman has a diverse set of responsibilities which are very
critical in achieving safe drilling operations. On Contractor operated drilling
rigs, the Foreman is the primary liaison between Saudi Aramco and the
Contractor. On Company owned rigs, he is the primary site leader, directing
all rig operations. Since his responsibilities are numerous and diverse, the
following sections, 2.1.1 through 2.1.7 will only cover his main duties:
2.1.1
Well and Camp Location:
A)
Inspect new well location to ensure well site, roads, power line
crossings, water well location and campsite are within
acceptable limits.
i)
ii)
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Well site and road dimensions must conform to SAES-B062 (See Appendix)
Rig equipment that is being transported to the new well site
should clear the power lines as specified in section 2.1.2
(B).
B)
Insure the flare pit (usually located south of the spud point) is
positioned down-wind of the derrick on all wells except Khuff and
Exploratory.
C)
Two flare pits will be available for Khuff and Exploratory wells.
The advantage of having a second flare pit is that in the event of
an uncontrolled flow and should the flare go out, then the gas
can be safely diverted to the second flare pit. This minimizes
the chances of the flow being ignited by the generators, and
eliminates the necessity or relocating the rig equipment.
Depending on the rig layout, the second pit could be on the
easterly or westerly side of the location; the first pit is usually
located south of the spud point. See Appendix for details.
D)
Camp location for all wells (except Khuff and Exploratory wells)
are selected based on a central site that is in proximity of a
number of upcoming wells to be drilled. This practice eliminates
unnecessary and costly camp moves. It is important to note that
the camp should never be located within walking distance from
the rig.
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
C
June 2006
GENERAL INFORMATION
ORGANIZATION AND RESPONSIBILITIES
___________________________________________________________________________________________________________________________
E)
2.1.2
The rig camp should be in a northerly direction and should be no
less than 3 to 4 Kms from the well site for all Khuff and
Exploratory wells. This distance would allow the rig personnel to
concentrate on controlling the well at the rig site, rather than
having to worry about evacuating the camp in case of an
emergency.
Rig Move:
A)
Witness the rig move. Insure safety guidelines are being
followed at all times while moving the rig and related equipment
to the new well location.
B)
When transporting rig equipment under power lines, clearance
distance becomes important to prevent line severing and
electrocution. The following guidelines are used in determining
safe clearance distance.
i)
ii)
8 feet for 69 kV or greater transmission lines.
5 feet for less than 69 kV transmission lines.
When the above clearances are not possible to attain, then
every effort should be made to find a different rout to transport
the rig equipment. If re-routing is not possible or does not
provide the necessary clearance, then de-energizing the power
line is considered as the last resort.
C)
2.1.3
Witness setting of the main camp.
Program Execution:
A)
Adhere to drilling, supplementary and completion programs.
Review contents of the program to ensure all steps are fully
understood. If unclear, contact the Superintendent or Drilling
Engineering for clarification and consultation.
B)
Discuss the program with the Assistant Foreman, contract rig
Supervisor and Driller to ensure all the steps are clearly
understood.
C)
Any changes from the program will need to be discussed with
the Superintendent to ensure that all the related facts have been
considered.
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SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
C
June 2006
GENERAL INFORMATION
ORGANIZATIONS AND RESPONSIBILITIES
___________________________________________________________________________________________________________________________
2.1.4
2.1.5
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Communication:
A)
Prepare the daily rig activities morning and afternoon reports
and transmit to the Superintendent.
B)
Communicate with Superintendent regarding possible changes
to drilling programs based on operational requirements.
C)
Obtain advice from Drilling Engineering to improve drilling
techniques and as well conditions dictate.
D)
Talk to Service Company representatives regarding operation of
their equipment. The operation of each equipment should be
fully understood prior to running in the well.
E)
Discuss with Superintendent new ideas and suggestions to
improve operating performance and safety procedures. The
Foreman is in the best position to observe and experience firsthand rig activities.
Rig Operations
A)
Directly supervise important rig operations such as nippling up/
down BOPE, running casing/liner, making up bottom hole
assemblies, logging/perforating operations, drilling through
hydrocarbon and potentially problem zones, etc.
B)
Witness all non-routine and critical work, e.g. cementing, fishing,
drill stem testing, kick circulation, testing of BOPs, completion
operations, tripping, etc.
C)
Monitor performance of the bit (weight and RPM) and decide on
when to pull a bit. Determine bit wear grading and replace worn
out equipment.
D)
Order materials and equipment from the Toolhouse in
anticipation of upcoming need.
See that all equipment
necessary for drilling and completing the well, as well as
maintaining the rig, is at the rig site.
E)
Schedule Service Company to perform work on the well as
needed. Provide sufficient lead-time when contacting the
Service Company.
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
C
June 2006
GENERAL INFORMATION
ORGANIZATION AND RESPONSIBILITIES
___________________________________________________________________________________________________________________________
2.1.6
2.1.7
F)
Ensure all work performed on the rig is being performed in a
safe and efficient manner.
G)
Conduct daily inspection and provide proper daily maintenance
of the nearby water supply well.
Record Keeping
A)
Casing, tubing and drill pipe tally.
B)
Tour sheets.
C)
Casing cementing details.
D)
Wellhead and tree work (pack-off energizing and testing, bonnet
testing, etc).
E)
Inspect and record condition of bottom hole assemblies on all
trips. Replace equipment as necessary.
F)
Maintain current pre-recorded information kill sheet.
G)
Prepare other Saudi Aramco forms and paperwork as needed.
Miscellaneous
A)
Training of the Assistant Foreman
B)
Conduct periodic well control and disaster drills
C)
Participate in scheduled rig inspections
D)
Prepare accident reports as necessary
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SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
C
June 2006
GENERAL INFORMATION
ORGANIZATIONS AND RESPONSIBILITIES
___________________________________________________________________________________________________________________________
2.2
Drilling Engineer
The Drilling Engineer is primarily responsible for providing technical support
to the rig operations to which he is assigned. He uses his knowledge and
expertise to advise and recommend solutions to problems and find cost
effective ways of performing rig work. He works closely with the Drilling
Foreman and various organizations within Saudi Aramco to ensure all
requirements are met while drilling the well. The following sections, 2.2.1
through 2.2.6, outline his responsibilities in more detail:
2.2.1
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Drilling Programs
A)
The engineer is responsible for preparing and publishing the
approved drilling program at least one week in advance of
drilling commencement for Development wells and at least two
weeks in advance for Deep Gas and Exploratory wells.
B)
Prior to preparing the program, the engineer should thoroughly
research the drilling practices and problems encountered in
adjacent wells. He is also expected to contact the Geologist,
Production and Reservoir Engineers in charge of the field or
area where the well is to be drilled to obtain important reservoir
information, such as pressures, fluctuation of injection trends,
facility shut-downs, depth of horizons, potential loss circulation
zones, dip angle, etc. He should then design or modify the
standard program (Well Menu) to include this information which
could avoid potential problems while drilling the well.
C)
The engineer will check the surplus material list and include in
the program usable materials in order to reduce inventory.
Surplus material can be used as long as they continue to meet
specifications and are acceptable alternatives without
compromising performance and safety.
D)
As field conditions dictate, the engineer will prepare
Supplements to the original program in order to revise operating
procedures or provide additional direction to the Foreman. The
Supplements should state the purpose it is being issued for and
what problem or change in condition has necessitated the
preparation of the supplement. A supplement program should
be issued ahead of work start-up. Sometimes, temporary handwritten directions are faxed to the Drilling Foreman due to time
constraints while the supplement is being prepared.
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
C
June 2006
GENERAL INFORMATION
ORGANIZATION AND RESPONSIBILITIES
___________________________________________________________________________________________________________________________
E)
Occasionally, a drilling program will be approved but not used
due to schedule changes. In such a case, the engineer is
responsible for checking all the contents of the program to
insure current data is being used; if necessary, he will issue a
supplement to the program. For development wells, this
program review will be done if the elapsed time between
program and spud date exceeds six (6) weeks. On exploration
wells, it is a judgement decision made by the Supervisor or
General Supervisor.
F)
The engineer will design the cement program depending on the
mixing/displacement time calculations and bottom hole
temperatures. If cement additives are to be used, he will
coordinate lab testing on field samples (cement and mix water)
by the Service Company and the Saudi Aramco Laboratory
ahead of time in order to eliminate all uncertainties
Final confirmation tests are coordinated by the Drilling Engineer
after supervising the mixing of chemicals on site, for 13-3/8”, 95/8”, 7” and 4-1/2” liners on Khuff/Pre-Khuff wells. The Drilling
Engineer will also witness these cement jobs.
G)
The engineer will calculate the mud weight to provide the
required overbalance for proper well control. Supervisor should
be consulted if diverting from the established guidelines, as
follows:
i)
ii)
iii)
Known water bearing zones
Known oil & gas bearing zones
Wildcats/outpost wells
100 psi
*300 psi
Based on review of
offset wells and/or
judgement decision
by the Gen. Supvr.
and Manager.
* When drilling oil wells with good offset control, calculate the
overbalance by taking the reservoir pressure and lost circulation
information into consideration. In these cases, the overbalance
could be reduced to the range of 200 to 300 psi. Conversely, if
sufficient offset information is not available, then use the
minimum 300 psi overbalance in the calculations. For Khuff/PreKhuff wells, the 300 psi overbalance guideline will be adhered to
at all times.
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SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
C
June 2006
GENERAL INFORMATION
ORGANIZATIONS AND RESPONSIBILITIES
___________________________________________________________________________________________________________________________
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H)
The engineer will calculate/design an optimum hydraulics
program to maximize hole cleaning and rate of penetration
based on the available rig equipment (pumps, DCs, etc.). He
will study the offset wells and recommend a suitable and costeffective bit program depending on the lithology of the
formations being drilled.
I)
The Drilling Engineer will estimate the target time using the
standard targets for each area for Development wells. For
Exploratory/outpost wells, the engineer will review available
offset well data and assign a realistic target time estimate.
J)
Cost estimate will be prepared for each program or supplement
using the unit price book and Service Company price list.
K)
Program verification: The Drilling Engineering Supervisor is
responsible for reviewing the program with the engineer. The
Supervisor is to pay special attention to mud weight in case of
questionable pressures, and ensure the drilling program
provides safe direction and is both practical and cost effective.
L)
The final completion of a well will be discussed between the
Drilling, Production and Reservoir Engineers, and will conform to
the requirements. The Drilling Engineer is responsible for
insuring the availability of all completion equipment. If the
desired equipment is not available, compatible substitute
equipment is an option provided the proponent is in agreement.
The engineer will include in the completion all drift sizes of
tubing, nipples, crossovers, etc., and the type of packer and
completion fluid. As a final step, he will investigate the
possibility of performing a stimulation to remove formation
damage and improve well productivity.
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
C
June 2006
GENERAL INFORMATION
ORGANIZATION AND RESPONSIBILITIES
___________________________________________________________________________________________________________________________
2.2.2
Communication
The Drilling Engineer must be a good listener and communicator. He
should establish dialog and close contact with the Forman, his
Supervisor. Drilling Superintendent, other Drilling Engineers, Mud and
Cement Lab Experts, Toolhouse and Contractor personnel, Geologist,
Reservoir and Production Engineers to exchange information when
necessary. Periodic field visits to the rig help enhance his working
relationship with the Foreman and rig contract personnel.
2.2.3
Rig Surveillance
A)
The Drilling Engineer will keep abreast of work progress on his
rig(s). On all wells, the engineer will plot the well drill time
progress on a daily basis and ensure that the well work is
proceeding as planned. If progress is slower than expected, he
will investigate the reasons and make recommendations to
remedy the situation. The engineer is expected to anticipate the
technical needs of the rig and keep the Foreman duly advised.
If trouble is experienced on a particular job, the Drilling Engineer
and the Foreman will determine the cause and submit an action
plan. The engineer is expected to witness all subsequent rig
jobs until the problem is resolved.
B)
The engineer is responsible for picking the casing points, coring
points and total depth for the following formations:
i) Ahmadi
When 13-3/8” casing is set 50’ below
Ahmadi
ii) K. S. Member
Water Supply wells (nominal 9-5/8”
C.P, 500’ below K.S.)
iii) Shu’aiba
Water Supply/Producer/Water
Injection wells (nominal 9-5/8” C.P.)
iv) Arab-D/Hanifa/Fadhili Producer/Water Injection wells
(nominal 7” C.P.)
v) Khuff/Pre-Khuff
This is the responsibility of the
Wellsite Geologist
The engineer will inform the Foreman depth of drill time picks
and all pertinent picks (core points, casing points, TDs, Etc.) on
the Tour Sheet. He will sign his name since this is the official
field record for the well.
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GENERAL INFORMATION
ORGANIZATIONS AND RESPONSIBILITIES
___________________________________________________________________________________________________________________________
C)
10 of 11
At the request of the engineer, an open hole caliper log is run
prior to running casing or liner. The engineer will obtain results
of the log and will calculate the cement volumes based on the
bore hole geometry. The cement volume excess should be as
follows:
Full Casing Strings
200 – 250 cubic feet of excess, more
than the caliper volume.
Liners
500 – 700 feet of rise around the DP
(with the hanger setting tool in
place).
D)
The drilling engineer will witness all perforating jobs for
production, cement or injectivity tests. He will discuss with the
Service Company the alternatives to best achieve the objective,
i.e. deep penetration, underbalanced perforating, large entry
holes, gun length, etc.
E)
The engineer will witness all open hole and cased hole Drill
Stem and Production Tests, and he will be responsible for
preparing a detailed testing procedure that satisfies the test
objectives. He is responsible for coordinating the testing
equipment and procedures. He is to discuss all phases of the
operation with his Supervisor and Foreman so that the required
data can be collected with minimum risk to operations.
F)
On deep wells, the drill string requirements should be calculated
for each section of the hole. The Forman and Supervisor must
be informed if the equipment in use is not adequate and needs
to be modified.
G)
The engineer will keep a continuous watch on the mud
properties and propose changes to the system as drilling
parameters also change.
H)
The engineer is responsible for providing technical information
on tubulars ( e.g. collapse, burst, hardness, etc.) to the Forman
as the need arises and provide recommendations on inhibitors.
I)
When running unusual or new equipment, or trial testing a new
procedure, the engineer should be fully informed of the details
and he should witness it while being implemented on the rig.
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
C
June 2006
GENERAL INFORMATION
ORGANIZATION AND RESPONSIBILITIES
___________________________________________________________________________________________________________________________
2.2.4
Completion Report
The Drilling Engineer will prepare completion reports for his well(s)
and submit to the Supervisor within one (1) week of rig release for
Development wells and within three (3) weeks for Exploration or Khuff
wells. It is highly recommended for the engineer to compile the
drilling morning reports on a daily basis in order to meet the
completion submission deadline.
2.2.5
Training, Seminars, Forums and Courses
A)
It is the engineer’s responsibility to stay abreast with new
technology. He must attend courses, seminars and forums, time
permitting, in order to enhance his knowledge of drilling
engineering aspects.
B)
The engineer will devote significant time and effort to mentor
and train young engineers. He will expose the young engineer
to all his responsibilities regarding office and fieldwork.
Following a specified elapsed time, the young engineer should
be on his own and be able to perform the normal duties of a
Drilling Engineer.
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CHAPTER 1
SECTION
D
June 2006
GENERAL INFORMATION
EMERGENCY RESPONSE PLAN
___________________________________________________________________________________________________________________________
EMERGENCY RESPONSE PLAN
1.0
ONSHORE
1.1 The Document
1.2 Purpose
1.3 Content
1.4 Update
2.0
OFFSHORE
2.1 The Document
2.2 Purpose
2.3 Content
2.4 Update
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
D
June 2006
GENERAL INFORMATION
EMERGENCY RESPONSE PLAN
___________________________________________________________________________________________________________________________
EMERGENCY RESPONSE PLAN
1.0
2.0
ONSHORE
1.1
The Document: An Emergency Response Plan has been available since the
early 1980s in the form of a General Instruction, GI-1850.001. The GI is
entitled “Onshore Contingency Plan”. It is periodically updated to reflect
changes in responsibility and policy. The most current revision is dated
08/01/1996. A copy of GI 1850.001 can be found in Chapter XI, Appendix A.
1.2
Purpose: GI 1850.001 contains the Contingency Plan for a disaster
occurring at any onshore wellsite during drilling or workover operation, or
when a Producing organization has turned over responsibility for well control
to the Drilling and Workover organization.
1.3
Content: The GI contains clear instructions and guidelines on who reports
the emergency, how it should be reported, which organizations are
responsible for taking action, and what are some immediate steps to take to
gain expedient control of the well. The document also provides guidance on
intentional well ignition, cost accounting, periodic disaster drills, documenting
and after-the-fact critiquing of the Contingency Plan implementation.
1.4
Update: GI-1850.001 will be updated every 3 years to assure the document
stays current with the ever-changing requirements. Proposed modifications
by individuals should be forwarded to the General Supervisor of Workover
Engineering and Technical Services Division for evaluation and eventual
inclusion into the next update of the GI.
OFFSHORE
2.1
The Document: An Offshore Emergency Response Plan had been available
for sometime as part of the Department Instruction Manual, DIM-1700.001. It
was converted to a General Instruction, GI-1851.001 during the last quarter of
1998 for ease of document storage, access and updating. The GI is entitled
“Drilling and Workover Operations Offshore Contingency Plan”, and it was
last updated as DIM-1700.001 in December 1996. A copy of this new GI
1851.001 can be found in Chapter XI, Appendix A.
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GENERAL INFORMATION
EMERGENCY RESPONSE PLAN
___________________________________________________________________________________________________________________________
2 of 2
2.2
Purpose: GI 1851.001 contains the Contingency Plan for a disaster occurring
at any offshore wellsite during drilling or workover operation, or when
Producing has turned over responsibility for well control to the Drilling and
Workover organization.
2.3
Content: The GI contains clear instructions and guidelines on who reports
the emergency, how it should be reported, and what are some immediate
steps to take to gain expedient control of the well. The document clearly
spells out the responsibilities of each organization that is required to provide
support, including the Marine Department which provides crucial oil spill and
platform fire containment equipment and services. In addition, the GI also
outlines the criteria used in deciding on intentional well ignition, procedures
for cost accounting, periodic disaster drills, documenting and after-the-fact
critiquing of the Contingency Plan implementation.
2.4
Update: GI-1851.001 will be updated every 3 years to assure the document
stays current with the ever-changing requirements. Proposed modifications
by individuals should be forwarded to the General Supervisor of Workover
Engineering and Technical Services Division for evaluation and eventual
inclusion into the next update of the GI.
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
E
June 2006
GENERAL INFORMATION
COMMUNICATION SYSTEMS
___________________________________________________________________________________________________________________________
COMMUNCIATION SYSTEMS
1.0
GENERAL
2.0
SYSTEMS
2.1 ESU (Extended Subscriber Unit)
2.2 IMTS (Improved Mobile Telephone System)
2.3 SSB (Single Side Band Radio)
2.4 Satellite Communication
2.5 Drilling Circuit Radio
3.0
REPAIRS
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
E
June 2006
GENERAL INFORMATION
COMMUNICATION SYSTEMS
___________________________________________________________________________________________________________________________
COMMUNCIATION SYSTEMS
10
GENERAL
1.1
2.0
Communication between the rigs and camp to the Drilling office is of
paramount importance during daily rig operations and emergencies. The rig
Foreman must have the capability to consult the Superintendent and
Engineering on a daily basis as drilling activities progress. He also needs to
be able to call the Toolhouse to order required materials and equipment, and
contact Service Companies to schedule upcoming rig work. During critical
operations or emergencies, the Foreman needs to keep the Superintendent
fully informed of the transpiring events, and be able to discuss action
alternatives as well conditions dictate. The importance of an effective
communication system cannot be stressed enough.
SYSTEMS
Every drilling rig is equipped with more than one communication system to ensure
uninterrupted service. Each system has limitations, however, a combination of
these systems complement each other.
2.1
ESU
This is the primary communication service for all rigs. The ESU, Extended
Subscriber Unit, radio equipment operates in UHF at a range of up to 60 kms
from the rig site. This microwave radio system was originally designed for
narrow band voice transmission only, however, it is also being used for
sending and receiving fax and low speed data transmission via a modem.
Communication on the ESU system is sometimes not possible due to
topographic blind spots, such as sand dune valleys.
2.2
IMTS
This is the backup to the ESU system, designed for use in case of
emergency. IMTS (Improved Mobile Telephone System) is a 25+ year-old
system and carries 4 channels; it is used for voice communication only.
Since spare parts are no longer manufactured, the IMTS equipment will
eventually be phased out in favor of newer state of the art equipment. There
are geographical “dead spots” where communication is not possible due to
limitations in antenna distribution and signal strength.
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GENERAL INFORMATION
COMMUNICAION SYSTEMS
___________________________________________________________________________________________________________________________
2.3
SSB
Single Side Band Radios (SSBs) are mounted on every rig Foreman’s vehicle
and on all offshore rigs. SSB uses high frequency signal and is monitored by
HYZ-3, more commonly known as Y-3. It is possible to make a telephone
patch through HYZ-3 on the SSB radio. First call HYZ-3 and tell the operator
that you wish to make a telephone patch; give him the number you want to
call. If calling the rig from the Drilling Office, call Y-3 and tell the operator the
rig number you would like to contact. The Y-3 telephone number is 8764088. SSB communication can be completely lost for hours since the signal
is sensitive to weather conditions.
2.4
Satellite Communication
Saudi Aramco has units available which have the capability to communicate
with remote sites through Mini-m satellite. The units are compact, battery
charged, portable and easy to operate. The major factor of these equipment
is the high operating unit rate of satellite airtime.
2.5
Drilling Circuit Radio
Every rig is equipped with a drilling circuit radio. Two channels are available:
A or F-1 (while drilling in Northern area) and B or F-2 (while drilling in
Southern area).
3.0
REPAIRS
All communication problems should be reported to “Communication Repair” by
calling 904. A trouble ticket is issued and the faulty communication equipment is
repaired or replaced thereafter.
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CHAPTER 1
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DRILLING MANUAL
June 2006
GENERAL INFORMATION
F
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
RIG SPECIFICATIONS
1.0
GENERAL
2.0
RIG SPECIFICATIONS DATA SHEETS (LAND RIGS)
2.1
ARABIAN DRILLING COMPANY
2.1.1 ADC-3
2.1.2 ADC-4
2.1.3 ADC-12
2.1.4 ADC-14
2.1.5 ADC-15
2.1.6 ADC-16
2.1.7 ADC-21
2.1.8 ADC-23
2.1.9 ADC-28
2.1.10 ADC-29
2.1.11 ADC-31
2.1.12 ADC-32
2.1.13 ADC-34
2.1.14 ADC-35
2.1.15 ADC-36
2.1.16 ADC-39
2.2
RAWABI DALMA LTD.
2.2.1 DALMA-1
2.2.2 DALMA-2
2.2.3 DALMA-7
2.2.4 DALMA-8
2.2.5 DALMA-9
2.2.6 DALMA-10
2.3
DRILLING & PETROLEUM SERVICES CO.
2.3.1 DPS-4
2.3.2 DPS-43
2.3.3 DPS-44
2.3.4 DPS-45
2.3.5 DPS-46
2.4
POOL ARABIA LIMITED
2.4.1 PA-70
2.4.2 PA-77
2.4.3 PA-115
2.4.4 PA-117
2.4.5 PA-125
2.4.6 PA-128
2.4.7 PA-203
2.4.8 PA-207
2.4.9 PA-210
2.4.10 PA-212
2.4.11 PA-263
2.4.12 PA-295
1
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Drilling & Workover Engineering Department
CHAPTER 1
SECTION
F
DRILLING MANUAL
June 2006
GENERAL INFORMATION
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.4.13
2.4.14
2.4.15
2.4.16
2.4.17
2.4.18
2.4.19
2.4.20
2.4.21
2.4.22
2.4.23
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PA-312
PA-393
PA-575
PA-654
PA-718
PA-785
PA-854
PA-858
PA-859
PA-860
PA-866
2.5
PRECISION DRILLING SERVICES
2.5.1 PD-144
2.5.2 PD-157
2.5.3 PD-173
2.5.4 PD-174
2.5.5 PD-786
2.5.6 PD-787
2.6
SAUDI ARAMCO DRILLING CO.
2.6.1 SAR-102
2.6.2 SAR-103
2.6.3 SAR-151
2.6.4 SAR-153
2.7
ZP ARABIA DRILLING CO.
2.7.1 SINO-1
2.7.2 SINO-2
2.7.3 SINO-3
2.7.4 SINO-5
2.7.5 SINO-6
2.7.6 SINO-7
2.7.7 SINO-9
2.7.8 SINO-10
2.7.9 SINO-12
2.7.10 SINO-18
2.8
SINO PAC DRILLING COMPANY
2.8.1 SP-1
2.9
SAUDI ARABIA SAIPEM LTD.
2.9.1 SSA-29
2.9.2 SSA-46
2.9.3 SSA-91
2.9.4 SSA-95
2.9.5 SSA-101
2.9.6 SSA-102
2.9.7 SSA-201
2.9.8 SSA-202
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
F
June 2006
GENERAL INFORMATION
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
3.0
RIG SPECIFICATIONS DATA SHEETS (OFFSHORE RIGS)
3.1
ARABIAN DRILLING COMPANY
3.1.1
ADC-17
3.2
ENSCO ARABIA LIMITED
3.2.1
ENS-76
3.2.2
ENS-95
3.2.3
ENS-96
3.2.4
ENS-97
3.3
POOL ARABIA LIMITED
3.3.1
PA-145
3.3.2
PA-656
3.3.3
OS-655
3.4
PRIDE ARABIA COMPANY
3.4.1
PM-1
3.4.2
PND-1
3.5
ROWEN ARABIA DRILLING CO.
3.5.1
RM-22
3.5.2
CR-36
3.5.3
AR-37
3.5.4
RC-42
3.6
SAUDI ARABIAN SAIPEM LIMITED
3.6.1
PN-2
3.6.2
PN-5
3.7
SAUDI ARAMCO DRILLING CO.
3.6.1
SAR-201
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GENERAL INFORMATION
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
RIG SPECIFICATIONS
1.0
GENERAL
1.1
During drilling operations, it becomes necessary at times to perform rig work,
such as fishing or running casing, that requires rig equipment to be operated
near the designed limit. If this limit is exceeded, then the equipment is likely
to fail thus causing financial loss and delays in the drilling operations. It is
common practice to review the rig equipment specifications in order to
operate within its capabilities and limitations.
1.2
Each and every rig is supplied with different equipment.
components of a rig can be categorized as follows:
A)
B)
C)
D)
E)
F)
1.3
2.0
The main
Rig equipment
Rig power
Mud system & pump
BOP equipment
Safety Equipment
Drill pipe & drill collars
Important information about a rig is the depth limitation or capacity. Every
piece of equipment has a maximum operating limit before failure occurs. In
the case of the rig depth limitation, it is based on the load the derrick structure
can sustain during operations. The limit is calculated based on the drill pipe
size (and weight) to be run, additional equipment on the drill pipe, and the
amount of overpull which might be needed in case of getting stuck. There
are also safety factors included in the limitation to account for normal wear
and tear.
SPECIFICATION DATA SHEETS
Since rig contractors are periodically changed, new rig specification sheets are
required. Also, existing rig equipment is sometimes modified or replaced. For
these reasons, it is important to update the Specification Data Sheets in section 2.0
of this chapter every time the Drilling Manual is revised. As of May, 1999, there
were 23 onshore and 2 offshore drilling rigs in operation.
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SECTION
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RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.1.1
ADC-3 (ONSHORE RIG)
A)
Year Built
:
1978
B)
Rig Equipment
1. Drawworks – Type
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National 110-UE
Pyramid Open Face Cantilever Type, 143’ x 25’
700,000 lbs.
Varco TDS-11SA
National C-375 (37-1/2”), Independent drive
National – 660-H-500, 500 Tons (Hook/Block Combination)
National P-400, 400 Tons Static
20’ (clearance) from ground to rotary beam
Not Operating; ADC system in place – ID3
Rig Power
1. Engine Power
2. Drawworks
:
:
3.
4.
5.
:
:
:
5 x Caterpillar D398, 900 hp
National 110-UE, 1500 hp
2 x GE 752 Shunt motors – 800 hp each
2 x G-D PZ-11, 1600 hp, 4 x GE 752 Shunt motors – 800 hp each
1 x GE 752 Shunt motor – 900 hp, 180 RPM, 30000 ft-lbs torque
1 x AC Motor, 800 hp each, 37,500 ft-lbs torque
:
:
:
:
:
:
:
2 Gardner Denver PZ-11, 1600 hp
2100 bbl. capacity, 128 bbl trip tank
2 x Derrick-Flo Line Cleaners
Swaco 2 x 12” cones, 1000 gpm
Swaco 20 x 4” cones, 1000 gpm
None
Swaco horizontal, 1000 GPM
C)
D)
Mud pumps
Rotary
Top Drive
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
E)
BOP Equipment (per Saudi Aramco Class ‘A’ Standard)
1. Accumulator
: 3000 psi, Koomey
2. Choke manifold
: 5000 psi WP, sour service
3. BOPs
: Cameron U 13-5/8” double ram, 5000 psi, H2S trim
Cameron U 13-5/8” single ram, 5000 psi, H2S trim
Hydril GK 13-5/8” x 5000 psi, H2S trim
Hydril MSP 21-1/4”, 2000 psi, H2S trim
F)
Safety Equipment
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
62 Fire extinguishers, 2 fire pumps (one at main camp), 2 portable
3-way, continuous monitoring detectors (O2/LEL/H2S), 1 cascade
system, 18 Scott Air Pack SCBAs, 5 eye wash stations, 3 shower
units, 5 wind socks, 1 Bauer (K-146) breathable air compressor.
HWDP
Drill collars
:
:
:
:
5” Grade G, 19.5 lbs./ft, 10,000 ft.
4”, 14#/ft, XT39, G-105Y, 16,000 ft.
60 of 5”, 80 of 4”
12 of 9-1/2”, 30 of 8-1/2”, 30 of 6-1/4”, 30 of 4-3/4”, 15 of 3-3/8”
H)
Depth Capacity
:
16,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
26.0 ft
0.0 ft
2.
3.
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F
SECTION
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RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.1.2
ADC-4 (ONSHORE RIG)
A)
Year Built
:
1973
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Gardner Denver 1100E – 1500 HP with auxiliary brake
Lee C. Moore 25’ x 145 ft
769,000 lbs.
Varco TDS 9S
National C375, 37 ½”
Continental Emsco – 350 Ton
National P-400 – 400 Ton
Specify structure type and load bearing capacity?
Totco, 6-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x CAT D398, 925 HP ea. w/ xxxx KVA generators
2 x GE 752 motors, 800 HP ea.
4 x GE 752 motors, 800 HP ea.
GE 752 DC motor, 750 HP, Torque xxx Amps / xxxxx ft.-lbs
Specify power & model? 700 HP, Torque xxx Amps / xxx ft.-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander / Desilter
5. Centrifuge
6. Degasser
:
:
:
:
:
:
2 x National 10 P 130 – 1300 HP ea.
1300 bbl. capacity with 60 bbl trip tank and 1100 bbl reserve
2 x Derrick Flo-line cleaners
Swaco 212 / Swaco PO4C16 – 800 GPM ea.
None
Swaco model?– 800 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, Koomey model and model No. of stations?
3 1/8” Make? 5,000 psi WP, sour service
Hydril MSP 21 ¼” annular, 2000 psi, Hydril GK 13-5/8” annular,
5000 psi, Cameron U 13-5/8” double ram, 5,000 psi, All H2S
trimmed.
F)
Safety Equipment
:
74 fire extinguishers, 1 fire pump, 2 Gas detector, 1 H2S monitoring
system, 1 Cascade system, 38 Scott SCBA`s, 3 eye wash stations,
1 shower at mud pits, 3 wind socks, 1 Bauer breathing air
compressor, 1 foam unit
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
5 Grade-G, 19.5 lbs/ft, 10000 ft, 3 ½” Grade-G, 13.3 lbs/ft, 10000 ft.
2 3/8” Grade-E 6.65 lbs/ft, 2000 ft.
60 of 5”, 100 of 3 ½”
9 of 9 ½”, 24 of 8 ½”, 24 of 6 ½”, 24 of 4 ¾”, 24 of 3 3/8”
H)
Depth Capacity
:
16,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
25.5 ft
21.5 ft
C)
D)
E)
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RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.1.3
ADC-12 (ONSHORE RIG)
A)
Year Built
:
1986
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National 110-UE – 1500 HP with auxiliary brake
Lee C. Moore 25’ x 149 ft
710,000 lbs.
National PS 350/500 – xxx Ton
National C375, 37 ½” – xxx Ton
Continental Emsco – 350 Ton
National P-400 – 400 Ton
Specify structure type and load bearing capacity?
Totco, 6-pen
Rig Power
1. Engine Power
:
2.
3.
4.
5.
:
:
:
:
4 x Caterpillar D398, 825 HP ea. 1 x Caterpillar D399, 100 HP w/
xxxx KW Generator
2 x GE 752 motors, 1000 HP ea.
4 x Reliance model motor, 1000 HP ea.
1 GE 752 DC motor, 750 HP, Torque xxx Amps / xxxxx ft.-lbs
Specify make and model ? HP 1000, Torque xxx Amps / xxx ft.-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x Gardner Denver PZ10, 1300 HP ea
1500 bbls capacity with 120 bbl trip tank
2 x Derrick Flo-line cleaners
Swaco 212 – 800GPM
specify make size and capacity in GPM?
None
Swaco model – 800 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, NL Shaffer / Koomey Type 20
3 1/8” 5,000 psi WP, sour service
Hydril MSP 21 ¼” annular, 2000 psi, Hydril GK 13-5/8” annular,
5000 psi, Cameron UU 13-5/8” double ram, 5,000 psi, All H2S
trimmed.
F)
Safety Equipment
:
33 fire extinguishers, 1 fire pump, 1 Gas detector, 1 H2S detector,
1 Cascade system, 22 Scott SCBA`s, 3 portable gas monitors, 6
H2S portable monitors, 4 eye wash stations, 4 wind socks, 2
showers at mud pits, 1 Bauer breathing air compressor, 1 foam unit
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
5 Grade E, 19.5 lbs/ft., 10,000 ft.,
3 ½” Grade G105, 13.3 lbs/ft, 10,000 ft.
70 of 5”, 99 of 3 ½”
7 of 9 ½”, 30 of 8 ½”, 30 of 6 ½”, 24 of 4 ¾”, 21 of 3 3/8”
H)
Depth Capacity
:
16,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
30.0 ft
22.3 ft
C)
D)
E)
Drawworks
Mud pumps
Rotary
Top Drive
7 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.1.4
ADC-14 (ONSHORE RIG)
A)
Year Built
:
1975 (Mast Inspection, BOP upgrade to 10,000 psi with Choke
Manifold and Mud System. New T. Block, Sub base Extension)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National 110-UE (1500HP)
Lee C. Moore 25’ x 149 ft
750,000 lbs.
Varco TDS-11S
Ideco 375E, 37 ½”
National 660H – 500 Tons
National P-400
Lee C. Moore, Casing 5,000,000 lbs, setback 7,000,000 lbs.
Totco, 6 pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
:
:
:
:
5.
:
5 x Caterpillar D398TA, 910 HP ea. with 930 KW GE Generators.
2 x GE 752 motors – 750 HP ea.
4 x GE 752 motors – 750 HP ea.
GE 752 DC motor – 750 HP, Torque Continuous 800 Amps
Torque Intermittent 1500 Amps.
AC motor – HP 800, Torque Continuos: 32,500 ft-lbs.
Torque Intermittent: 50,000 Ft Lb.
C)
D)
Top Drive
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
5. Centrifuge
6. Degasser
:
:
:
:
:
:
:
2 x Gardner Denver PZ11, 800 HP ea.
3000 bbls capacity with 2 x 60 bbl trip tanks
3 x Derrick Flo-line cleaners
Derrick 3 x 10” cone – 600 GPM
Derrick 20 x 4” cone – 600 GPM
None
Swaco with type 30 Vacuum pump – 550 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, Stewart & Stevenson Koomey Type 80
4-1/16”, 10,000 psi WP, sour service
2 x Cameron U 13-5/8”, 10,000 psi, double, 3 x Stewart &
Stevensen 20 ¾”, 5000 psi, 1 x SS Q 26 ¾”, 3000 psi, double, 1 x
Hydril GK, 13-5/8”, 5000 psi, 1 x Hydril MSP, 21 ¼”, 2000 psi, 1 x
Shaffer, 30”, 1000 psi
F)
Safety Equipment
:
33 fire extinguishers, 1 fire pump, 1 Gas detector, 1 h2S detector,
1 Cascade system, 22 scott SCBA`s, 3 portable gas monitors, 6
H2S portable monitors, 4 eye wash stations, 4 wind socks, 2
showers at mud pits, 1 Bauer breathing air compressor, 1 foam unit
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
5” Grade-G105, 19.5 ppf, 15,000 ft., 3 ½” Grade-G105,
13.3 ppf, 9,000 ft, 2-3/8” Grade-E, 6.65 ppf, 5,000 ft
50 of 5”, 50 of 3 ½”
30 of 6 ½”, 30 of 4 ¾”, 24 of 2 7/8”
H)
Depth Capacity
:
15,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
30.0 ft
26.0 ft
E)
8 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.1.5
ADC-15 (ONSHORE RIG)
A)
Year Built
:
2001
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Midcontinent U-1220 EB (1220 HP) w/ xxxxxxxx auxiliary Brake
Dreco 25’ x 20’ x 146 ft.
1,300,000 lbs. (static) with 12 lines
National Oilwell, PS 350/500 – xxx Ton
Oilwell, Model? 37 ½” – xxx Ton
Ideco Model? – 650 Tons
National Model? – 650 Tons
Dreco slingshot type, specify load capacity?
Totco, 6 pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
6 x Caterpillar D398TA, 1000 HP ea. w/ xxxxx 1778KVA generators
2 x EMD D79 motor, 1000 HP ea. (Different HP? Please check)
2 x EMD D79 motor, 800 HP ea.
GE 752 DC motor, 1000 HP Torque ------ Amps / ------- ft-lbs.
GE 752 motor Torque ------ Amps / ------- ft-lbs.
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander / Desilter
5. Centrifuge
6. Degasser
:
:
:
:
:
:
2 x Gardner Denver PZ11, 800 HP ea.
4000 bbls mud & 1000 bbls drill water, 60 bbl trip tank
3 x Derrick Flo-line cleaners
Derrick, 2 x 12” – 800 GPM / 12 x 4” – 800 GPM
Swaco - SC4, Capacity GPM?
Swaco – 1000 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
Stewart & Stevensen Koomey Unit, Type 80
10,000 psi WP, sour service
2 x Cameron U 13-5/8”, 10,000 psi, double, 3 x Stewart &
Stevensen 20-3/4”, 5000 psi, 1 x SS Q 26-3/4”, 3000 psi, double,
Hydril GK, 13-5/8”, 5000 psi, Hydril MSP, 21-1/4”, 2000 psi,
Shaffer, 30”, 1000 psi
F)
Safety Equipment
:
80 Fire extinguishers, 1 Fire pump, 1 gas detector, 1 H2S detector,
1 cascade system, Scott SCBAs, 3 portable gas monitors, eye
wash stations, 2 shower at mud pits, 3 wind socks, 2 foam units,
1 breathable air compressor
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
5-1/2’ Grade E, 24.7 lbs./ft., 10,000 ft., 5” Grade G, 19.5 lbs./ft.,
15,000 ft, 3-1/2” Grade G, 15.5 lbs./ft, 15,000 ft
25 of 5-1/2”, 30 or 5”, 30 of 3-1/2”
17 of 9-1/2’, 24 of 8-1/4”, 30 of 6-1/4”, 30 of 4-3/4”
H)
Depth Capacity
:
25,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
31 ft
27 ft
C)
D)
E)
9 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
F
SECTION
June 2006
GENERAL INFORMATION
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.1.6
ADC-16 (ONSHORE RIG)
A) Year Built
:
1975
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National 1320EU, 2000 HP
Dreco 30 ft x 152 ft.
1,200,000 lbs with 12 Lines
National PS500 (PS2)
National C375
National 650 Ton
National P500
Dreco
Schlumberger iD3 System, 26 function digital recorder
Rig Power
1.
2.
3.
4.
5.
:
:
:
:
:
5 x Caterpiller D399 – 1215 HP ea
2 x GE 752, DC motor – 1000 HP ea Check HP?
6 x GE 752 DC motor – 1000 HP ea
GE 752 DC motor – 1000 HP Torque 1050 Amps / 54,000 ft.-lbs.
GE 752 DC motor, Torque 1050 Amps / 54,000 ft.-lbs.
Mud System & Pump
1. Mud Pumps
2. Mud Pits & Storage
3. Shale Shakers
4. Desander
5. Desilter
5. Centrifuge
6. Degasser
:
:
:
:
:
:
:
3 x National 12P160 (1600 HP)
2,000 bbl active, total 4,000 capacity
3 x Derrick Linear Motion Flo-Line Cleaner – 513
Derrick 3 cone
Derrick 24 cone,
None
Derrick vacuum – 1200 GPM
BOP Equipment
1. Accumulator
2. Choke Manifold
3. BOP’s
:
:
:
Cameron, 3,000 psi, 14 Stations
4-1/16'' 10,000 psi
Shaffer 30” Annualr Preventer – 1000 psi, Hydril 21 ¼” Annualr
Preventer – 2000 ps, 1X 13-5/8'' 5K Hydril Annular Preventer, 1X
26-3/4'' 3K Cameron Single RAM, 1X 26-3/4'' Cameron Double
RAM, 2 X 13-5/8'' 10K Cameron Double RAM
F)
:
100 Fire extinguishers, 1 Fire pump, Air cascade system, 12
Breathing 5 min apparatus, 19 SCBA 30 min Breathing Apparatus,
Fixed gas detection system, Portable gas detection Equipment,
5 eye wash stations, 1 emergency shower, 4 x wind socks
Engine Power
Drawworks
Mud Pumps
Rotary
Top Drive
Safety Equipment
G)
Drill Pipes & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
5 ½” Grade G, 24.7 lbs./ft, 12,000 ft., 5” Grade G, 19.5 lbs/ft, 15000 ft,
3-1/2” Grade G, 13.3 lbs./ft, 9,000 ft.
15 x 6 5/8”, 30 x 5 ½”, 50 x 5”, 50 of 3-1/2”
18 of 9-1/2”, 30 of 8-1/2”, 30 of 6-1/4”, 30 of 4-3/4”
H)
Depth Capacity
:
19,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
33.0 ft
27.0 ft
10 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.1.7
ADC-21 (ONSHORE RIG)
A)
Year Built
:
1982
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Gardner Denver 3000 E (3000 HP) w/ 7838 Elmagco Auxiliary Brake
L.C. Moore, 30’ x 26’ x 147 ft.
1,550,000 lbs. (static) with 12 lines
Hydralift, Hydraulic HPS 500 – 500 Ton
Continental Emsco, 37-1/2” – 750 Ton
LC Moore, Crown / Travel Combination – 650 Tons
Continental Emsco LB650 – 650 Tons
L.C. Moore, slingshot, casing 1,500,000 lbs. setback 800,000 lbs.
MD/Totco, 6-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x Caterpillar D399 – 1215 HP ea. w/ Kato 1050 KW generators
3 x EMD D79 DC motors – 1000 HP ea.
4 x EMD D79 DC motors – 800 HP ea.
EMD D79 DC motor Torque 763 Amps / 24,000 ft-lbs.
GE 752 DC motor Torque 1270 Amps / 36,000 ft-lbs.
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x Gardner Denver PZ11, 1600 HP ea.
4000 bbl capacity with 1208 bbl. active and 120 bbl trip tank
Derrick shakers, 3 x Derrick Fl-Line cleaners
Harrisburg 2 x 12” cone – 1600 GPM
Harrisburg 16 x 4” cone – 1600 GPM
None
Swaco Vacuum type Horizontal & Poor-by Vertical – 1200 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP Koomey w/ 14 stations and 40 x 11 gal. bottles
4 1/16” Cameron 10,000 psi WP, sour service
Cameron 13-5/8” double ram, 10,000 psi, 2 x Cameron 13-5/8”
single ram, 10,000 psi. 1 Cameron U 20-3/4” double ram, 3000 psi,
1 Cameron U 20-3/4” single ram, 3000 psi, 2 x Cameron U 26-3/4”
single ram, 3000 psi, Hydril GL 13-5/8”, 5000 psi; Hydril MSP, 211/4”, 2000 psi, Shaffer 30” annular 1000 psi
F)
Safety Equipment
:
Fire extinguishers, 1 Fire pump, fixed gas detector system, 1
cascade system, Scott SCBAs, portable gas detectors, eye wash
stations and showers, 3 wind socks, 1 foam unit, 1 breathable air
compressor
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
:
:
5.5” Grade G 24.7 ppf, 12,000 ft.; 5” Grade G, 19.5 ppf, 15,000 ft.
3-12” Grade G, 13.3 ppf, 9,000 ft.
30 of 5-1/2”, 50 of 5”, 30 of 3-1/2”
12 of 9-1/2”, 30 of 8-1/2’, 30 of 6-1/4”, 30 of 4-3/4”
C)
D)
E)
HWDP (Joints)
Drill collars (Joints)
H)
Depth Capacity
:
25,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
34.0 ft
27.0 ft
11 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.1.8
ADC-23 (ONSHORE RIG)
A)
Year Built
:
1975 (Completely refurbished in 2005)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National Oil Well E-3000
Dreco, 30’ x 160 ft.
1,500,000 lbs. (static) with 12 lines
National Oil Well PS750/500
National C-375 (37-1/2”)
National – 750/500
National Oilwell, 750/500
Dreco, Load Casing 2,360,000 lbs.
Schlumberger, ID Cubed with 26 functions digital recorder
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x Caterpillar D3512 – 1450 HP ea.
3 x GE 752 motor – 1000 HP ea.
6 x GE 752 motors – 1000 HP ea.
Ind. Dr, GE 752 motor, 1000 HP, Torque 1050 Amps / 39500 ft.-lbs
AC motor, 1400 HP, Torque 1600 Amps / 89,000 ft.-lbs.
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
3 x National 14P220 (2200 HP)
4000 bbl. capacity, 120 bbl trip tank
3 x Derrick-Flo Line Cleaner
Derrick – 1000 GPM
Derrick High G – 1600 GPM
None
Derrick – 1000 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, Koomey
10000 psi WP, Cameron, sour service
Cameron UU 13-5/8” double ram, 10000 psi,
Cameron U 13-5/8” double ram, 10000 psi,
Hydril GK 13-5/8” x 5000 psi,
Hydril MSP 20” and 20-1/4”, 2000 psi, All H2S trimmed
F)
Safety Equipment
:
105 Fire extinguishers, 2 Fire pump, 2 gas detector, 4 H2S
detectors, 1 cascade system, 17 Scott Air Pack SCBAs, 2 portable
gas/ H2S monitors, 5 eye wash stations, 3 shower-mud pits, 4 wind
socks, 1 Drager H2S sniffer, 1 Bauer Breathable air compressor
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
5.5” Grade XD-105 24.7 ppf, 14,300 ft.
5.5” Grade S-135, 24.7 ppf, 7000 ft
4” Grade XD-105, 14.4 ppf, 9,860 ft.
41 of 5.5”, 53 of 4”
18 of 9-1/2”, 28 of 8-1/2”, 40 of 6-1/4”, 5 of 4-3/4”
H)
Depth Capacity
:
25,000 feet
I)
DF – GL Elevation
Clearance below DF
:
:
38.5 ft
28.5 ft
C)
D)
E)
12 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.1.9
ADC-28 (ONSHORE RIG)
A)
Year Built
:
1981
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Gardner Denver 1100E (1500 HP) with Auxiliary brake
Pyramid, 25 ft x 160 ft
1,000,000 lbs (static) with 12 lines
TDS-11 SA, – 500 Ton
Continental Emsco T375 37 ½” – 650 Ton (static)
National 650-G500 – 650 Ton (Hook block combination)
National P-400 – 400 Ton (static), 268 Ton (dynamic)
Pyramid, Lo-lift Cantilever, casing xxxxxx lbs, setback xxxxxx lbs.
Schlumberger ID3, 26 function digital data recorder
Rig Power
1. Engine Power
2. Drawworks
3. Mud Pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x Caterpillar D-398TA – xxxx HP ea. w/ 1165 KVA generators
2 x GE 752 motors – xxxxx HP ea.
4 x GE 752 motors – xxxxx HP ea
GE 752 DC motor – xxxxx HP, Torque ---- Amps / ----- ft-lbs.
2 x Reliance motors - 400 HP ea, Torque ---- Amps / ---- ft-lbs
Mud System & Pump
1. Mud Pumps
2. Mud Pits & Storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x Gardner Denver PZ11, 1600 HP ea.
2000 bbl capacity with 50 bbl trip tank,
1 x Derrick 2000 Flo-Line Cleaner, 1x Derrick 503 Flo-Line Cleaner
Swaco 2 x 12” Cone – 1000 GPM
Swaco 16 x 4” Cone – 1000 GPM
None
Swaco Horizontal Vacum – 1200 GPM
:
:
:
3000 psi, CAD 24 x 11 gal bottles, 12 stations
3 1/8” Cameron FLS, 5000 psi
Hydril MSP-20, 21 ¼” Annular 2000 psi,
C)
D)
E)
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
Annular,
Hydril GK, 13 5/8"
5000 psi, Cameron U 13 5/8” single ram 5000 psi, Cameron U
13 5/8" double ram 5000 psi w/ tandem booster
F)
Safety Equipment
:
81 Fire extinguishers, 1 Fire pump, 1 gas detector, 4 H2S detectors,
1 cascade system, 16 Scott Air Pack SCBAs, 2 portable gas/ H2S
monitors, 3 eye wash stations, 1 shower-mud pits, 4 wind socks, 1
Drager H2S sniffer, 1 Bauer Breathable air compressor, 1 foam unit.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
5” Grade-G, 19.9 lbs/ft, 10000 ft, 4” Grade-XD, 14.4 lbs/ft, 10,000 ft,
2 3/8” Grade-E 6.6 lbs/ft, 3000 ft.
60 of 5", 80 of 4"
12 of 9 ½”, 30 of 8 ½”, 30 of 6 ¼”, 30 of 4 ¾”, 15 of 3 3/8”
H)
Depth Capacity
:
18,000 ft with 4 ½” Drillpipe
I)
DF – GL Elevation
Clearance below DF
:
:
xx.x ft
xx.x ft
13 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.1.10
ADC-29 (ONSHORE RIG)
A)
Year Built
:
1981
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Gardner Denver 1100E (1500 HP) w/ xxxxx auxiliary brake
Pyramid, 160 ft high x 25 ft square base
1,000,000 lbs (static) with 12 lines
TDS-11 SA, 500 Ton
Continental Emsco T375, 650 ton static load
Continental Emsco RA-52-6, 500 Ton
National P-400, 400 Ton static, 268 Ton dynamic
Pyramid, Lo-Lift Cantilver casing xxxxxx lbs, setback xxxxxx lbs
Schlumberger ID3, 26 function digital data recorder
Rig Power
1. Engine Power
2. Drawworks
3. Mud Pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x CAT D-398TA ---- HP ea.
2 x GE 752 DC motors – ------ HP ea.
2 x GE 752 DC motors f– ------ HP ea.
1 x GE 752 DC Shun Motor ---- HP, Torque ---- Amps / ----- ft.-lbs
2 x Reliance AC Motors 400 HP ea, Torque ---- Amps / ---- ft.-lbs
Mud System & Pump
1. Mud Pumps
2. Mud Pits & Storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x Gardner Denver PZ11, 1600 HP
1500 Bbl. active, 500 Bbl. reserve, …. Bbl. Trip tank
2 x Derrick 2000 Flo-Line Cleaner
Derrick 2 x 12”cone – 1000 GPM
Derrick 16 x 4” cone – 1200 GPM
None
Derrick, Vacu-Flo vacuum – 1200 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, CAD 24 x 11 gal bottles, 12 stations
3 1/8” Cameron FLS 5000 psi WP, sour service?
Hydril MSP-20, 21 ¼” Annular 2000 psi, Hydril GK, 13 5/8" Annular
5000 psi, Cameron U 13 5/8" single ram 5000 psi, Cameron U
13 5/8" double ram 5000 psi with tandem Boosters, All H2S trimmed
F)
Safety Equipment
:
81 Fire extinguishers, 1 Fire pump, 1 gas detector, 4 H2S detectors,
1 cascade system, 16 Scott Air Pack SCBAs, 2 portable gas/ H2S
monitors, 3 eye wash stations, 1 shower-mud pits, 4 wind socks, 1
Drager H2S sniffer, 1 Bauer Breathable air compressor, 1 foam unit.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
lbs./ft,
:
5” Grade G-105, 19.9 lbs/ft, 10,000 ft., 4” Grade XD-105, 14.4
2.
3.
HWDP
Drill collars
:
:
16,000 ft., 2-3/8" Grade E-95, ---- lbs/ft, 3,000 ft.
60 of 5", 80 of 4"
12 of 9 ½”, 30 of 8 ½”, 30 of 6 ¼”, 30 of 4 ¾”, 15 of 3 3/8”
H)
Depth Capacity
:
18,000 ft with 4 ½” Drillpipe
I)
DF – GL Elevation
Clearance below DF
:
:
xx.x ft
xx.x ft
C)
D)
E)
14 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.1.11
ADC-31 (ONSHORE RIG)
A)
Year Built
:
2005
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National 1100 UE, 1500 HP with xxxxxx Auxiliary brake
Dreco Beam Leg – 30 ft x 152 ft.
1,300,000 lbs (static) with 12 lines.
Varco-TDS 11SA – 500 Ton
Continental Emsco -T375 (37 ½”) – 650 Ton
Dreco – 650 Ton
TL-400 – 400 Ton
National Sligshot, casing xxxxxx lbs, setback xxxxxx lbs?.
Schlumberger ID3, 26 function digital data recorder
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar 3512, 1321 HP ea, w/ 1165 KVA generators
2 x Joliet C75ZB3-15 motor – ------ HP ea.
2 x Joliet C75ZB3-15 motor – ------ HP ea.
Joliet C75ZB3-15 motor, 750 HP, Torque ----- Amps / ------ ft.-lbs
Make ? motor, 800 HP ea. Torque ---- Amps / ------ ft.-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x National 12-P-1600 (1600 HP ea.)
2000 Bbls. with 76 Bbls. trip tank
2 x Derrick 513-Flo Line Cleaner
Derrick 3 x 10 cone – 1200 GPM
Derrick 20 x 4 cone – 1200 GPM
None
Derrick Vacu-Flo – 1000 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, CAD 12 station
4 1/16” Swaco 10,000 psi WP, sour service, Check?
Cameron U 21 ¼” single ram 2000 psi, Cameron U 13-5/8” double
ram 5000 psi, Cameron U 13-5/8” single ram 5000 psi, Hydril MSP
13-5/8” Annular 5000 psi, All H2S trimmed
F)
Safety Equipment
:
75 dry chemical fire extinguishers, 20 x CO2 fire extinguishers, 2
Fire pump, 3 gas LEL and 5 H2S detector fixed @ shaker and bell
nipple area, 4 portable gas/ H2S , 1 cascade system, 14 Scott Air
Pack SCBAs, monitors, 4 eye wash stations, 4 shower-mud pits
and 1 on CMT tank, 4 wind socks, 1 Bauer Breathable air
compressor,
please check all ?
G)
Drill Pipe & Drill Collars
1. Drill Pipe
HWDP
Drill collars
:
:
:
:
5” Grade G, 19.5 lbs/ft, 10,000 ft.
4” Grade G, 14 lbs./ft, 16,000 ft., 2 3/8” Grade E, lbs/ft, 3000 ft.
60 of 5” Grade ? ---- lbs/ft, 80 of 4” Grade ? ---- lbs/ft
12 of 9 ½”, 30 of 8 ½”, 30 of 6 ¼”, 30 of 4 ¾”, 15 of 3 3/8”
H)
Depth Capacity
:
18,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
xx.x ft
xx.x ft
C)
D)
E)
2.
3.
15 of 102
SAUDI ARAMCO
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Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.1.12
ADC-32 (ONSHORE RIG)
A)
Year Built
:
2005
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National 1100 UE, 1500 HP with xxxxxx Auxiliary brake
Dreco Beam Leg – 30 ft x 152 ft.
1,300,000 lbs (static) with 12 lines.
Varco-TDS 11SA – 500 Ton
Continental Emsco -T375 (37 ½”) – 650 Ton
Dreco – 650 Ton
TL-400 – 400 Ton
National Sligshot, casing xxxxxx lbs, setback xxxxxx lbs?.
Schlumberger ID3, 26 function digital data recorder
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar 3512, 1321 HP ea, w/ 1165 KVA generators
2 x Joliet C75ZB3-15 motor – ------ HP ea.
2 x Joliet C75ZB3-15 motor – ------ HP ea.
Joliet C75ZB3-15 motor, 750 HP, Torque ----- Amps / ------ ft.-lbs
Make ? motor, 800 HP ea. Torque ---- Amps / 37,500 ft.-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x National 12-P-1600 (1600 HP ea.)
2000 Bbls. with 76 Bbls. trip tank
2 x Derrick 513-Flo Line Cleaner
Derrick 3 x 10 cone – 1200 GPM
Derrick 20 x 4 cone – 1200 GPM
None
Derrick Vacu-Flo – 1000 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, CAD 12 station
4 1/16” Swaco 10,000 psi WP, sour service
Cameron U 21 ¼” single ram 2000 psi, Cameron U 13-5/8” double
ram 5000 psi, Cameron U 13-5/8” single ram 5000 psi, Hydril MSP
13-5/8” Annular 5000 psi, All H2S trimmed
F)
Safety Equipment
:
75 dry chemical fire extinguishers, 20 x CO2 fire extinguishers, 2
Fire pump, 3 gas LEL and 5 H2S detector fixed @ shaker and bell
nipple area, 4 portable gas/ H2S , 1 cascade system, 14 Scott Air
Pack SCBAs, monitors, 4 eye wash stations, 4 shower-mud pits
and 1 on CMT tank, 4 wind socks, 1 Bauer Breathable air
compressor
G)
Drill Pipe & Drill Collars
1. Drill Pipe
HWDP
Drill collars
:
:
:
:
5” Grade G, 19.5 lbs/ft, 10,000 ft.
4” Grade G, 14 lbs./ft, 16,000 ft., 2 3/8” Grade E, lbs/ft, 3000 ft.
60 of 5” Grade ? ---- lbs/ft, 80 of 4” Grade ? ---- lbs/ft
12 of 9 ½”, 30 of 8 ½”, 30 of 6 ¼”, 30 of 4 ¾”, 15 of 3 3/8”
H)
Depth Capacity
:
18,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
xx.x ft
xx.x ft
C)
D)
E)
2.
3.
16 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.1.13
ADC-34 (ONSHORE RIG)
A)
Year Built
:
2001 (Upgraded in 2005
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National Oil Well E-2000 (2000 HP)
Lee C Moore, 30 x 142 ft.
1,300,000 lbs. (static) with 12 lines
National Oil Well PS-500A
Oilwell (37-1/2”)
Oilwell – 650 Ton
None
Lee C. Moore
Schlumberger, ID Cubed with 26 functions digital recorder
C)
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
lbs.
5. Top Drive
:
:
:
:
5 x Caterpillar D3512, 1478 HP ea.
2 x GE 752 motor – 1000 HP ea.
6 x GE 752 motors – 1000 HP ea.
Ind. Dr, GE 752 motor, 1000 HP, Torque 1000 Amps / 48,000 ft.-
:
GE B 20B2 motor, 1150 HP, Torque 1052 Amps/ 45,000 ft.-lbs.
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
3 x Gardner Denver PZ-11 (1100 HP ea.)
4000 bbl. capacity, 120 bbl trip tank
3 x Brandt King Cobra
Brandt Hydro-cyclone System – 1000 GPM
Brandt Hydro-cyclone System – 1000 GPM
None
Brandt VG-1 Hyflow – 1000 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, Koomey
10000 psi WP, sour service
Cameron UU 13-5/8” double ram, 10000 psi, Cameron U 13-5/8”
single ram, 10000 psi, Hydril GK 13-5/8” x 5000 psi, Hydril MSP 30”
annular 2000 psi, Hydril MSP 20-1/4” Annular 2000 psi, All H2S
trimmed.
F)
Safety Equipment
:
92 Fire extinguishers, 2 Fire pump, 2 gas detector, 4 H2S detectors,
18 Scott Air Pack SCBAs, 4 portable gas / H2S monitors, 4 eye
wash stations, 2 shower-mud pits, 4 wind socks, 1 Drager H2S
sniffer, 1 Mako Breathable air compressor, 1 foam unit.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
5.5” Grade XD-105 24.7 ppf, 15,000 ft.
5.5” Grade S-135, 24.7 ppf, 7000 ft
4” Grade XD-105, 14.4 ppf, 10,000 ft.
30 of 5” and 100 of 4”
18 of 9-1/2”, 30 of 8-1/2”, 30 of 6-1/4”, 30 of 4-3/4”
H)
Depth Capacity
:
19,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
35.0 ft
30.0 ft
D)
E)
17 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.1.14
ADC-35 (ONSHORE RIG)
A)
Year Built
:
2001
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National Oilwell E-2000 – 2000 HP
Lee C Moore, 30” x 152 ft.
1,300,000 lbs. (static) with 14 lines
National PS-500 (PS2) – 650 Ton
Oilwell -B375 (37 ½”) – 650 Ton
Oilwell – 650 Ton
C. Emsco LB-500 – 500 Ton
Lee C. Moore, double Cantilever, Load 1,300,000 lbs.
Schlumberger, ID Cubed system with 26 function digital recorder
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x Caterpillar 3512B, 1478 HP ea.
2 x GE 752, 1000 HP ea.
6 x GE 752, 1000 HP ea.
GE 752, 1000 HP, Torque 750 Amps / 20,000 ft.-lbs.
National motor, 1000 HP ea. Torque 800 Amps / 22,500 ft.-lbs.
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
3 x Garden Denver PZL-11, 1600 HP ea.
4000 Bbls. total with 2000 Bbls active w/ 90 bbl. trip tank
3 x Brandt King Cobra
King Cobra 3 cone – 500 GPM
King Cobra 24 cone – 1200 GPM
None
Brandt DG-10 – 1200 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, Shaffer, 14 station
4 1/16” Swaco 10,000 psi WP, H2S trim
Shaffer 30” Annular, 2000 psi, Hydril 13 5/8” Annular - 5000 psi,
Cameron 26 ¾” single ram, 3000 psi, Cameron 26 ¾” double ram,
3000 psi, Cameron 13-5/8” single ram, 10,000 psi, Cameron 135/8” double ram w/ shear, 10,000 psi.
F)
Safety Equipment
:
75 dry chemical fire extinguishers, 20 x CO2 fire extinguishers, 2
Fire pump, 3 gas LEL and 5 H2S detector fixed @ shaker and bell
nipple area, 4 portable gas / H2S monitors, Cascade system, 14
Scott Air Pack SCBAs, monitors, 4 eye wash stations, 4 showermud pits and 1 on CMT tank, 4 wind socks, Bauer Breathable air
compressor
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill Collars
:
:
5.5” Grade XD-105, 24.7 ppf, 15,000 ft., 5.5” Grade S-135, 24.7
ppf, 7000 ft, 4” Grade XD-105, 14.0 ppf, 10,000 ft.,
15 of 6 5/8”, 50 of 5 ½”
18 of 9 ½”, 30 of 8 ½”, 30 of 6 ¼”, 30 of 4 ¾”
H)
Depth Capacity
:
19,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
36.0 ft
30.6 ft
C)
D)
E)
18 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.1.15
ADC-36 (ONSHORE RIG)
A)
Year Built
:
2005
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National Oilwell E-2000 (2000 HP) with Wichita Auxiliary Brake
Dreco, 160 ft.
1,555,000 lbs. with 14 lines
National Oilwell TPS2-750A – 750 Ton
Oilwell -A375 (37 ½”) – 750 Ton
Dreco 760 TB 750-8A – 750 Ton
OIlwell 650 – 650 Ton
Dreco cantilever, Casing 1,000,000 lbs, setback 800,000 lbs.
Schlumberger ID Cubed system, 26 function digital recorder
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x Caterpillar 3512 – 1400 HP ea. w/ Kato 1200 KW generators
2 x– GE 752 rebuilt motor – 1000 HP ea.
6 x GE 752 rebuilt motor – 1000 HP ea.
GE 752 rebuilt motor – 1000 HP, Torque 1100 Amps / 50,000 ft-lbs.
NOV-GB motor, 1150 HP, Torque 1100 Amps / 60,286 ft-lbs.
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
3 x National Oilwell 12-P-160 – 1600 HP ea.
5,000 bbl. capacity with 2000 bbl. active and 2 x 50 bbl. trip tanks
3 x Brandt King Cobra – xxx GPM
Brandt King Cobra 3 x 12” cone – 1500 GPM
Brandt King Cobra 24 x 3” cones– 1200 GPM
None
Brandt XC10 Horizontal Vacuum type – 1200 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, CAD with 14 stations, 42 x 10 gal. bottles
4 1/16” Cameron 10,000 psi WP, H2S trimmed
Hydril GK 13 5/8” Annular – 5000 psi,
2 x Cameron 13-5/8” double ram – 10,000 psi
F)
Safety Equipment
:
75 dry chemical fire extinguishers, 20 x CO2 fire extinguishers, 2
Fire pump, 3 gas LEL and 5 H2S detector fixed @ shaker and bell
nipple area, 4 portable H2S gas detectors, 1 cascade system, 14
Scott Air Pack SCBAs, monitors, 4 eye wash stations, 4 shower at
mud pits and 1 at CMT tank, 4 wind socks, One Bauer Breathable
air compressor.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill Collars
:
:
5.5” Grade XD-105, 24.7 ppf, 14,000 ft., 5.5” Grade S-135, 24.7ppf,
7,500 ft., 4” Grade XD-105, 14.0 ppf, 10,000 ft.,
15 of 6 5/8”, 50 of 5 ½”
18 of 9 ½”, 30 of 8 ½”, 15 of 6 ¼”, 30 of 4 ¾”
H)
Depth Capacity
:
21,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
39.0 ft
32.5 ft
C)
D)
E)
19 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
June 2006
GENERAL INFORMATION
F
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.1.16
ADC-39 (ONSHORE RIG)
A)
Year Built
:
2005
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National 80 UE, 1000 HP with xxxxxxx auxiliary brake
LCM check ?, - 30’ x W’ x 160 ft.
500,000 lbs. static with 12 lines
None
National C275 (27 ½”) ----- Ton
National 545, ---- Tons
National P-400, ---- Tons
Specify type Load?. casing xxxxxx lbs, setback xxxxxxxx lbs.
Schlumberger ID Cubed system, 26 function digital recorder
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
3 x Caterpillar D398, ------ HP ea. with xxxx KW generators
1 x GE 752, ------ HP ea.
2 x GE 752 HT, ------ HP ea.
1 x GE 752, ----- HP, Torque ---- Amps / -------- ft.-lbs
None
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x Garden Denver PZ10, 1000 HP ea.
2000 Bbls. 60 Bbls. trip tank
2 x Derrick Flo-Line Cleaner
Brandt S12-2, 1000 GPM ?
None
None
Swaco DG-10 horizontal, 800 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, Koomy T20-220-3S
Make and Model ? 5000 psi WP?
Hydril 21 ¼” MSP 20 - 2000 psi, Hydril 13 5/8” GK - 5000 psi
Cameron 13 5/8” double ram - 10000 psi,
F)
Safety Equipment
:
75 dry chemical fire extinguishers, 20 x CO2 fire extinguishers, 2
Fire pump, 3 gas LEL and 5 H2S detector fixed @ shaker and bell
nipple area, 4 portable gas/ H2S , 1 cascade system, 14 Scott Air
Pack SCBAs, monitors, 4 eye wash stations, 4 shower-mud pits
and 1 on CMT tank, 4 wind socks, 1 Bauer Breathable air
compressor.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
2. HWDP
3. Drill Collars
:
:
:
5” Grade G105, 19.9 lbs/ft, 5,000 ft.
50 of 5” Grade ---, ------ lbs/ft
6 of 9 ½”, 15 of 8 ½”
H)
Depth Capacity
:
11,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
26.0 ft
xx.x ft
C)
D)
E)
20 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.2.1
DALMA-1 (ONSHORE RIG)
A)
Year Built
:
1979 (Mast upgraded and major refurbishment in May 2006)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Oilwell E2000 (2000 HP) w/ Baylor Eddy Current Auxiliary Brake
Derrick Cantilever, 28’ x 19’ x 152 ft.
1,125,000 lbs with 12 lines.
None
Oilwell B37.5 (37 ½”) – 500 Ton
Dreco Flat 760C crown - 583 Ton, Oilwell B500, traveling – 500 Ton
Oilwell P.C500 – 500 Tons
Derrick, Self Elevating, set back 500,000 lbs.
M.D. Totco, 7-Pens
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar D399, 1200 HP ea.
2 x GE 752 motor – 1000 HP ea.
4 x GE 752 – 850 HP ea.
Ind. drive, GE 752 motor 1000 HP, Torque 800 Amps / 43,200 ft.-lbs.
2 x 350 AC Motor, 400 HP ea, Torque 700 Amps / 32,500 ft.-lbs.
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x Oilwell A-1700PT (1700 HP)
2000 bbl. active with 1000 bbl. reserve
2 x Derrick-Flo Line Cleaners
Harrisburg 3 x 10” cone – 1600 GPM.
National Oilwell, DSL-1600-5c – 1600 GPM.
None
Swaco 255 – 1200 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, Koomey ABB TX-280, 14 station 20 x 15 gal bottles
Swaco 3 1/8”, 5000 psi WP, H2S trim
Hydril MSP 21 ¼” Annular – 3000 psi, Hydril GK 13 5/8” Annular –
5000 psi, Cameron U 13 5/8” double ram, 5000 psi, Cameron U
13 5/8” single ram, 5000 psi
F)
Safety Equipment
:
51 Fire extinguishers, 1 Fire pump, 1 gas detector, 4 H2S detectors,
1 cascade system, 16 Scott Air Pack SCBAs, 2 portable gas / H2S
monitors, 3 eye wash stations, 1 shower-mud pits, 4 wind socks, 1
Drager H2S sniffer, 1 Bauer Breathable air compressor, 1 foam unit.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
5” Grade G105, 19.5 ppf, 10,000 ft,
4” Grade XT-39, 13.3 ppf, 9,000 ft,
2 3/8” Grade E, 6.65 ppf, 5,000 ft.
50 of 5”, 50 of 3 ½”
18 of 9 ½”, 30 of 8 ¼”, 30 of 6 ¼”, 30 of 4 ¾” and 15 of 3 1/8”
H)
Depth Capacity
:
10,000 ft with 5” Drillpipe
I)
DF – GL Elevation
Clearance below DF
:
:
33.0 ft
27.0 ft.
C)
D)
E)
21 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.2.2
DALMA-2 (ONSHORE RIG)
A)
Year Built
:
1981
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National 1320-4E (2000hp)
Derrick Services International
1,000,000 (static) with 12 lines
Varco-TDS 115
Oilwell C375 (37-1/2”)
National Dynamic 650-G-500 (Hook/Block Combination) – 500 Tons
National P500
Derrick, Tilt up Parallelogram, setback 500,000 lbs.
M.D. Totco, RG100, 7 pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar D399, 1215 HP ea.
2 x GE 752 motor – 1000 HP ea.
4 x GE 752 – 1000 HP ea.
Ind. drive, GE 752 motor 1000 HP, Torque 800 Amps/36,800 ft.-lbs.
2 x 350 AC Motor, 400 HP ea, Torque 700 Amps / 32,500 ft.-lbs.
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x Oilwell, A-1700PT – 1700 HP, 1 x GD PZ8–800 HP
2458 bbl. capacity, 2 x 60 bbl trip tanks, 2 x 500 bbl cmt tanks
2 x Derrick-Flo Line Cleaner
Harrisburg – 1600 GPM
Harrisburg – 1600 GPM
None
Swaco – 1200 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, Koomey 80, 14 station, 16 x 11 gal bottles
3 1/16 10,000 up, 3 1/8 5000 psi down WP, sour service,
Hydril MSP 21 ¼” Annular 2000 psi, Hydril 13 5/8” Annular 5000
psi, Cameron UU 13-5/8” double ram, 5000 psi, Cameron U 13-5/8”
single ram, 5000 psi, All H2S trim
F)
Safety Equipment
:
51 Fire extinguishers, 1 Fire pump, 1 gas detector, 4 H2S detectors,
1 cascade system, 14 x 30-min. SCBA, 16 Scott Air Pack SCBAs, 2
portable gas / H2S monitors, 3 eye wash stations, 1 shower-mud
pits, 4 wind socks, 1 Drager H2S sniffer, 1 Bauer Breathable air
compressor, 1 foam unit.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
5” Grade-G, 19.5 ppf, 8,850 ft.
4” Grade-X 15.7 ppf, 14,000 ft.
57 of 5”
11 of 9 ½”, 32 of 8 ½”, 25 of 6 ½”, 30 of 4 ¾”, 15 of 3 3/8”
H)
Depth Capacity
:
10,000 ft with 5” Drillpipe
I)
DF – GL Elevation
:
Clearance below DF :
C)
D)
E)
22 of 102
33.5 ft
27.0 ft.
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
June 2006
GENERAL INFORMATION
F
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.2.3
DALMA-7 (ONSHORE RIG)
A)
Year Built
:
1979
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National 110-UE (1500 HP)
Union Industries, 28’ x 19’, 142 ft.
750,000 lbs with 12 lines.
Varco TDS 9
National C-375 (37 ½”)
National – 350 Ton
National – 400 Ton
Union Industries
M.D. Totco, 7-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar 3512, 1442 HP ea. with 1077 KW generators
2 x GE 752 motor – 1000 HP ea.
4 x GE 752 – 850 HP
Ind. drive, GE 752 motor – 1000 HP
2 x 350 AC Motor, 350 HP ea, Torque 700 Amps / 32,500 ft.-lbs.
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
3 x National 10-P-130 (1300 HP ea.)
2324 bbl. mud, 937 bbl. water, 120 bbl. trip tanks
3 x Derrick-Flo Line Cleaner
Harrisburg – 1600 GPM
Harrisburg – 1600 GPM
None
Swaco
3.
BOP Equipment
1. Accumulator
2. Choke manifold
BOPs
:
:
:
3000 psi, Koomey type 80, 32 x 11 gal bottles
3 1/8” Choke, 5000 psi, source service
Hydril GK 13 5/8” Annular – 5000 psi, Cameron U 13 5/8” double
ram, 5000 psi
F)
Safety Equipment
:
50 Fire extinguishers, 1 Fire pump, 1 gas detector, 4 H2S detectors,
1 cascade system, 17 Scott Air Pack SCBAs, 2 portable gas/ H2S
monitors, 3 eye wash stations, 1 shower-mud pits, 5 wind socks, 1
Drager H2S sniffer, 1 Bauer Breathable air compressor
G)
Drill Pipe & Drill Collars
1. Drill Pipe
2. HWDP
3. Drill collars
:
:
:
5” Grade G105, 19.5 ppf, 10,000 ft.
80 of 5”
12 of 9 ½”, 30 of 8 ¼”, 30 of 6 ¼”, 30 of 4 ¾”
H)
Depth Capacity
:
16,000 ft with 5” Drillpipe
I)
DF – GL Elevation
Clearance below DF
:
:
30.4 ft
23.1 ft.
C)
D)
E)
23 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
June 2006
GENERAL INFORMATION
F
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.2.4
DALMA-8 (ONSHORE RIG)
A)
Year Built
:
1979
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National 110-UE (1500 HP)
Union Industries, 28’ x 19’, 142 ft.
750,000 lbs with 12 lines.
Varco TDS 9
National C-375 (37 ½”)
National – 350 Ton
National – 400 Ton
Union Industries
M.D. Totco, 7-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar 3512, 1442 HP ea. with 1077 KW generators
2 x GE 752 motor – 1000 HP ea.
4 x GE 752 – 850 HP
Ind. drive, GE 752 motor – 1000 HP
2 x 350 AC Motor, 350 HP ea, Torque 700 Amps / 32,500 ft.-lbs.
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
3 x National 10-P-130 (1300 HP ea.)
2324 bbl. mud, 937 bbl. water, 120 bbl. trip tanks
3 x Derrick-Flo Line Cleaner
Harrisburg – 1600 GPM
Harrisburg – 1600 GPM
None
Swaco
3.
BOP Equipment
1. Accumulator
2. Choke manifold
BOPs
:
:
:
3000 psi, Koomey type 80, 32 x 11 gal bottles
3 1/8” Choke, 5000 psi, source service
Hydril GK 13 5/8” Annular – 5000 psi, Cameron U 13 5/8” double
ram, 5000 psi
F)
Safety Equipment
:
50 Fire extinguishers, 1 Fire pump, 1 gas detector, 4 H2S detectors,
1 cascade system, 17 Scott Air Pack SCBAs, 2 portable gas/ H2S
monitors, 3 eye wash stations, 1 shower-mud pits, 5 wind socks, 1
Drager H2S sniffer, 1 Bauer Breathable air compressor
G)
Drill Pipe & Drill Collars
1. Drill Pipe
2. HWDP
3. Drill collars
:
:
:
5” Grade G105, 19.5 ppf, 10,000 ft.
80 of 5”
12 of 9 ½”, 30 of 8 ¼”, 30 of 6 ¼”, 30 of 4 ¾”
H)
Depth Capacity
:
16,000 ft with 5” Drillpipe
I)
DF – GL Elevation
Clearance below DF
:
:
30.4 ft
23.1 ft.
C)
D)
E)
24 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.2.5
DALMA-9 (ONSHORE RIG)
A)
Year Built
:
1979
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National 11-VE
Branham
575,000 lbs.
None
National C375 (37 ½”)
National Hook / Block combination – 500 Ton
National P500 – 500 Ton
Branham
M.D. Totco, 8-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar 398, 1050 HP ea.
2 x Schneider motor – 750 HP ea.
6 x Schneider motor – 750 HP ea.
Chain Driven 160/3R
None
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
3 x National 10-P-130 (1300 HP ea.)
3000 bbl. capacity, 2 x 63 bbl. trip tanks, 2 x 500 bbl. cmt. tanks
4 x Derrick-Flo Line Cleaner
Derrick– 1200 GPM
Derrick– 1200 GPM
None
Swaco – 1200 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, Koomey ABB TX-280, 6 stations, 20 x 15 gal. bottles
3 1/16” Cameron, 5000 psi, source service
Hydril 13-5/8” Annular 10,000 psi, Cameron 13 5/8” double ram,
10000 psi, Cameron 13 5/8” single ram, 10,000 psi, All H2S
trimmed.
F)
Safety Equipment
:
34 Fire extinguishers, 6-channel gas detection system, 5 x T-40
H2S personal monitors, 2 x Multigas Monitors (H2S, LEL, Oxygen,
CO2), 5 wind socks, 18 x 30-min. Scott Air Pack SCBAs, Mako
Breathable air compressor, 2 x Fire pumps, H2S sniffer, Cascade
system, 2 x portable & 3 x fixed showers, 3 eye wash stations,
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
5” Grade G105, 19.5 ppf, 10,000 ft.
3 ½” Grade G105, 13.3 ppf, 9,000 ft.
50 of 5”, 82 of 3 ½”
12 of 9 ½”, 30 of 8 ¼”, 30 of 6 ¼”, 30 of 4 ¾”
H)
Depth Capacity
:
12,000 ft.
I)
DF – GL Elevation
Clearance below DF
:
:
25.8 ft
20.0 ft.
C)
D)
E)
25 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
June 2006
GENERAL INFORMATION
F
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.2.6
DALMA-10 (ONSHORE RIG)
A)
Year Built
:
1979
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National 110-UE (1500 HP)
Union Industries, 28’ x 19’, 142 ft.
750,000 lbs with 12 lines.
Varco TDS 9
National C-375 (37 ½”)
National – 350 Ton
National – 400 Ton
Union Industries
M.D. Totco, 7-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar 3512, 1442 HP ea. with 1077 KW generators
2 x GE 752 motor – 1000 HP ea.
4 x GE 752 – 850 HP
Ind. drive, GE 752 motor – 1000 HP
2 x 350 AC Motor, 350 HP ea, Torque 700 Amps / 32,500 ft.-lbs.
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
3 x National 10-P-130 (1300 HP ea.)
2324 bbl. mud, 937 bbl. water, 120 bbl. trip tanks
3 x Derrick-Flo Line Cleaner
Harrisburg – 1600 GPM
Harrisburg – 1600 GPM
None
Swaco
3.
BOP Equipment
1. Accumulator
2. Choke manifold
BOPs
:
:
:
3000 psi, Koomey type 80, 32 x 11 gal bottles
3 1/8” Choke, 5000 psi, source service
Hydril GK 13 5/8” Annular – 5000 psi, Cameron U 13 5/8” double
ram, 5000 psi
F)
Safety Equipment
:
50 Fire extinguishers, 1 Fire pump, 1 gas detector, 4 H2S detectors,
1 cascade system, 17 Scott Air Pack SCBAs, 2 portable gas/ H2S
monitors, 3 eye wash stations, 1 shower-mud pits, 5 wind socks, 1
Drager H2S sniffer, 1 Bauer Breathable air compressor
G)
Drill Pipe & Drill Collars
1. Drill Pipe
2. HWDP
3. Drill collars
:
:
:
5” Grade G105, 19.5 ppf, 10,000 ft.
80 of 5”
12 of 9 ½”, 30 of 8 ¼”, 30 of 6 ¼”, 30 of 4 ¾”
H)
Depth Capacity
:
16,000 ft with 5” Drillpipe
I)
DF – GL Elevation
Clearance below DF
:
:
30.4 ft
23.1 ft.
C)
D)
E)
26 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.3.1
DPS-4 (ONSHORE RIG)
A)
Year Built
:
1992
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Continental Emsco C-2
C. Emsco 150’ x 30 ft
1,560,000 lbs with 14 lines
National Oilwell PS-500
Continental Emsco 37 ½”
Continental Emsco 650 Ton
BJ Dynaplex 5500
Specify structure type and load capacity?
Varco RigSense, no. of recorder pens?
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x Caterpillar 3512-TA, 1435 HP ea. Each with 1025 KW generator
2 x GE 752, 1000 HP ea.
4 x GE 752, 1000 HP ea.
1 x GE 752 – 1000 HP, Torque --- Amps / ----- ft.-lbs
1 x GE 752 High Torque – 1000 HP, Torque --- Amps / ----- ft.-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
5. Centrifuge
6. Degasser
:
:
:
:
:
:
:
2 x C. Emsco FB-1600, 1600 HP ea.
4000 Bbls capacity, xxxx Bbls Active, xxx Bbls trip tank
3 x Derrick Flo-line cleaners
Specify Make & Model? – 1000 GPM
Specify Make? / 1000 GPM
None
Brandt Specify Model? – 1000 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, Koomy 2T60392 with 14 stations
4-1/16” Shaffer 10,000 psi WP, sour service
1 x Shaffer 21 ¼” annular – 1000 psi, 1 x Cameron 20 ¾” single
rams, 3000 psi, 1 x Cameron 20 ¾” double rams, 3000 psi, 1 x
Shaffer 21 ¼” annular - 5000 psi, 2 x Cameron 13-5/8” double ram,
10,000 psi
F)
Safety Equipment
:
80 fire extinguishers, 1 fire pump, Gas detection systems for H2S
and explosive gasses, Cascade System, xx SCBA / xx SABA
breathing sets, x portable gas monitors, x eyewash stations, x wind
socks, shower at mud pits, breathing air compressor.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
5 ½” Grade G-105, 21.9 lbs/ft., 12,000 ft., 5” Grade G 19.5 lbs/ft,
15000 ft, 3 ½” Grade G 13.3 lbs/ft, 9000 ft.
15 of 6-5/8”, 30 of 5 ½”, 50 of 5”, 50 of 3 ½”
18 of 9 ½”, 30 of 8 ½”, 30 of 6 ¼”, 30 of 4 ¾”
H)
Depth Capacity
:
19,000 feet
I)
DF – GL Elevation
Clearance below DF
:
:
35 feet
30.0ft.
C)
D)
E)
27 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.3.2
DPS-43 (ONSHORE RIG)
A)
Year Built
:
1980
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Oilwell E 2000
Pyramid 152’
1,300,000 lbs
National 350/500
Oilwell D-375
Oilwell B-500
Oilwell 350/500 power swivel
Specify structure type and load capacity?
Martin Decker 6-pen recorder
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x Caterpillar D-399, 2000 HP ea.
2 x GE 752, ----- HP ea.
2 x GE 752 ----- HP ea.
1 x GE 752 – 1000 HP, Torque --- Amps / ----- ft.-lbs
1 x GE 752 – 1000 HP, Torque --- Amps / ----- ft.-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
5. Centrifuge
6. Degasser
:
:
:
:
:
:
:
2 x Oilwell 1700 PT, 1700 HP ea.
4000 Bbls capacity, 60 Bbls trip tank
3 x Brandt LCM-2D, 2 x 800 GPM mud cleaners
Specify Make & Model? – 1600 GPM
Specify Make? / 1600 GPM
Brandt SC4, ------ GPM
Specify Make & Model? – 1200 GPM Degasser
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, Shaffer 2130420-3SX
Shaffer 10,000 psi WP, sour service
1 x Shaffer 30” annular - 1000 psi, 2 x Stewart & Stevenson 26 ¾”
single rams - 3000 psi, 1 x Shaffer 20 ¾” double rams, 3000 psi, 1
x Shaffer 20 ¾” single ram, 3000 psi 1 x Shaffer 21 ¼” annular 2000 psi, 2 x Shaffer 13-5/8” double ram, 10,000 psi, 1 x Shaffer
13-5/8” annular, 5000 psi,
F)
Safety Equipment
:
xx fire extinguishers, 1 fire pump, Gas detection systems for H2S
and explosive gasses, Cascade System, xx SCBA / xx SABA
breathing sets, x portable gas monitors, x eyewash stations, x wind
socks, shower at mud pits, breathing air compressor.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
5 ½” Grade E 21.9 lbs/ft., 10,000 ft., 5” Grade G 19.5 lbs/ft,
15000 ft, 3 ½” Grade G 13.3 lbs/ft, 15000 ft.
30 of 5 ½”, 100 of 5”, 100 of 3 ½”
12 of 9 ½”, 30 of 8 ½”, 30 of 6 ¼”, 30 of 4 ¾”
H)
Depth Capacity
:
20,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
35 ft
28.0 ft.
C)
D)
E)
28 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.3.3
DPS-44 (ONSHORE RIG)
A)
Year Built
:
1998
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Oilwell E 2000, 2000 HP
Pyramid 152’
1,000,000 lbs with 12 lines
National 350/500 power swivel
Oilwell D-375, 650 Ton
Oilwell B-600, 600 Ton
Oilwell 350/500 power swivel
Pyramid self elevating, csg 1,300,000 lbs, set back 800,000 lbs
Drill Watch, VIP Visua-logger
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x Caterpillar 3512, 1000 HP ea. w/ 1025 KW Generators
2 x GE 752, 1000 HP ea.
4 x GE 752, 1000 HP ea.
Oilwell D 375, 1000 HP, Torque 1500 Amps / 43,200 ft.-lbs
1 x GE 752, 1000 HP, Torque 1400 Amps / 38,722 ft.-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
3 x Oilwell 1700 PT, 1700 HP ea.
4000 Bbls capacity, 1526 Bbls Active, 60 Bbls trip tank
3 x Brandt shakers, 2 x 800 GPM mud cleaners
Brandt SR-3, 1600 GPM
Brandt SE-24, 1600 GPM
None
Brandt DG-10, 1200 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
Koomy 2T30420-38X, 3000 psi
4-1/16”, Shaffer 10,000 psi WP, H2S trimmed
Shaffer 30” Annular, 1000 psi, Cameron 26 ¾” Dbl Ram 3000 psi.
Cameron 26 ¾” Sgl Ram 3000 psi, Shaffer 13-5/8” Annular 5000
psi, Cameron 13 5/8” Dbl Ram 10000 psi BSR w/ Booster.
Cameron 13 5/8” Dbl Ram 10000 psi.
F)
Safety Equipment
:
65 Fire extinguishers, 1 Fire pump, Air cascade system, 12
Breathing 5 min apparatus, 19 SCBA 30 min Breathing Apparatus,
Fixed gas detection system, Portable gas detection Equipment,
5 eye wash stations, 2 emergency showers, 4 x wind socks
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
5-1/2” Grade E, 24.7 lbs/ft., 10,000 ft., 5” Grade G, 19.5 lbs/ft.,
15,000 ft., 3-1/2”, Grade G, 13.3 lbs/ft., 15,000 ft.
30 of 5 ½”, 50 of 5”, 50 of 3 ½”
18 of 9-1/2”, 30 of 8-1/2”, 30 of 6 ¼”, 30 of 4 ¾”
H)
Depth Capacity
:
20,000 feet
I)
DF – GL Elevation
Clearance below DF
:
:
35.0 ft.
28.0 ft.
C)
D)
E)
29 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.3.4
DPS-45 (ONSHORE RIG)
A)
Year Built
:
1997 (Refurbished)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Oilwell E 2000 (2000 HP) with Elmagco Auxiliary Brake
Pyramid 30’ x 152 ft
1,275,000 lbs with 12 lines
National 350/500 – 500 Ton
Oilwell D-375 (37 ½”) – 500 Ton
Oilwell B-500 – 500 Ton
Oilwell 350/500 power swivel (integrated with Top Drive)
Pyramid, self-elevating, casing 1,275,000 lbs, set back 800,000 lbs.
Martin Decker, 6-Pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x Caterpillar D-399, 1200 HP ea. w/ 1050 KW generators
2 x GE 752 – 1000 HP ea.
4 x GE 752 – 1000 HP ea.
Ind. Dr, GE 752 motor – 1000 HP, Torque 750 Amps / 17500 ft.-lbs
GE 752 motor – 1000 HP, Torque 750 Amps / 17500 ft.-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x Oilwell 1700 PT, 1700 HP ea.
4,000 bbl. capacity w/ 1940 bbl. active, 60 bbl. trip tank
3 x Brandt shakers, 2 x 800 GPM mud cleaners
Brandt, Brexel – 1600 GPM
Brandt – 1600 GPM
None
Ingersol Rand, 1200 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
Shaffer 2T30420-38X
Shaffer 10,000 psi WP, sour service
Shaffer 30” annular, 1000 psi, 2 x Stewart & Stevenson 26 ¾” single
ram, 3000 psi, Shaffer 21-1/4” annular, 2000 psi, 2 x Shaffer 135/8” double ram, 10,000 psi, Shaffer 13-5/8” annular, 5000 psi,
Shaffer 20-3/4” double ram, 3000 psi, Shaffer 20-3/4” single ram,
3000 psi
Safety Equipment
:
154 Fire extinguishers (Rig & Camp), Fire pump, Air cascade system,
13 Breathing 5 min apparatus (13 spare bottles), 20 SCBA 30 min
Breathing (20 spare Bottles) Apparatus, Fixed gas detection
system, 7 Portable gas detection Equipment, 5 eye wash stations,
3 emergency showers, 4 x wind socks
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
5-1/2” Grade E, 21.9 ppf, 10,000 ft., 5” Grade G, 19.5 ppf, 15000 ft,
3-1/2”, Grade G, 13.3 ppf, 15,000 ft.
30 of 5 ½”, 100 of 5”, 100 of 3 ½”
12 of 9-1/2”, 30 of 8-1/2”, 30 of 6 ¼”, 30 of 4 ¾”
H)
Depth Capacity
:
20,000 feet
I)
DF – GL Elevation
Clearance below DF
:
:
35.0 ft.
28.0 ft.
C)
D)
E)
F)
G)
30 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.3.5
DPS-46 (ONSHORE RIG)
A)
Year Built
:
1975 (Refurbished in 2000)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National 110 UE, 1500 HP with Baylor 6032 eddy current brake
Pyramid 152 ft., load 840,000 lbs
705,000 lbs with 12 lines
National Oilwell PS500A
National C-375 (37 ½”)
National 660 – 500 Ton
National P500 – 500 Ton
pyramid self elevating, set back 504,000 lbs
Martin Decker 8-Pen with Rig-sense version 2.0 SP 2
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar 3512, 1321 HP ea. w/ 925 KW Generators
2 x GE 752 – 750 HP ea.
4 x GE 752 – 1000 HP ea.
Oilwell D 375 – 1000 HP Torque 17,500 ft-lbs.
GE 752 – 1000 HP, Torque 33,154 ft.-lbs continuous @120 RPM
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x Oilwell 1700 PT, 1700 HP ea.
4053 bbl. capacity with 1156 bbl. active and 2 x 50 bbl. trip tanks
3 x Brandt shakers, 2 x 800 GPM mud cleaners
Brandt SRS-3 cones – 1600 GPM
Brandt SE-24cones – 1600 GPM
None
Brandt vacuums – 1000 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, Koomey/Shaffer 2T60392-3SX
4-1/16” Shaffer 10,000 psi WP, H2S trimmed
Shaffer30” annular, 1000 psi, 2 x Cameron 26 ¾” single rams, 3000
psi, Shaffer 20-3/4” double ram, 3000 psi, Shaffer 20-3/4” single
ram, 3000 psi, Shaffer 21 ¼” annular, 2000 psi, Shaffer 13-5/8”
double ram, 10,000 psi, Shaffer 13-5/8” annular, 5000 psi, Shaffer
13-5/8” double ram with shear rams, large bore bonnets and 16”
boosters, 10000 psi
F)
Safety Equipment
:
54 Fire extinguishers, 1 Fire pump, Air cascade system, 12
Breathing 5 min apparatus, 19 SCBA 30 min Breathing Apparatus,
Fixed gas detection system, Portable gas detection Equipment, 7
eye wash stations, 2 emergency shower,4 x wind socks
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
5-1/2” Grade G, 24.7 ppf, 9860 ft, 5” Grade G, 19.5 ppf, 15,000 ft,
3 ½” Grade G, 13.3 ppf, 10,000 ft, 2 3/8” Grade E 6.65 ppf, 4,800 ft.
15 of 5 ½”, 61 of 5”
18 of 9-1/2”, 30 of 8-1/2”, 30 of 6 ¼”, 30 of 4 ¾”
H)
Depth Capacity
:
15,000 feet
I)
DF – GL Elevation
Clearance below DF
:
:
30.0 ft
25.0 ft.
C)
D)
E)
31 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.4.1
PA-70 (ONSHORE RIG)
A)
Year Built
:
1980
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Mid Continent U-1220 EB with Elmagco Auxiliary Brake
Lee C. Moore 35 ft x 142 ft.
1,300,000 lbs with 12 lines
None
Continental Emsco T-37.50 (37 ½”) – 650 Ton
McLissick Model RP-686 – 650 Tons
Continental Emsco LB 650 – 650 Ton
LCM Sligshot, casing 1,300,000 lbs., setback 800,000 lbs.
Totco, 6-Pen
C)
Rig Power
1. Engine Power
generators
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
5 x Caterpillar D-399, 1200 HP ea. with Kato 5 x 1050 KW
:
:
:
:
2 x GE 752 Motors – 1000 HP ea.
4 x GE 752 Motors – 1000 HP ea.
Ind. Dr, GE 752 Motor – 1000 HP, Torque 1050 Amps / 54,000 ft-lbs.
None
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x Continental Emsco FB 1600 (1600 HP)
3000 bbl. capacity with120 bbl. Trip tank
3 x Derrick Flo Line Cleaners –Model L-48-96F
Derrick Model 38-1612 with 3 x 12” cones – 945 GPM
Derrick Model 38-10613 with 20 x 5” cones – 800 GPM
None
Swaco Type 30, Model 255 – 1000 GPM
:
3000 psi, Shaffer-Koomey T40240-3S w/ 14 sta., 36 x 12 gal.
:
:
4 1/16”, Energy, 10,000 psi WP, sour service.
Hydril 30” annular 1000 psi, 2 x Cameron U 26 3/4” single ram,
3000 psi, Hydril 21 ¼” annular 2000 psi, Cameron 20 3/4” double
ram, 3000 psi, Cameron 20 ¾” single ram, 3000 psi, Hydril GK 135/8” annular 5000 psi, 2 x Cameron 13 5/8” double ram, 10,000 psi,
All H2S Trim.
:
20 x Fire extinguishers, 1 x Fire pump, 1 x Gas detector, 1 x H2S
detectors, 1 x Cascade system, 1 x Mako breathable air
compressor, 1 x CO2 system, 3 x Eye Wash Stations, 1 x
Emergency Shower on Mud Pits
HWDP
Drill collars
:
:
:
:
5 ½” Grade G, 24.7 ppf, 12,000 ft., 5” Grade G, 19.5 ppf, 15,000 ft.
3-1/2” Grade G, 13.3 ppf, 9,000 ft.
9 of 6-5/8”, 30 of 5-½”, 50 of 5” and 50 of 3-½”
18 of 9 ½”, 30 of 8 ¼”, 30 of 6 ¼”, and 30 of 4 ¾”
H)
Depth Capacity
:
25,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
34.7 ft
25.0 ft
D)
E)
BOP Equipment
1. Accumulator
bottles
2. Choke manifold
3. BOPs
F)
Safety Equipment
G)
Drill Pipe & Drill Collars
1. Drill Pipe
2.
3.
32 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.4.2
PA-77 (ONSHORE RIG)
A)
Year Built
:
1975
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Mid Continental U-914 EC (1500 HP) with Elmagco Auxiliary Brake
Pyramid 25 x 156 ft.
890,000 lbs. (static) with 12 lines
Can-Rig-1050E – 500 Ton
Gardner Denver RT375, 37 ½”
McKissick – 500 Ton
None
Pyramid Slingshot type, casing 800,000 lbs., setback 500,000 lbs.
Acadiana, 6-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar D399 – 1000 HP ea. w/ 1050 KW generators
2 x GE 752 motor – 1000 HP ea.
4 x GE 752 motor – 1000 HP ea.
GE 752 motor – 1000 HP.
GE 752, 1000 HP, Torque 1250 Amps / 30,000 ft-lbs.
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x C. Emsco FB-1300 – 1300 HP ea.
2000 bbl. capacity with100 bbl. trip tank
2 x Derrick-Flo Line Cleaner
Derrick Super ‘G’ Model-58, 3 x 12” cone – 800 GPM
Derrick Super ‘G’ Model-58, 20 x 4” cone – 800 GPM
None
Derrick Vacu-Flo – 1000 GPM, Burgess Magna – 1000 GPM”
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, Koomey T20200 with 9 stations
3 1/8”, 5000 psi WP, sour service
Hydril GK 13 5/8” Annular 5000 psi,
Cameron UU 13 5/8” double ram, 5000 psi with s. booster,
Cameron U 13 5/8” single ram, 5000 psi, All H2S trimmed
F)
Safety Equipment
:
68 Fire extinguishers, 1 Fire pump, 1 gas detector, 4 H2S detectors,
1 cascade system, 16 Scott Air Pack SCBAs, 2 portable gas/ H2S
monitors, 3 eye wash stations, 1 shower-mud pits, 5 wind socks, 1
Drager H2S sniffer, 1 Bauer Breathable air compressor.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
HWDP
Drill collars
:
:
:
:
4” Grade-G, 14.00 ppf, 16,000 ft.
3 ½” Grade-G, 13.3 ppf, 5000 ft, 2 3/8” Grade-E, 6.65 ppf, 500 ft.
60 of 4”
30 of 6 ¼”, 30 of 4 ¾”, 30 of 2-7/8”
H)
Depth Capacity
:
15,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
30.0 ft
25.0 ft
C)
D)
E)
2.
3.
33 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.4.3
PA-115 (ONSHORE RIG)
A)
Year Built
:
1975
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Mid Continental U 1220 EB – 2000 HP with xxxxxxx auxiliary brake
Lee C. Moore 30’ x W x 152 ft.
1,300,000 lbs. static with 12 lines
Can-Rig 1165E – 500 Ton
Ideco LR375 (37 ½”) – xxx Ton
Mc Kissick model? – 650 Ton
None
LCM what type? Load casing xxxxxxx lbs, setback 800,000 lbs?
Acadia, 6-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar D399, 1000 HP ea. with xxx KW generators
2 x GE 752 motor – 1000 HP ea.
4 x GE 752 motor – 1000 HP ea.
Ind. drive, GE 752 motor 800 HP, Torque ….. Amps / xxxx ft-lbs.
1 GE 752 Motor, 1000 HP, Torque ……. Amps / 31000 ft.-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
3 x C. Emsco FB-1300 – 1300 HP ea
3,000 bbl. capacity, 120 bbl trip tank
3 x Derrick Flo Line Cleaner 2000
Derrick 2 x 12” cone – 800 GPM ?
Derrick 12 x 4” cone – 800 GPM
2 x Oil Tools DE 1000 – 1000 GPM
Swaco model? – 1000 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, Koomy 160-11ST w/ 11 stations, 16 x 00 gal. bottles
3 1/8” Make? 5000 psi WP, sour service
Hydril GK 13 5/8” annular, 5000 psi, Cameron U 13 5/8” single ram,
5000 psi, Cameron U 13 5/8” double ram w/ shear booster, 5000
psi, All H2S trimmed.
F)
Safety Equipment
:
28 Fire extinguishers, 1 Fire pump, 2gas detector, 4 H2S detectors,
1 cascade system with 12 work packs, 16 Scott Air Pack SCBAs, 2
portable gas/ H2S monitors, 4 eye wash stations, 2 shower-mud
pits, 4 wind socks, 1 Drager H2S sniffer, 1 MAKO Breathable air
compressor, 1 foam unit.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
HWDP
Drill collars
:
:
:
:
5” Grade G, 19.5 lbs/ft, 25,000 ft.
4’’Grade-G 14.0 lb/ft, 25,000 ft
100 of 5”, 100 of 3 ½”
12 of 9 ½”, 30 of 8 ¼” 30 of 6 ¼”, 60 of 4 ¾”
H)
Depth Capacity
:
25,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
25.0 ft
xx.x ft.
C)
D)
E)
2.
3.
34 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.4.4
PA-117 (ONSHORE RIG)
A)
Year Built
:
1981 (Upgrade / Refurbishment done in 2003)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Mid Continent U-1220 EB
LCM 156 ft.
1,300,000 lbs with12 lines
None
Continental Emsco T-3750
Oilwell 650 Tons
Continental Emsco LB650
Dreco, Load, casing 1,500,000 lbs, setback 800,000 lbs.
M.D. TOTCO, 6 Pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x Caterpillar D-399, 1000 HP ea.
2 x GE 752 Motors, 1000 HP ea.
4 x GE 752 Motors – 1000 HP ea.
Ind. Drive, GE 752 Motor, 1000 HP
None
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x Continental Emsco FB 1600 (1600 HP)
3000 bbl. capacity with120 bbl. Trip tank
3 x Derrick Flo Line Cleaners
Derrick – 800 GPM
None
None
SWACO – 800 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
Shaffer T20160-2S, 3000 psi, xx Stations
4 1/16”, 10,000 psi WP, sour service.
Cameron U 13-5/8” Double Ram, 10,000 psi with shear booster,
Hydril GK, 13-5/8” Annular 5000 psi – All H2S trimmed
F)
Safety Equipment
:
28 x Fire extinguishers, 1 x Fire pump, 1 x Gas detector, 1 x H2S
detectors, 2 x Cascade system, 2 x Mako breathable air
compressor, 1 x CO2 system, 0 x Eye Wash Stations, 2 x
Emergency Shower on Mud Pits
G)
Drill Pipe & Drill Collars
1. Drill Pipe
ft.
:
5 ½” Grade G, 24.7 lbs/ft -10,000 ft., 5” Grade G, 19.5 lbs/ft-15,000
HWDP
Drill collars
:
:
:
3-1/2” Grade G, 13.3 lbs./ ft - 9,000 ft.
9 of 6-5/8”, 30 of 5-½”, 50 of 5” and 50 of 3-½”
18 of 9 ½”, 30 of 8 ¼”, 30 of 6 ¼”, and 30 of 4 ¾”
H)
Depth Capacity
:
25,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
25.0 ft
20.0 ft
C)
D)
E)
2.
3.
35 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.4.5
PA-125 (ONSHORE RIG)
A)
Year Built
:
1980
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Mid Continent U-914EC (xxxx HP) w/ xxxxxx auxiliary brake
Lee C. Moore 25 ft x 152 ft.
1,000,000 lbs (static) with12 lines
Can-Rig 1050E – xxx Ton
National C375, 37 ½” – xxx Ton
Oilwell 500 – 500 Ton
None
Dreco – xxxxxxxx Csg, xxxxxxx set back.
Totco, 6 Pen
:
:
:
:
4 x Caterpillar 3512, 1300 HP ea. w/ ABC xxxxx KW generators
2 x GE 752 Motors, 1000 HP ea.
4 x GE 752 Motors – 1000 HP ea.
Ind. Drive, GE 752 Motor, 1000 HP, Torque xxxx Amps / xxxxx ft-
:
GE 752 Motors, 1000 HP, Torque xxxx Amps / xxxxx ft-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x Continental Emsco FB1600 (1600 HP)
2,000 bbl. capacity with100 bbl. Trip tank
2 x Derrick Flo Line Cleaners 513
Derrick 3 x 12” cone – 800 GPM
Derrick 12 x 2” cone – 800 GPM
None
Brandt, Model xxxx, – 1000 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, Vetco TX392-15SB3, xx stations
4 1/16”, Make? 10,000 psi WP, sour service.
Hydril GK, 13 5/8” Annular 5000 psi, Cameron U 13 5/8” double
ram, 10,000 psi with shear booster, Cameron U 13 5/8” single ram,
10,000 psi – All H2S trimmed
F)
Safety Equipment
:
23 x Fire extinguishers, 1 x Fire pump, 1 x Gas detector, 1 x H2S
detectors, 1 x Cascade system, MAKO breathable air compressor,
1 x CO2 system, 0 x Eye Wash Stations, 2 x Emergency Showers.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
HWDP
Drill collars
:
:
:
:
5” Grade-G, 19.5 lbs/ft -10,000 ft.
4” Grade-G, 14.5 lbs/ft-16,000 ft.
60 of 5” and 80 of 4”.”
12 of 9 ½”, 30 of 8 ¼”, 30 of 6 ¼”, and 30 of 4 ¾”
H)
Depth Capacity
:
15,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
xx.x ft
25.0 ft
C)
D)
E)
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
lbs.
5. Top Drive
2.
3.
36 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.4.6
PA-128 (ONSHORE RIG)
A)
Year Built
:
1980
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Mid Continent U-1220 EB
LCM 30 ft x 156 ft.
1,300,000 lbs with12 lines
National PS 350/500
Continental Emsco T-3750
Oilwell 650 Tons
None
Dreco
Totco, 6 Pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x Caterpillar D-399, 1000 HP ea.
2 x GE 752 Motors, 1000 HP ea.
4 x GE 752 Motors – 1000 HP ea.
Ind. Drive, 1 X GE 752 Motor, 1000 HP
1 x GE 752 Motors – 1000 HP, 1050 Amps / 54,000 ft./lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x Continental Emsco FB 1600 (1600 HP)
3000 bbl. capacity with120 bbl. Trip tank
3 x Derrick Flo Line Cleaners
Derrick – 800 GPM
as above
None
Swaco – 800 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, Shaffer T40240-3S,
4 1/16”, 10,000 psi WP, sour service.
2 x Cameron U 13-5/8” Double Ram, 10,000 psi with shear booster,
Hydril GK, 13-5/8” Annular 5000 psi – All H2S trimmed
F)
Safety Equipment
:
31 x Fire extinguishers, 1 x Fire pump, 1 x Gas detector, 1 x H2S
detectors, 1 x Cascade system, 2 x Mako breathable air
compressor, 1 x CO2 system, 0 x Eye Wash Stations, 2 x
Emergency Shower on Mud Pits
G)
Drill Pipe & Drill Collars
1. Drill Pipe
ft.
:
5 ½” Grade G, 24.7 lbs/ft -10,000 ft., 5” Grade G, 19.5 lbs/ft-15,000
HWDP
Drill collars
:
:
:
3-1/2” Grade G, 13.3 lbs./ ft - 9,000 ft.
9 of 6-5/8”, 30 of 5-½”, 50 of 5” and 50 of 3-½”
18 of 9 ½”, 30 of 8 ¼”, 30 of 6 ¼”, and 30 of 4 ¾”
H)
Depth Capacity
:
20,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
25.0 ft
20.0 ft
C)
D)
E)
2.
3.
37 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.4.7
PA-203 (ONSHORE RIG)
A)
Year Built
:
1978
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Ideco E-1700 (1700 HP) with Elmagco 7838W Auxiliary Brake
Pyramid 25 x 142 ft.
750,000 lbs with12 lines
None
Ideco 37 ½”
Name 400 Tons
Name 400 Tons
Pyramid – Load Capacity xxxxxxxxx Csg, xxxxxxxx set back.
Totco, 6 Pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x Caterpillar D-398, 900 HP ea.
2 x GE 752 Motors, 1000 HP ea.
6 x GE 752 Motors – 1000 HP ea.
Ind. Drive, 1 X GE 752 Motor, 1000 HP (xxxx Amps / xxxxx ft./lbs)
1 X GE 752 Motor, 1000 HP (xxxx Amps / xxxxx ft./lbs)
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x Oilwell 1400 PT (1400 HP)
3000 bbl. capacity with120 bbl. Trip tank
3 x Derrick Flo Line Cleaners
Derrick 12” x 3 cone – 800 GPM
Derrick 4” x 16 cone – 800 GPM
None
Swaco Model xxxx, 800 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
Koomy, 3000 psi, 16 Stations
4 1/16”, 10,000 psi WP, sour service.
Shaffer 30” annular – 1000 psi, 2 x Hydril 26 ¾” single ram – 3000
psi, 2 x Hydril 20 ¾” single ram – 3000 psi, Hydril GK, 13-5/8”
Annular – 5000 psi, Hydril 11” annular – 10000 psi, All H2S trimmed
F)
Safety Equipment
:
xx Fire extinguishers, 1 Fire pump, Air cascade system, 12 x 5-min.
Breathing apparatus, 19 SCBA 30 min Breathing Apparatus, Fixed
gas detection system, Portable gas detection Equipment, 5 x eye
wash stations, 1 emergency shower, 4 x wind socks
G)
Drill Pipe & Drill Collars
1. Drill Pipe
ft.
:
5 ½” Grade G, 24.7 lbs/ft -10,000 ft., 5” Grade G, 19.5 lbs/ft 15,000
2.
3.
HWDP
Drill collars
:
:
3 ½” Grade G, 13.3 lbs/ft 9,000ft., 2 7/8” Grade E, 6.7 lbs/ft 5,000 ft
30 of 5-½”, 30 of 5” and 50 of 3-½”
18 of 10”, 30 of 8 ½”, 30 of 6 ½”, and 30 of 4 ¾”
H)
Depth Capacity
:
17,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
31.0 ft
26.0 ft
C)
D)
E)
38 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.4.8
PA-207 (ONSHORE RIG)
A)
Year Built
B)
Rig Equipment
1. Drawworks
Brake
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
C)
D)
E)
F)
:
1956 (Refurbished 2005)
:
National 100-UE (1000 HP) with Baylor/Elmagco 6032 Auxiliary
:
:
:
:
:
:
:
:
Lee C. Moore, 24 ft x152 ft (Extended 10 ft., May 2006)
800,000 lbs. (static) with 12 lines
Can-Rig 1050 – 500 Ton.
National C375 37 ½” – 650 Ton
McKissick – 550 Ton
None
Lee C. Moore, Box-on-Box, set back 500,000 lbs.
Acadiana, 6-pen.
:
:
:
:
4 x Caterpillar D398, 825 HP ea. with 1000 KW generators
2 x GE 752 motors – 750 HP ea
4 x GE 752 motors – 750 HP ea
EMD S-79 motor – 800 HP, Torque 900 Amp/36,250 ft/lbs @ 100
:
GE 752 motor – 1000 HP, Torque 1250 Amps/30,000 ft/lbs @ 180
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x National 10-P-130 (1300 HP)
2237 bbl. capacity with 164 bbl trip tank capacity
2 x Derrick Flo Line Cleaners
Derrick 3 x 12” cone – 800 GPM
Derrick 20 x 4” cone – 800 GPM
None
Swaco Horizontal – 1000 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, CAD, 9 stations
3 1/8” EEC, 5000 psi WP, sour service.
Hydril GK 13 5/8” Annular 5000 psi, Cameron U 13 5/8” double
ram, 5000 psi, Cameron U 13 5/8” single ram, All H2S trimmed
:
3 x portable fire extinguishers, 5 x 10 lbs CO2 fire extinguishers, 41
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
RPM
5. Top Drive
RPM
Safety Equipment
x
30 lbs DCP fire extinguishers, 15 SCBA, 12 SABA, 2 x chemical
PPE box, 5 x eye wash stations, 1 emergency shower, 5 x wind
socks, 6 x portable gas monitors, (4 x Combustible Gas,2 x H2S),
Fire pump, Air Cascade System.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
4” Grade-CY, 14.0 ppf, 16,000 ft, 3 ½” Grade-G, 13.3 ppf, 5,000 ft.
2 3/8” Grade-C, 6.5 ppf, 5,000 ft
60 of 4”
30 of 6 ¼”, 30 of 4 ¾”, 30 of 2 7/8”, 30 of 2 3/8”
H)
Depth Capacity
:
16,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
25.5 ft
21.3 ft
39 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.4.9
PA-210 (ONSHORE RIG)
A)
Year Built
:
1975 (Inspected and recertified by Pyramid, Jun. 2001)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National 110 UE – 1500 HP with Baylor auxiliary brake
Pyramid 30’ x 24’ x 149 ft.
1,000,000 lbs. static with 12 lines
Can-Rig 1050E – 500 Ton
Oilwell A-37.5 (37 ½”) – 500 Ton
National 650G – 500 Ton
C. Emsco – 500 Ton
Pyramid Girder, Load casing 900,000 lbs, setback 800,000 lbs.
M.D./Totco, 6-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x Caterpillar D398, 900 HP ea. with 1030 KW generators
2 x EMD 79 motor – 800 HP ea.
4 x EMD 79 motor – 800 HP ea.
Ind. Dr. EMD 79 motor – 800 HP, Torque 1000 Amps / 26,500 ft-lbs.
GE 752 shunt motor, 1000 HP, Torque 1400 Amps / 31,000 ft-lbs.
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x Oilwell A-1700PT – 1700 HP ea. Gardner Denver PZ-7 – 550 HP
1900 bbl. capacity, 2 x 40 bbl trip tanks
2 x Derrick Flo Line Cleaner 503
Demco Sand Bull, 2 x 10” cone – 500 GPM
Demco Sand Bull, 8 x 4” cone – 500 GPM
None
Burgess Magna VAC – 1000 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, NL Shaffer with 8 stations, 12 x 10 gal. bottles
3 1/8” Cameron 5000 psi WP, sour service
Hydril MPS 21-1/4” annular 2000 psi, Cameron 13 5/8” annular
500 psi, Cameron U 13 5/8” double ram, 5000 psi, Cameron U
13 5/8” single ram, 5000 psi, All H2S trimmed.
F)
Safety Equipment
:
90 portable Fire extinguishers, 1 Fire pump, 4 x 150 lbs. wheeled
Fire Extinguishers, 58 x 30 lbs. wheeled Fire Extinguishers, 2 gas
detector, 4 H2S detectors, 1 cascade system with 12 work packs,
16 Scott Air Pack SCBAs, 2 portable gas/ H2S monitors, 4 eye
wash stations, 2 shower-mud pits, 4 wind socks, 1 Drager H2S
sniffer, 1 Bauer Breathable air compressor, 1 foam unit.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
HWDP
Drill collars
:
:
:
:
5” Grade-G, 19.5 ppf, 15,000 ft, 4’’Grade-G 14.0 ppf, 18,000 ft.
2 3/8” Grade-E 6.65 ppf, 2000 ft
60 of 5”, 60 of 4”
12 of 9-1/2”, 30 of 8 ¼”, 33 of 6 ¼”, 30 of 4 ¾”, 15 of 3 3/8”.
H)
Depth Capacity
:
18,000 ft
I)
DF – GL Elevation
Clear below DF – GL
:
:
25.5 ft
19.2 ft.
C)
D)
E)
2.
3.
40 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.4.10
PA-212 (ONSHORE RIG)
A)
Year Built
:
1975 (Major Refurbishment and Certification in 2001)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National 110 UE – 1500 HP with xxxxxxx auxiliary brake
Lee C. Moore 30’ x W x 152 ft.
990,000 lbs. static with 12 lines
Can-Rig 1165E – 500 Ton
National C375 (37 ½”) – xxx Ton
National model? – 500 Ton
None
LCM what type? Load casing xxxxxxx lbs, setback 800,000 lbs?
Totco, 6-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar D399, 1000 HP ea. with xxx KW generators
2 x EMD79motor – 1000 HP ea.
4 x EMD D79 – 1000 HP ea.
Ind. drive, EMD D79 motor 800 HP, Torque ….. Amps / xxxx ft-lbs.
1 GE 752 Motor, 1000 HP, Torque ……. Amps / 31000 ft.-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x C. Emsco FB-1300 – 1300 HP ea
2,000 bbl. capacity, 100 bbl trip tank
3 x Derrick Flo Line Cleaner 2000
Harrisburg 2 x 12” cone – 800 GPM ?
Demco 12 x 4” cone – 800 GPM
None
Swaco specify model No. 800 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, Shaffer with xx stations and 00 x 00 gal. bottles
3 1/8” Make? 5000 psi WP, sour service
Hydril GK 13 5/8” annular, 5000 psi, Cameron U 13-5/8” double ram,
5000 psi, Cameron U 13 5/8” single ram, 5000 psi, All H2S trimmed.
F)
Safety Equipment
:
29 Fire extinguishers, 1 Fire pump, 2gas detector, 4 H2S detectors,
1 cascade system with 12 work packs, 16 Scott Air Pack SCBAs, 2
portable gas/ H2S monitors, 4 eye wash stations, 2 shower-mud
pits, 4 wind socks, 1 Drager H2S sniffer, 1 MAKO Breathable air
compressor, 1 foam unit. PLEASE CHECK ALL
G)
Drill Pipe & Drill Collars
1. Drill Pipe
HWDP
Drill collars
:
:
:
:
5” Grade G, 19.5 lbs/ft, 10,000 ft.
4’’Grade G 105 14.0 lb/ft 18,000 ft
100 of 5”, 100 of 4”
12 of 9 ½”, 30 of 8 ½”, 30 of 6 ¼”, 60 of 4 ¾”
H)
Depth Capacity
:
15,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
xx.x ft
xx.x ft.
C)
D)
E)
2.
3.
41 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.4.11
PA-263 (ONSHORE RIG)
A)
Year Built
:
2002
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Oilwell E-2000 (2000 HP)
Dreco 32 ft x 147 ft.
1,000,000 lbs with12 lines
Can Rig 1050E
Oilwell B 37 ½”
Mc Kissick 650 Tons
None (Integrated with Top Drive)
Dreco.
Totco, 6 Pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x Caterpillar D-399, 1000 HP ea.
2 x GE 752 Motors, 1000 HP ea.
6 x GE 752 Motors – 1000 HP ea.
Ind. Dr, GE 752 Motor, 1000 HP, Torque 1050 Amps / 54,000 ft-lbs.
GE 752 Motor, 1000 HP, Torque 1050 Amps / 54,000 ft- lbs.
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
3 x Continental Emsco FB 1600 (1600 HP)
3000 bbl. capacity with120 bbl. Trip tank
3 x Derrick Flo Line Cleaners
Derrick – 800 GPM
None
None
Swaco – 800 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
CAD SB360-11SB3K, 3000 psi, xx Stations
4 1/16”, 10,000 psi WP, sour service.
2 x Cameron U 13-5/8” Double Ram, 10,000 psi, Hydril GK, 13-5/8”
Annular 5000 psi – All H2S trimmed with shear booster
F)
Safety Equipment
:
25 x Fire extinguishers, 1 x Fire pump, 1 x Gas detector, 1 x H2S
detectors, 2 x Cascade system, 2 x MKO breathable air
compressor, 1 x CO2 system, 0 x Eye Wash Stations, 2 x
Emergency Shower on Mud Pits
G)
Drill Pipe & Drill Collars
1. Drill Pipe
ft.
:
5 ½” Grade G, 24.7 lbs/ft -12,000 ft., 5” Grade G, 19.5 lbs/ft-15,000
HWDP
Drill collars
:
:
:
3-1/2” Grade G, 13.3 lbs./ ft - 9,000 ft.
9 of 6-5/8”, 30 of 5-½”, 50 of 5” and 50 of 3-½”
18 of 9 ½”, 30 of 8 ¼”, 30 of 6 ¼”, and 30 of 4 ¾”
H)
Depth Capacity
:
25,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
32.0 ft
26.0 ft
C)
D)
E)
2.
3.
42 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.4.12
PA-295 (ONSHORE RIG)
A)
Year Built
:
1988 (Refurbished: Dec. 2004)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Mid Continent, U-1220 EB (2000 HP) with 7838 Elmagco Brake
Pyramid 31’ x 152 ft.
1,000,000 lbs. (static) with 12 lines
National 350/500 – 500 Ton
Oilwell B-37 1/2 (37-1/2”)
Continental Emsco – 500 Ton
Continental Emsco – LB 650 Ton
Pyramid Cantilever Type, casing 900,000 lbs, setback 700,000 lbs
Totco, 7 pen & Epoch Rig Watch system
:
:
:
:
4 x Caterpillar D399, 1225 HP ea. With 1050 KW generators
2 x GE 752 motor – 1000 HP ea.
4 x GE 752 – 1000 HP ea.
Ind. Dr. GE 752 motor – 1000 HP, Torque 1400 Amps / 38,000 ft.-
:
GE 752 motor – 1000 HP, Torque 1400 Amps / 38,455 ft.-lbs
:
:
:
:
:
:
:
2 x Continental Emsco FB 1600 – 1600 HP ea.
2000 bbl. capacity, 1200 bbl. active with 120 bbl trip tanks
3 x Derrick-Flo Line Cleaner 500
Derrick 3 x 10” cones
Derrick 20 x 4” cones
Derrick DE-1000 hydraulic, Variable GPM
Brandt DG-10 – 1000 GPM
:
:
:
3000 psi, Vetco TX392-15SB3 with 14 stations
4 1/16” Energy Equipment Corporation, 10000 psi WP, sour service
Hydril GK 13-5/8” Annular 5000 psi, Cameron U 13-5/8” double
C)
D)
E)
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
lbs
5. Top Drive
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
ram,
5000 psi, Cameron U 13-5/8” single ram, 5000 psi, All H2S trimmed.
F)
Safety Equipment
:
104 Fire extinguishers, 1 Fire pump, 4 gas detector, 4 H2S
detectors, 1 cascade system, 29 Scott Air Pack SCBAs, 4 portable
gas/ H2S monitors, 5 eye wash stations, 1 shower-mud pits, 5 wind
socks, 2 Drager H2S sniffer, 1 Mako Breathable air compressor, 2
Gastec units w/ accessories & tubes.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
HWDP
Drill collars
:
:
:
:
:
4” Grade G, 14.0 lbs./ ft, 16,000 ft.
3-1/2” Grade G, 13.3 lbs./ ft, 5,000 ft.
2-3/8” Grade E, 6.6 lbs / ft, 5,000 ft.
60 of 4”
30 of 6-1/4”, 30 of 4-3/4”, 30 of 2 7/8”
H)
Depth Capacity
:
25,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
31.5 ft
25.5 ft
2.
3.
43 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.4.13
PA-312 (ONSHORE RIG)
A)
Year Built
:
1976
B)
Rig Equipment
1. Drawworks
Brake
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
Gardner Denver 1500E (2000 HP) w/ National Baylor Elmagco
:
:
:
:
:
:
:
:
Pyramid 27’ x 152 ft.
1,000,000 lbs. (static) with 12 lines
Can-Rig 1050E – 500 Tons
National C375, 37 ½”
Continental Emsco – 500 Tons
None
Pyramid, casing 700,000 lbs, setback 450,000 lbs.
Totco, 6-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x Caterpillar D398, 825 HP ea. with 1,000 KW generators
2 x GE 752 motor – 1000 HP ea.
4 x GE 752 – 1000 HP ea.
GE 752 motor – 1000 HP, Torque 1000 Amps / 15,130 ft-lbs
GE 752 motor, 1000 HP, Torque 1400 Amps / 38,455 ft-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x Continental Emsco FB-1600 – 1600 HP ea.
2000 bbl. capacity, 1500 bbl. Active with 100 bbl trip tank
2 x Derrick-Flo Line Cleaner 513
Derrick 3 x 10” cone – 800 GPM
Derrick 20 x 4”cone – 800 GPM
Derrick DE-1000 – 220 GPM
Brandt – 800 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, CAD 4201472-BS2 with 14 stations
4 1/16” Energy Equipment 10,000 psi WP, sour service
Hydril GK 13-5/8” Annular 5000 psi, Cameron UU 13-5/8” double
Ram, 5000 psi with booster, Cameron UU 13-5/8” single ram, 5000
psi, All H2S trimmed.
F)
Safety Equipment
:
32 Fire extinguishers, 1 Fire pump, 4 gas detector, 4 H2S detectors,
Cascade System, 29 Scott Air Pack SCBAs, 4 portable gas/ H2S
monitors, 5 eye wash stations, 1 shower-mud pits, 5 wind socks, 2
Drager H2S sniffer, 1 Mako Breathable air compressor.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
HWDP
Drill collars
:
:
:
:
4” Grade-G, 15.0 ppf, 16,000 ft.
3 ½” Grade G, 13.3 ppf, 5,000 ft.
60 of 4”
30 of 6 ¼”, 30 of 4 ¾”, 30 of 2 7/8”
H)
Depth Capacity
:
25,000 feet
I)
DF – GL Elevation
Clearance below DF
:
:
31.5 ft.
25.5 ft.
C)
D)
E)
2.
3.
44 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.4.14
PA-393 (ONSHORE RIG)
A)
Year Built
:
1980 (Upgraded in 2005)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Mid Continent U-1220 EB (2,000 HP) w/ Elmagco auxiliary brake
Dreco 25 ft x 152 ft.
1,167,000 lbs (static) with12 lines
National PS 350/500 – 350 Ton (Drilling) – 500 Ton (Max. Pull)
C. Emsco T3750, 37 ½” – 350 Ton
C. Emsco – 500 Ton
None
Dreco – Load casing 1,167,000 lbs, setback 700,000 lbs.
Totco, 6 Pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar 3512, 1500 HP ea. w/ ABC 1365 KW generators
2 x GE 752 Motors – 1000 HP ea.
4 x GE 752 Motors – 1000 HP ea.
GE 752 Motor – 1000 HP, Torque 1200 Amps / 38455 ft-lbs.
GE 752 Motors, 1085 HP, Torque 1400 Amps / 38455 ft-lbs.
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x Continental Emsco FB1600 (1600 HP)
2,000 bbl. capacity with100 bbl. Trip tank
2 x Derrick Flo Line Cleaners 513
Derrick 3 x 12” cone – 800 GPM
Derrick 12 x 2” cone – 800 GPM
None
Brandt, Model DG-10, – 1000 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, CAD with 14 stations
4 1/16” EEC, 10,000 psi WP, sour service.
Hydril GK, 13 5/8” Annular 5000 psi, Cameron U 13 5/8” double
ram
10,000 psi with shear booster, Cameron U 13 5/8” single ram,
10,000 psi – All H2S trimmed
F)
Safety Equipment
:
21 x Fire extinguishers, 1 x Fire pump, 1 x Gas detector, 1 x H2S
detectors, 1 x Cascade system, MAKO breathable air compressor,
1 x CO2 system, 0 x Eye Wash Stations, 2 x Emergency Showers.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
HWDP
Drill collars
:
:
:
:
5” Grade-G, 19.5 ppf, 10,000 ft.
4” Grade-G, 14.5 ppf, 16,000 ft.
60 of 5” and 80 of 4”.
12 of 9 ½”, 30 of 8 ¼”, 30 of 6 ¼”, and 30 of 4 ¾”
H)
Depth Capacity
:
20,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
33.6 ft
25.0 ft
C)
D)
E)
2.
3.
45 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.4.15
PA-575 (ONSHORE RIG)
A)
Year Built
:
1975
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National 1320 UE (2000 HP) with Baylor Elmago Brake
Pyramid 25’ x 152 ft.
1,000,000 lbs.
National PS 350/500 – 500 Ton
National C375, 37 ½” – 500 Tons
Mc Kissick – 500 Ton (Hook/Block Combination)
None
Pyramid single pony, set back 1,000,000 lbs
Totco, 6-pen and Epoch Rig Watch System
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar D399, 825 HP ea. w/ KATO 1050 KW generators
2 x GE 752 motor – 1000 HP ea.
4 x GE 752 – 1000 HP ea.
GE 752 motor – 1000 HP, Torque 1400 Amps / 17,600 ft/lbs.
GE 752 motor – 1000 HP, Torque 1400 Amps / 38,712 ft/lbs.
:
:
:
:
2 x National FB-1600 – 1600 HP ea.
2000 bbl. capacity, 1500 bbl. Active with 172 bbl trip tank
2 x Derrick-Flo Line Cleaner 513
Brandt 4 x 10” cone – 500 GPM, Derrick Hi-Speed 20 cone –
:
:
:
Brandt 16 x 4” cone – 500GPM
None
Brandt DG-10 – 500GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, Koomey E-80 with 3 stations and 28 x 10 gal bottles.
3 1/16” EEC, 5000 psi WP, sour service
Hydril 21 ¼” Annular 2000 psi, Hydril GK 13-5/8” Annular 5000 psi,
Cameron U 13-5/8” double ram, 5000 psi with booster, Cameron U
13-5/8” single ram, 5000 psi, All H2S trimmed.
F)
Safety Equipment
:
Zeiger, 8-channel gas monitoring system, 25 Fire extinguishers, 1
Fire pump, 4 gas detector, 4 H2S detectors, 1 cascade system, 29
Scott Air Pack SCBAs, 4 portable gas/ H2S monitors, 5 eye wash
stations, 1 shower-mud pits, 5 wind socks, 2 Drager H2S sniffer, 1
MAKO Breathable air compressor.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
HWDP
Drill collars
:
:
:
:
:
5” Grade-G, 19.5 ppf, 10,000 ft.
4” Grade G, 14.5 ppf, 16,000 ft.
2 3/8” Grade E 00.0 ppf, 3000 ft.
60 of 5”, 80 of 4”
12 of 9 ½”, 30 of 8 ¼”, 30 of 6 ¼”, 30 of 4 ¾”, 15 of 3 ½”
H)
Depth Capacity
:
20,000 feet
I)
DF – GL Elevation
Clearance below DF
:
:
30.0 ft.
25.5 ft.
C)
D)
E)
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
1000 GPM
5. Desilter
6. Centrifuge
7. Degasser
2.
3.
46 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.4.16
PA-654 (ONSHORE RIG)
A)
Year Built
:
1975
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National 1320 UE (2000 HP) with Auxiliary Brake
Lee C. Moore 30’ x 152 ft.
1,000,000 lbs. (static) with 12 lines
Can Rig 1050E – 500 Ton
National C375, 37 ½” – 500 Ton
National Model? – 500 Ton
None
LCM, type? casing xxxxxx lbs, setback 600,000 lbs.
Totco, 6-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar 3512, 1300 HP ea. w/ KATO 1050 KW generators
2 x GE 752 motor – 1000 HP ea.
4 x GE 752 – 1000 HP ea.
GE 752 motor – 1000 HP, Torque …… Amps / …… ft-lbs
GE 752 motor, 1000 HP, Torque 000 Amps / 000000 ft-lbs
:
:
:
:
2 x C. Emsco FB-1600 – 1600 HP ea.
2000 bbl. capacity, with 100 bbl trip tank
2 x Derrick-Flo Line Cleaner 513
Derrick 10” x 4 cones – 1000 GPM, Derrick Hi-Speed 20 cone ….
:
:
:
Derrick 4” x 16 cones – 1000 GPM
None
Brandt DG-10 – 1000 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, Vetco Model? with xx stations and 00 x 00 gal bottles.
4 1/16” MAKE?, 10,000 psi WP, sour service
Hydril GK 13-5/8” Annular 5000 psi, Cameron U 13-5/8” single ram,
5000 psi, Cameron U 13-5/8” double ram, 5000 psi, with booster.
All H2S trimmed.
F)
Safety Equipment
:
Zeiger, 8-channel gas monitoring system, 23 Fire extinguishers, 1
Fire pump, 4 gas detector, 4 H2S detectors, 1 cascade system, 29
Scott Air Pack SCBAs, 4 portable gas/ H2S monitors, 5 eye wash
stations, 1 shower-mud pits, 5 wind socks, 2 Drager H2S sniffer, 1
MAKO Breathable air compressor.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
5” Grade-G, 19.5 ppf, 10,000 ft.
4” Grade G, 14.0 ppf, 16,000 ft.
2 3/8” Grade E 00.0 ppf, 3000 ft.
60 of 5”, 80 of 4”
12 of 9 ½”, 30 of 8 ¼”, 30 of 6 ¼”, 30 of 4 ¾”
H)
Depth Capacity
:
22,000 feet
I)
DF – GL Elevation
Clearance below DF
:
:
00.0 ft.
25.5 ft.
C)
D)
E)
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
GPM
5. Desilter
6. Centrifuge
7. Degasser
47 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.4.17
PA-718 (ONSHORE RIG)
A)
Year Built
:
1981 (Commenced Operations: Dec. 2004)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Gardner Denver 1100E (1500 HP)
Dreco 24’ x 152 ft. (Mast Extension Mar. 2006)
787,000 lbs. (12 lines)
Can-Rig-1050E – 500 Ton
Gardner Denver 37-1/2”
National G-650
None
Dreco Slingshot, Casing 775,000 lbs., setback 450,000 lbs.
Martin Decker, 7 pen
:
5 x Caterpillar D398, 800 HP ea. w/ Kato 1030/900/800 KW
:
:
:
:
2 x EMD D-79 motor – 800 HP ea.
4 x EMD D-79 motor – 800 HP ea.
Compound Drive (Installed Mar. 2006)
GE 752, 1000 HP, Torque 1250 Amps / 30,000 ft-lbs.
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x Gardner Denver PZ-11(1600 HP)
2120 bbl. capacity with 160 bbl trip tanks
2 x Derrick-Flo Line Cleaner
Derrick Super ‘G’ Model-58, 3 cone – 500 GPM
Derrick Super ‘G’ Model-58, 20 cone – 500 GPM
None
Derrick Vacu-Flo – 1200 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, Koomey type-80, 10 Station
3 1/8” EEC, 5000 psi WP, sour service
Hydril GK 13-5/8” Annular 5000 psi, Cameron UU 13-5/8” double
ram, 5000 psi, Cameron U 13-5/8” single ram, 5000 psi, All H2S
trimmed
F)
Safety Equipment
:
82 Fire extinguishers, 1 Fire pump, 1 gas detector, 4 H2S detectors,
Cascade system, 32 Scott Air Pack SCBAs, 2 portable gas / H2S
Monitors, 4 eye wash stations, 1 shower-mud pits, 6 wind socks, 2
Dragger H2S sniffer,1 Bauer Breathable air compressor.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
4” Grade CY-105, 14.00 ppf, 8,525 ft., 3-1/2” Grade G-105, 13.3
ppf, 5,084 ft., 2 3/8” Grade-E 6.65 ppf, 2,480 ft.
60 of 4”
28 of 6 ¼”, 30 of 4 ¾”, 15 of 2 7/8”
H)
Depth Capacity
:
16,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
29.30 ft
25.80 ft
C)
D)
E)
48 of 102
Rig Power
1. Engine Power
generators
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.4.18
PA-785 (ONSHORE RIG)
A)
Year Built
:
1981
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
lbs.
9. Geolograph
:
:
:
:
:
:
:
:
Ideco E-1700 (1700 HP) with Baylor auxiliary brake
Dreco 30’ x 142 ft.
900,000 lbs.
Can Rig 1050E – 500 Ton
Ideco LR275 27 ½” – 500 Ton
National – 500 Tons (Hook/Block Combination)
Integrated with Top Drive
Pyramid Sling shot type, casing 1,000,000 lbs, set back 600,000
:
Acadia, 7-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar D399, 1000 HP ea. w/ 1313 KVA generators
2 x GE 752 motor – 1000 HP ea.
4 x GE 752 – 1000 HP ea.
GE 752 motor – 800 HP, Torque 750 Amps / 25,000 ft-lbs
Can-Rig, AC motor, 800 HP, Torque 1350 Amps / 30,000 ft-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
5. Centrifuge
6. Degasser
:
:
:
:
:
:
:
2 x C. Emsco FB-1600 – 1600 HP ea.
2000 bbl. capacity with 100 bbl trip tank
2 x Derrick-Flo Line Cleaner
Derrick 2 x 12” cones – 1000 GPM
Derrick 12 x 4” cones – 1000 GPM
None
Harrisburg – 1000 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, Koomey T20180
4 1/16” EEC, 10,000 psi WP, sour service
Hydril GK 13-5/8” 5000 psi,
Cameron UU 13 5/8” double ram, 5000 psi,
Cameron U 13 5/8” single ram, 5000 psi, All H2S trimmed.
F)
Safety Equipment
:
21 Fire extinguishers, 1 Fire pump, 1 gas detection system, 4 H2S
detectors, 1 cascade system, 16 Scott Air Pack SCBAs, 2 portable
gas/ H2S monitors, 3 eye wash stations, 1 shower at mud pits, 4
wind socks, 1 Drager H2S sniffer, 1 Bauer Breathable air
compressor.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
HWDP
Drill collars
:
:
:
:
4” Grade-G, 14.5 ppf, 16,000 ft.
3 ½” Grade-G, 13.3 ppf, 5,000 ft.
60 of 4’’
30 x 6 ¼” 30 x 4 ¾”
H)
Depth Capacity
:
18,000 ft.
I)
DF – GL Elevation
Clearance below DF
:
:
29.0 ft.
25.0 ft.
C)
D)
E)
2.
3.
49 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.4.19
PA-854 (ONSHORE RIG)
A)
Year Built
:
1982 (New Dog House, Mud Cleaner and Minor Refurbishments)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Cabot / IRI 2042 (700 HP)
Four Leg Cabot / IRI 12’ x 117 ft.
300,000 lbs.
None
National C275 (27 ½”) – 300 Ton
Gardner Denver – 200 Ton
Gardner Denver – 200 Ton
Pyramid Sling shot type, casing 300,000 lbs, set back 250,000 lbs.
Totco, 4-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
2 x Caterpillar 3406 DI, 825 HP ea. w/ 250 KW generators
2 x GE 752 motor – 800 HP ea.
2 Caterpillar 398 – 800 HP ea.
Compound Drive, Torque 30,000 ft-lbs.
None
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander / Desilter
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x Gardner Denver PZ-8 – 800 HP ea.
1500 bbl. capacity with 100 bbl trip tank
1-Derrick-Flo Line Cleaner
One Desander
None
None
National – 800 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, Koomey T20160 with 8 stations
3 1/8” Cameron 5,000 psi WP, sour service
Shaffer LWS 13 5/8” double ram , 3000 psi,
Shaffer LWS 13 5/8” annular 3000 psi, All H2S trimmed.
F)
Safety Equipment
:
49 Fire extinguishers, No Fire pump, 1 gas detection system, 1
cascade system, 16 Scott Air Pack SCBAs, 2 portable gas/ H2S
monitors, 2 eye wash stations, 1 shower at mud pits, 3 wind socks,
1 Drager H2S sniffer, 1 Bauer Breathable air compressor,
G)
Drill Pipe & Drill Collars
1. Drill Pipe
HWDP
Drill collars
:
:
:
:
3 ½” Grade-E, 13.3 ppf, 10,000 ft.
2 3/8” Grade-E, 6.65 ppf, 5,650 ft.
None
10 x 6 ¼”, 20 x 4 ¾”, 20 of 3 3/8”
H)
Depth Capacity
:
12,500 ft
I)
DF – GL Elevation
Clearance below DF
:
:
20.0 ft.
16.0 ft.
C)
D)
E)
2.
3.
50 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.4.20
PA 858 (ONSHORE RIG)
A)
Year Built
:
1975
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Cabot / IRI Model 2042 (720 HP ) w/ Hydromatic Auxiliary Brake
Cabot / IRI, 117 ft.
350,000 lbs
None
National C-275 (27 ½”) – 500 Ton
McKissick – 250 Ton (Hook / Block Combination)
National N-47 – 200 Ton
Cabot Bogie type (wheel), Load 500,000 lbs. simultaneous capacity
Totco, 6 pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
2 x Caterpillar 3412 – 665 HP ea w/ 650 KW generators
2 x Caterpillar 3406 – 350 HP ea.
2 x Caterpillar D 398 – 860 HP ea
Compound Chain Drive (Mechanical Drive)
None
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x National 8-P-80 – 800 HP ea
1300 bbl. capacity with 100 bbl trip tank
1 x Derrick-Flo Line Cleaner
none
None
None
Brandt DG-10 – 1000 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, Koomey with 7 stations
2 1/16” Cameron 5000 psi WP, sour service
Cameron UU 13 5/8” double ram, 5000 psi,
Cameron U 13 5/8” single ram, 5000 psi,
Hydril GK 13 5/8” Annular 5000 psi, All H2S trimmed
F)
Safety Equipment
:
54 Fire extinguishers, 1 Fire pump, 1 gas detector, 4 H2S detectors,
1 cascade system, 16 x 30-min. Scott Air Pack SCBAs, 12 x 15min. Diablo Air packs, 2 portable gas / H2S monitors, 2 eye wash
stations, 6 small bottle eye wash, 1 shower at mud pits, 4 wind
socks, 1 BW Defender H2S sniffer, 1 Bauer Breathable air
compressor.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
HWDP
Drill collars
:
:
:
:
3 ½” Grade E 13.3 ppf, 10,000 ft.
2 3/8” Grade E 6.65 ppf, 5,000 ft.
None
14 of 6 ¼”, 20 of 4 ¾”, 20 of 3 3/8”
H)
Depth Capacity
:
12,500 ft
I)
DF – GL Elevation
Clearance below DF
:
:
18 .0
16.0
C)
D)
E)
2.
3.
51 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.4.21
PA-859 (ONSHORE RIG)
A)
Year Built
:
1977 (Refurbished & Upgraded to 1500 HP, August 2002)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National 110 UE (1500 HP) with Auxiliary Brake
Pyramid, 25’ x 142 ft.
771,000 lbs. (static) with 12 lines
None
National C-375 (37-1/2”) – 500 Ton
National – Type G 650 G500 (Hook/Block Combination)
C. Emsco LB400 – 400 Ton
Pyramid
Wagner, 6-pen
:
:
:
:
5 x Caterpillar D398, 960 HP ea.
2 x GE 752 motor – 800 HP ea.
4 x GE 752 – 800 HP ea.
Ind. Dr., GE 752 motor – 800 HP, Torque 1000 Amps / 24,000 ft-
:
None
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x Continental Emsco FB1600 (1600 HP) & one Oilwell A 1100PT
4500 bbl. capacity, 120 bbl trip tank
2 x Derrick-Flo Line Cleaner
Derrick High G Drier 1200 GPM
Derrick High G Drier 1200 GPM
None
Swaco 1000 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, CAD
10000 psi WP, sour service
Hydril GX 11” annular 10,000 psi, 2 x Cameron U 11” double ram,
10,000 psi, All H2S trimmed.
F)
Safety Equipment
:
70 Fire extinguishers, 1 Fire pump, 1 gas detector, 4 H2S detectors,
1 cascade system, 17 Faber 15 min & 14 EA Diablo 30 min Scott
Air Pack SCBAs, 2 portable gas/ H2S monitors, 3 eye wash
stations, 1 shower-mud pits, 5 wind socks, 1 Drager H2S sniffer, 1
Mako Breathable air compressor,
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
5” Grade G, 19.5 ppf, 15,000 ft, 3-1/2” Grade G, 13.3 ppf, 10,000 ft,
3-1/2” Grade E, 13.3 ppf, 4,000 ft., 3-1/2” Grade G, 15.5 ppf, 4,000
ft, 2-3/8” Grade E, 6.65 ppf, 4,000 ft
60 of 5”, 60 of 3-1/2”
30 of 6-1/4”, 30 of 4-3/4”, 15 of 3-3/8”
H)
Depth Capacity
:
16,000 ft.
I)
DF – GL Elevation
Clearance below DF
:
:
31 ft.
25 ft.
C)
D)
E)
52 of 102
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
lbs.
5. Top Drive
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.4.22
PA-860 (ONSHORE RIG)
A)
Year Built
:
1978 (Re-furbished – Dec. 2003)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Ideco E-1700 (1700 HP) with Elmagco 7838W Brake
Pyramid 25 x 152 ft.
771,000 lbs with 12 lines
Can Rig 1050E – 500 Ton
Oilwell A 37 ½”
Ideco –TB-525-6-50 – 400 Ton
National P400 – 400 Ton
Pyramid – Load Casing 700,000 lbs, Set back 500,000 lbs.
Totco, 6-Pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x Caterpillar D-398, 900 HP ea with 800 KW generators
2 x GE 752 Motors, 1000 HP ea.
4 x GE 752 Motors – 1000 HP ea.
Ind. Drive, GE 752 Motor, 1000 HP (963 Amps / 19500 ft/lbs)
GE 752 Motor, 1132 HP (1000 Amps / 33,300 ft/lbs)
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
8. Dryer
:
:
:
:
:
:
:
:
2 x Oilwell A1700PT (1700 HP)
3000 bbl. capacity with77 bbl. trip tank
3 x Derrick Flo Line Cleaners 2000
Demco 12” x 3 cone – 800 GPM
Demco 4” x 16 cone – 800 GPM
None
Brandt Model DG-10 – 1000 GPM
Derrick, Hi-“G”
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
Shaffer T20200, 3000 psi, 16 Stations
4 1/16”, 10,000 psi WP, sour service.
Hydril 30” Annular 1000 psi, Hydril 21 ¼” Annular 2000 psi, Hydril
13 5/8” Annular 5000 psi, Hydril 11” Annular 5000 psi, 2 x Cameron
26 ¾” single ram 3000 psi, 2 x Cameron 13 5/8” double ram 10000
psi, Shaffer 20 ¾” double ram 3000 psi, Shaffer 20 ¾” single ram
3000 psi, All H2S trimmed.
Shaffer 13 5/8” Rotating Head 500 psi WP
F)
Safety Equipment
:
50 Fire extinguishers, 1 Fire pump, 31 x 5-min. Breathing
apparatus, Air Cascade system, 2 x BAUER BA compressor. 1
emergency shower, 4 x wind socks
G)
Drill Pipe & Drill Collars
1. Drill Pipe
ft.
:
5 ½” Grade G, 24.7 lbs/ft -10,000 ft, 5” Grade G, 19.5 lbs/ft 15,000
2.
3.
HWDP
Drill collars
:
:
3 ½” Grade G, 13.3 lbs/ft 9,000ft, 2 3/8” Grade-E, 6.65 lbs/ft 5000ft.
30 of 5 ½” & 50 of 5” & 50 of 3 ½”
18 of 9 ½”, 30 of 8 ½”, 30 of 6 ¼”, 30 of 4 ¾”, 24 of 2 7/8”
H)
Depth Capacity
:
18,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
32.8 ft
25.3 ft
C)
D)
E)
53 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.4.23
PA-866 (ONSHORE RIG)
A)
Year Built
:
1985 (Upgrade / Refurbishment done in 2003)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Continental Emsco, C-III (2000 HP) with Elmagco Auxiliary Brake
Dreco 28 ft x 147 ft
1,555,000 lbs (with 14 lines)
National PS-350/500 – 500 Ton
National C-375 (37 ½”) – 650 Ton
Continental Emsco – 650 Ton
National P-500 – 500 Ton
Dreco Sling Shot – casing 1,500,000 lbs., setback 800,000 lbs.
MD Totco, 7-Pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x D-399 Caterpillar, 1195 HP ea. with 1030 KW generators
2 x GE 752 Motors, 1000 HP ea.
6 x GE 752 Motors – 1000 HP ea.
Ind. Dr, GE 752 Motor – 1000 HP (1050 Amps / 54,000 ft.-lbs)
GE 752 Motor – 1000 HP (1050 Amps / 54,000 ft.-lbs)
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
3 x Continental Emsco FB-1600 (1600 HP ea.)
4000 bbl with 120 bbl. Trip tank
3 x Derrick Super G Flo Line Cleaners
2 Derrick DSV-3, 3 x 12” cone – 1000 GPM
2 Derrick D-RND-16, 16 x 2” cone – 1600 GPM
None
Swaco – 1000 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, CAD SB360-11SB3K with 14 stations
4-1/16” EEC, 10,000 psi WP with 5 x HCR Valves, Sour Service
Hydril 30” Annular 1000 psi with 7-1/16” HCR Diverter Valves, 2 x
Cameron U 26-3/4” Single Ram, 3000 psi, Hydril MSP 21-1/4”
Annular 2000 psi, Cameron UU 20-3/4” Double Ram 3000 psi,
Cameron U 20-3/4” Single Ram 3000 psi, Hydril GK 13-5/8”
Annular 5000 psi, Cameron UU 13-5/8” Double Ram 10,000 psi, 2 x
Cameron U 13-5/8” Single Ram 10,000 psi – All H2S trimmed
F)
Safety Equipment
:
54 Fire extinguishers, 1 Fire pump, 1 (Pem Tech) Gas detector
system with 1 LEL and 5 H2S detectors, 1 Bauer Cascade system
breathable air compressor, 17 ea. Scott 30 min Air Packs SCBA's,
8 x 5-min. Scott Air Packs SCBA, 7 x 15-min Air Packs SCBA’s, 6 x
Portable H2S monitors, 2 x Portable LEL monitors, 5 x Eye Wash
Stations, Emergency Shower on Mud Pits, 7 Wind socks.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
HWDP
Drill collars
:
:
:
:
5 ½” Grade G, 24.7 ppf, 12,000 ft., 5” Grade G, 19.5 ppf, 15,000 ft.
3-1/2” Grade G, 13.3 ppf, 9,000 ft.
15 of 6-5/8”, 30 of 5-½”, 50 of 5” and 50 of 3-½”
18 of 9-1/2”, 30 of 8-1/2”, 30 of 6-1/4”, and 30 of 4-3/4”
H)
Depth Capacity
:
28,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
38.2 ft
31.7 ft
C)
D)
E)
2.
3.
54 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.5.1
PD-144 (ONSHORE RIG)
A)
Year Built
:
1978 (10’ mast extension)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Continental Emsco C-3 (3000 HP) with Elmagco 7838W brake
Lee C. Moore 152 ft.
1,500,000 lbs. (static) with 14 lines
Varco-IDS-1
Oilwell B-37.5, 37 ½”
Oilwell A500 with BJ 5750 Dynaplex Hook
Integrated with top drive
Lee C. Moore Swing Up, casing 1,500,000 lbs, set back 750,000 lbs.
MD Totco, 8 pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar D3516, 1855 HP ea. w/ 1322 KW Generator
2 x GE 752 DC motor – 1000 HP ea.
6 x GE 752 – 1000 HP ea. (2 with each pump)
Ind. drive, GE 752 motor 1000 HP
AC Motor, 1000 HP.
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
3 x Oilwell A-1700-PT – 1700 HP ea.
4000 bbl. capacity (active and reserve120 bbl. trip tank
3 x Derrick Flo-line Cleaners
Demco 2 x 12” cone – 1600 GPM.
Harrisburg 20 x 4” cone – 1600 GPM.
None
Swaco 225, double life vacuum – 1000 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, CAD 550USG.
4 1/16” 10000 psi w/ 2 x hydraulic chokes and one manual
2 x Cameron U 13-5/8” double ram, 10000 psi, H2S trim.
Hydril GL 13-5/8” x 5000 psi,
F)
Safety Equipment
:
100 Fire extinguishers, 1 Fire pump, Air cascade system, 12
Breathing 5 min apparatus, 19 SCBA 30 min Breathing Apparatus,
Fixed gas detection system, Portable gas detection Equipment,
5 eye wash stations, 2 emergency showers, 4 x wind socks
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
:
5 ½” Grade G, 24.7 ppf, 12,000 ft.
5” Grade G, 19.5 ppf, 15,000 ft
3-1/2” Grade G, 13.3 ppf, 9,000 ft.
15 x 6 5/8”, 30 x 5 ½”, 50 x 5”, 50 of 3 ½”
18 of 9 ½”, 30 of 8 ½”, 30 of 6 ¼”, 30 of 4 ¾”
H)
Depth Capacity
:
20,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
35.0 ft
29.0 ft
C)
D)
E)
55 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.5.2
PD-157 (ONSHORE RIG)
A)
Year Built
:
1978
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Ideco E-1700 (1700 HP) with Elmagco 6032 auxiliary brake
Dreco width x 142 ft
900,000 lbs. (static) with 12 lines
None
Oilwell B-37 ½”
National 660H500 with BJ 5500 Dynaplex Hook, 1,000,000 lbs.
Ideco TL-500, 1,000,000 lbs.
Dreco Slingshot, casing 800,000 lbs, set back 880,000 lbs
Specify type with number of pens and system ?
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar D399, 1200 HP ea. w/ 1050 KW Generator
2 x GE 752 DC motor – 1000 HP ea.
2 x GE 752 DC motors – 1000 HP ea.
Ind. drive, GE 752 motor 1000 HP, Torque xxx Amps / xxxxx ft.-lbs
N/A
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
1 x Oilwell A-1700-PT, 1 x Oilwell A-1400-PT, 1 x Ideco T-1600
3599 bbl. Capacity (active and reserve) mention trip tank ?
3 x Derrick Dual Flow with 2 x National Mud Cleaners (capacity?)
Make ? 2 x 12” cone specify GPM ?
Make ? 16 x 4” cone specify GPM ?
None
Make?, Closed Bottom, 36” OD, 4” Outlet (specify GPM ?)
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, Koomey 550 USG
4 1/16” Make?, 10000 psi w/ 2 x hydraulic chokes and one mannual
2 x Cameron U 13-5/8” double ram, 10000 psi, H2S trim (check?)
Hydril GL 13-5/8” x 5000 psi,
F)
Safety Equipment
:
100 Fire extinguishers, 1 Fire pump, Air cascade system, 12
Breathing 5 min apparatus, 19 SCBA 30 min Breathing Apparatus,
Fixed gas detection system, Portable gas detection Equipment,
5 eye wash stations, 1 emergency shower, 4 x wind socks
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
:
5 ½” Grade G, 24.7 lbs./ft, 12,000 ft.
5” Grade G, 19.5 lbs/ft, 15000 ft
3 ½” Grade G, 13.3 lbs./ft, 9,000 ft.
15 x 6 5/8”, 30 x 5 ½”, 50 x 5”, 50 of 3 ½”
18 of 9 ½”, 30 of 8 ½”, 30 of 6 ¼”, 30 of 4 ¾”
H)
Depth Capacity
:
xx,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
30.0 ft
26.0 ft
C)
D)
E)
56 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.5.3
PD-173 (ONSHORE RIG)
A)
Year Built
:
1981 (Blocks Re-built in 2006)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Gardner Denver 3000E w/ Baylor 7838 Electric Brake
Dreco 147 ft.
1,300,000 lbs. (static) with 14 lines
Varco IDS -1, 1000 HP
Gardner Denver 37 ½”
Dreco – 750 Ton
Continental Emsco LB -500
Dreco Sling Shot capacity 1,500,000 lbs.
MD Totco ,8 Pins
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x Caterpillar 399, 1300 HP ea w/ 1050 KW Generators
3 x GE 752 DC motor – 1000 HP ea.
6 x GE 752 motor – 800 HP ea.
Ind. drive, GE 752 motor – 800 HP
GE 752 Motor, 1000 HP, Torque – 34,000 ft/lbs
:
:
:
:
:
:
3 x Gardner Denver PZ -11 (1600 HP)
4000 bbl. Capacity (active and reserve),2 x 66 Bbl trip tanks
3 x Derrick Model 58 Flo-line Cleaner Plus
Harrisburg 3 x 10” cone – 600 GPM
Harrisburg 20 x 5” cone – 600 GPM
None
: Swaco 2 stage vacuum pump – 1000 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
Cad Oilfield,3000 psi, 14 stations, 40 x 10 gal bottles
4 1/16” 10000 psi w/ 2 hydraulic and one manual chokes.
2 x Cameron U 13-5/8” double ram, 10000 psi,
Hydril GL 13-5/8”, 5000 psi (H2S Trim)
Safety Equipment
:
95 Fire extinguishers, 1 Fire pump, Air cascade System, 13 x 5-min
air packs, 13 x 30-min SCBA Air Packs, Fixed gas detection system
(MSA Model 5300), Portable Gas Detection system (Bio systems),
4 x Eye Wash Stations, 1 x Emergency Shower, 5 x Wind Socks, 2 x
C)
D)
E)
F)
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
Sate Proving Areas
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill Collars
:
:
:
5 ½” Grade G, 24.7 ppf, 11,500 ft.
5” Grade G, 19.5 ppf, 18,200 ft
3 ½” Grade-G, 13.3 lbs./ft, 6200 ft.
38 x 6 5/8”, 53 x 5 ½”, 53 x 5”
16 of 10”, 22 of 8 ½”, 10 of 6 ¼”.”
H)
Depth Capacity
:
25,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
38.0 ft
35.35 ft
57 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.5.4
PD-174 (ONSHORE RIG)
A)
Year Built
:
1981
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Emsco C-3 (3000 HP) with Elmagco 7838W auxiliary brake
Pyramid 152 ft
1,300,000 lbs. (static) with 14 lines
Varco IDS 1 – 500 Ton
National Oilwell A-375 (37 ½”) – 500 Ton
Emsco RA-60-6 (1,300,000 lbs) with BJ 5500 Dynaplex Hook
Integrated with top drive
Dreco Raised Floor, casing 1,000,000 lbs, set back 800,000 lbs
M.D, 8-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x Caterpillar D399, 1200 HP ea. w/ 1000 KW Generator
2 x GE 752 DC motor – 1000 HP ea.
6 x GE 752 – 1000 HP ea.
Ind. Dr, GE 752 motor 1000 HP, Torque 1050 Amps / 54,000 ft.-lbs
GE 752 – 1000 HP, Torque 1050 Amps / 54,000 ft.-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
3 x Emsco F-1600 (1600 HP)
4000 bbl. Capacity (active and reserve) with 67/52 bbl. trip tank
3 x Derrick 58 and 2 x Harrisburg Mud Cleaners
Harrisburg 4 cone – 1600 GPM
Harrisburg 20 x 4” cone – 1600 GPM
None
One Atmospheric, One Double Life Vacuum – 1600 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, Koomy 550 USG Type 80
4 1/16” 10000 psi w/ 2 x hydraulic chokes and one mannual
2 x Cameron U 13-5/8” double ram, 10000 psi, H2S trimmed.
Hydril GL 13-5/8” x 5000 psi
F)
Safety Equipment
:
100 Fire extinguishers, 1 Fire pump, Air cascade system, 12
Breathing 5 min apparatus, 19 SCBA 30 min Breathing Apparatus,
Fixed gas detection system, Portable gas detection Equipment,
5 eye wash stations, 1 emergency shower, 5 x wind socks
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
5 ½” Grade XD-105, 27.06 ppf, 15,000 ft.
5 ½” Grade S-135, 27.53 ppf, 6,900 ft
4” Grade G-105, 14.0 ppf, 10,235 ft.
27 x 6 5/8”, 50 x 5 ½”, 100 x 4”
9 of 10”, 30 of 8-1/2”, 30 of 6-1/4”, 30 of 4-3/4”
H)
Depth Capacity
:
25,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
35.0 ft
29.0 ft
C)
D)
E)
58 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.5.5
PD-786 (ONSHORE RIG)
A)
Year Built
:
2001
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Oilwell E-2000 (2000 HP) with Elmagco 7838W auxiliary brake
Pyramid 162 ft
1,275,000 lbs. (static) with 14 lines
Varco TDS 11SA
C. Emsco T-3750 (37 ½”) – 650 Ton
Oilwell A500 with BJ 5500 Dynaplex Hook
Integrated with top drive
Pyramid Swing Up, casing 1,275,000 lbs, set back 750,000 lbs
M.D / Totco 8-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar D3516, 1855 HP ea. w/ 1322 KW Generator
2 x GE 752 DC motor – 1000 HP ea.
2 x GE 752 – 1000 HP ea.
Chain Drive with Drawworks
2 x AC Motor, 400 HP ea.
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
3 x Oilwell A-1700-PT (1700 HP)
4400 bbl. Capacity (active and reserve) with 57/65 bbl. trip tanks
3 x Brandt King Cobra
Brandt 2 x 12” cone – 1000 GPM
Brandt 16 x 4” cone – 1000 GPM
None
One Atmospheric, One Double Life Vacuum
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, Koomey 550 USG w/ 50 x 11 gal. bottles
4 1/16” 10000 psi w/ 2 x hydraulic and one mannual chokes
2 x Cameron U 13-5/8” double ram, 10000 psi, H2S trimmed
Hydril GL 13-5/8” x 5000 psi
F)
Safety Equipment
:
36 Fire extinguishers, 1 Fire pump, 2 x Air cascade system, 15
Breathing apparatus, 4 station Fixed gas detection system, 2 set
Portable gas detection Equipment, 6 eye wash stations, 3
emergency shower, 4 x wind socks
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
:
5 ½” Grade G, 24.7 lbs./ft, 12,000 ft.
5” Grade G, 19.5 lbs/ft, 15000 ft
3-1/2” Grade G, 13.3 lbs./ft, 9,000 ft.
15 x 6 5/8”, 30 x 5 ½”, 50 x 5”, 50 of 3-1/2”
18 of 9-1/2”, 30 of 8-1/2”, 30 of 6-1/4”, 30 of 4-3/4”
H)
Depth Capacity
:
19,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
35.5 ft
29.25 ft
C)
D)
E)
59 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.5.6
PD-787 (ONSHORE RIG)
A)
Year Built
:
1978 (New Derrick and Substructure: 2001)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National 1320-UE (2000 HP) with Elmagco 7838 Auxiliary Brake
Pyramid 30 x 162 ft.
1,275,000 lbs (static) w/ 14 lines, 900,000 lbs. (static) w/ 12 lines
Varco TDS-11SA – 500 Ton
Oilwell BC37 ½” – 650 Ton
BJ 5500 Dynaplex Hook – 500 Ton
Integrated with top drive
Pyramid, casing 800,000 lbs, set back 880,000 lbs.
M.D. / Totco, 8-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar D3516, 1855 HP ea. w/ 1322 KW Generator
2 x GE 752 DC motor – 1000 HP ea.
6 x GE 752 DC motors – 1000 HP ea.
Drive Not Installed
2 x AC motors – 400 HP ea. Torque 37,000 ft-lbs.
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
3 x Oilwell A-1700-PT – 1600 HP ea.
4000 bbl. capacity with 2000 bbl. active and 2 x 60 bbl. trip tanks.
3 x Brandt King Cobra shakers, 2 x Brandt KC Cleaner – 2000 GPM
Brandt 2 x 12” cone – 1000 GPM
Brandt 16 x 4” cone – 1000 GPM
None
DL Closed Bottom, 36” OD, 8” Outlet – 700 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, Koomey 550USG, 14 stations
4-1/16” ECC, 10,000 psi w/ 2 x hydraulic and one manual chokes
Hydril GL 13-5/8” annular 5000 psi, 2 x Cameron U 13-5/8” double
ram, 10000 psi, H2S trimmed
F)
Safety Equipment
:
100 Fire extinguishers, 1 Fire pump, Air cascade system, 12 x 5-min.
Breathing Apparatus, 19 x 30-min. SCBA, Fixed gas detection
system, Portable gas detection equipment, 5 eye wash stations, 2
emergency shower, 4 wind socks
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
5.5” Grade XT-105 24.7 ppf, 15,000 ft, 5.5” Grade S-105 24.7 ppf,
7,000 ft, 4” Grade XT-105 14.0 ppf, 7,000 ft.
115 of 5”
11 of 10”, 19 of 8-1/4”, 28 of 6 -1/2”
H)
Depth Capacity
:
20,000 ft. with 5” drillpipe
I)
DF – GL Elevation
Clearance below DF
:
:
35.0 ft
30.0 ft
C)
D)
E)
60 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.6.1
SAR-102 (ONSHORE RIG)
A)
Year Built
:
1991 (Out of Service from Dec. 1998 to Aug. 2005)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Skytop Brewster H1-4610B1-38, 500 HP with auxiliary brake
Skytop Brewster, 110 ft.
275,000 lbs with 8 lines
None
Skytop Brewster RSB-275, 27 ½” – 500 Ton
BJ HB-154 – 150 Ton
Oilwell – 225 Ton
Skytop Brewster, Load capacity 290,000 lbs setback
None
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
2 x Caterpillar D379, 600 HP ea. w/ 460KW Generators
Detroit Diesel 12A-90748 – 575 HP
2 x Caterpillar D398 – 1100 HP ea.
Load capacity 500 Ton, 350 RPM
None
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x Garden Denver PZ-8, Triplex – 1100 HP ea
1015 bbl. Capacity (active and reserve) 60 bbl trip tank
1x Derrick Flo-Line Cleaner
Brandt 2 x 12” cone – 1000 GPM
None
None
Poor-boy, 24” OD, 3” Outlet – 800 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, Cameron 8 station, 40 bottles
2 1/16” 5000 psi H2S trimmed
Shaffer 11” Annular 5000 psi, 1 x Shaffer 11” double ram, 5000 psi,
1 x Shaffer single ram 5000 psi, All H2S trimmed
F)
Safety Equipment
:
44 Fire extinguishers, 1 Fire pump, 1 x Air Cascade system, 27 x
30-min. SCBA, 10 x 5-min. SCBA, 1 x 5-station gas detector, 4 x
H2S detectors, 2 x portable gas detectors, ,3 x wind socks, 2 x
shower stations, 3 x eye wash stations, 1 x Breathing Air
compressor
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
3 ½” Grade G, 13.3 ppf, 7,500 ft.
2 3/8”” Grade G, 6.7 ppf, 6,500 ft.
10 of 3-1/2”
22 of 4 ¾”, 18 of 3 3/8”
H)
Depth Capacity
:
7,000 ft with 3 ½” drillpipe
I)
DF – GL Elevation
Clearance below DF
:
:
15.0 ft
12.5 ft
C)
D)
E)
61 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.6.2
SAR-103 (ONSHORE RIG)
A)
Year Built
:
1993
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Skytop Brewster 950 HP with auxiliary brake
Skytop Brewster 25 x 115 ft.
275,000 lbs with 10 lines
None
Skytop Brewster RSB-375, 37 ½”
Web Wilson 250 Ton
Oilwell 225 Ton
Skytop Brewster, Load capacity 290,000 lbs setback
Totco, 6 pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
2 x Caterpillar D379 – 600 HP ea. w/ xxxx KW Generator
2 x Caterpillar 3408 – 450 HP ea.
2 x Caterpillar 398 – 1100 HP ea.
xxxxxxx 1000 HP, Torque xxx Amps / 410,000 ft.-lbs
N/A
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x Garden Denver PZ-8, Triplex – 750 HP ea
820 bbl. Capacity (active and reserve) 35 bbl trip tank
1x Derrick Flo-Line Cleaner (Tandem unit)
None
None
Mission Magnum 6” x 8” – 75 HP
None
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, Cameron 7 stations
2 1/16” 5000 psi H2S trimmed
Shaffer 11” Annular 5000 psi, 1 x Shaffer 11” double ram, 5000 psi,
All H2S trimmed
F)
Safety Equipment
:
44 Fire extinguishers, 1 Fire pump, 1 x Air Cascade system, 27 x
30-min. SCBA, 10 x 5-min. SCBA, 1 x 5-station gas detector, 4 x
H2S detectors, 2 x portable gas detectors, ,3 x wind socks, 2 x
shower stations, 3 x eye wash stations, 1 x Breathing Air
compressor. H2S LEL 5-channel fixed combustible gas detection
system
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
3 ½” Grade G, 13.3 lbs/ft, 9000 ft.
2 3/8”” Grade G, 6.65 lbs./ft, 600 ft.
2 of 3 ½”
15 of 4 ¾”, 20 of 3 3/8”
H)
Depth Capacity
:
10,000 ft with 3 ½” drillpipe
I)
DF – GL Elevation
Clearance below DF
:
:
18.0 ft
13.5 ft
C)
D)
E)
62 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.6.3
SAR-151 (ONSHORE RIG)
A)
Year Built
:
1975 (Refurbished 1996
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Midcontinental U712-EA – 1200 HP with Elmagco auxiliary brake
Lee C. Moore 25 x 115 ft.
550,000 lbs with 8 lines
None
National C-375, 37 ½”
Ideco – 350 Ton
National P-4000 – 400 Ton
Aramco made, Load capacity, setback 290,000 lbs.
MD / Totco 6-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
Type of engines? 1500 HP ea. w/ 1000 KW Generators
2 x GE 752 DC motor – 1000 HP ea.
2 x GE 752 DC motors – 1000 HP ea.
Ind. Dr, GE 752 motor 1000 HP, Torque 800 Amps
None
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x Oilwell A-1700 PT, Triplex – 1700 HP ea
1335 bbl. Capacity (active and reserve) 70 bbl trip tank
2 x Derrick Flo-Line Cleaner
Brandt double 2 x 12” cone – 1000 GPM
Brandt double 2 x 12” cone – 1000 GPM
None
None
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, Cameron 8 station
3 1/8” 5000 psi WP, H2S trimmed
Shaffer 13 5/8” Annular 3000 psi, Shaffer 13 5/8” double ram,
5000 psi, Shaffer 11” Annular 3000 psi, All H2S trimmed
F)
Safety Equipment
:
40 Fire extinguishers, 1 Fire pump, 1 x Air Cascade system, 30 x
30-min. SCBA, 11 x 5-min. SCBA, 5-station gas detector, 4 x H2S
detectors, 2 x portable gas detectors, ,3 x wind socks, 2 x shower
stations, 3 x eye wash stations, Breathing Air compressor. H2S
Light & siren 5-channel fixed combustible gas detection system
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
5” Grade G, 19.5 ppf, 6,900 ft.
3 ½” Grade G, 13.3 ppf, 7,200 ft.
25 of 5”, 12 of 3 ½”
3 of 10”, 18 of 8”, 23 of 6 ¼”, 24 of 4 ¾”
H)
Depth Capacity
:
12,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
16.3 ft
13.0 ft
C)
D)
E)
63 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.6.4
SAR-153 (ONSHORE RIG)
A)
Year Built
:
1993 (Completely Refurbished in 1998)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National 110 UE – 1500 HP with auxiliary brake
Pyramid 25 x 147 ft.
750,000 lbs with 12 line.
National PS350/500 – 250 Ton
National A or B 375, 37 ½”
Make & model? 350 Ton
Make and model? 400 Ton
Pyramid, specify type?, Load setback 290,000lbs lbs.
Totco 6-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar D3512 – 1321 HP ea. w/ xxxx KW Generator
2 x GE 752 DC motor – 750 HP ea.
2 x GE 752 DC motors – 1300 HP ea.
Ind. drive, GE 752 motor 1365 HP, Torque xxx Amps / xxxxx ft.-lbs
2 x AC motors, 350 HP ea. Torque xxx Amps / xxxxx ft.-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x National 10P-130, Triplex – 1300 HP ea
1500 bbl. Capacity (active and reserve) 60 bbl trip tank
2 x Derrick Flo-Line Cleaner
Derrick x” x 3 cone – 500 GPM
Derrick x” x 15 cone – 500 GPM
None
Derrick Vacu-Flow – 1000 GMP, Poor Boy 24” dia – xxx GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, Stewart & Stevenson x station (Check?)
3 1/8” 5000 psi WP, Cameron H2S trimmed
Hydril 13 5/8” Annular 3000 psi, 1 x Cameron 13 5/8” double ram,
3000 psi, All H2S trimmed
F)
Safety Equipment
:
40 Fire extinguishers, 1 Fire pump, 1 x Air Cascade system, 25 x
30-min. SCBA, 11 x 5-min. SCBA, 1 x 5-station gas detector, 4 x
H2S detectors, 2 x portable gas detectors, ,3 x wind socks, 2 x
shower stations, 3 x eye wash stations, 1 x Breathing Air
compressor. H2S Light & siren 5-channel fixed combustible gas
detection system
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
5” Grade E, 19.5 lbs/ft, xxxxx ft.
3 ½” Grade G, 13.3 lbs./ft, xxxxx ft.
xx of 5”, xx of 3 ½”
xx of 8”, xx of 6 ¼”, xx of 4 ¾”
H)
Depth Capacity
:
16,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
30.0 ft
24.6 ft
C)
D)
E)
64 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.7.1
SINO-1 (ONSHORE RIG)
A)
Year Built
:
1999 (Upgraded to 1500 HP in 2002)
B)
Rig Equipment
1. Drawworks
2.
Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
3H, JC50D – 1500 HP with DS-50 CURRUNT Brake
Lanzho Pet. & Chem. Mach. Factory, LL315/45K, 26’ x 147 ft.
770,000 lbs with 10 lines
Varco TDS 11SA – 350 Ton
LPMP, ZP-375, 37 ½” – 600 Ton
LPMP, TC350 (Hook/Block Combination) – 350 Tons
LPMP, SL450 – 300 Ton
3H, Pyramid slingshot type, casing 500,000 lbs, setback 350,000 lbs.
TDS-2000 Petron, 6-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar 3512, 1381 HP ea. with 1400 KW generators
2 x GE 752 motor, 1500 HP ea.
4 x GE 752 motor, 1000 HP ea.
YJ23A motor – 800 HP, Torque 24,000 ft-lbs
2 x AC motor – 400 HP ea., Torque, 30,000 ft-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x BPMP F-1300 – 1300 HP ea.
2000 bbl. capacity, 60 bbl trip tank
2 x Derrick Flo-line cleaner
Derrick 2 x 12” – 800 GPM
Derrick 16 x 2” – 800 GPM
None
ZDRI, ZCQ/4– 800 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, CAP Specialties Inc., SB330-15SB3K-14 stations
3-1/8”, 3H, 3000 psi WP, JLGH 3000 psi, sour service
Cameron 13 5/8” annular 3000 psi
Cameron U 13 5/8” double ram, 3000 psi
Cameron U 13-5/8” single ram, 3000 psi
All H2S trimmed
:
60 Fire extinguishers, 1 fire pump, 2 gas detector, 4 H2S Detector,
Cascade system, 14 x SCBAs, 2 Portable gas Monitors, 3 eye
wash stations, 2 showers, 4 wind socks, 1 breathable
air compressor
HWDP
Drill collars
:
:
:
:
5” Grade G-105, 19.5 ppf, 5000 ft.
4”.Grade CY-105, 15.67 ppf, 15000 ft.
20 of 5”
15 of 8 ¼”, 30 of 6 ¼”, 30 of 4 ¾”
H)
Depth Capacity
:
8,000 feet
I)
DF – GL Elevation
Clearance below DF
:
:
29.6 ft.
25.0 ft.
C)
D)
E)
F)
G)
Safety Equipment
Drill Pipe & Drill Collars
1. Drill Pipe
2.
3.
65 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.7.2
SINO-2 (ONSHORE RIG)
A)
Year Built
:
2003
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
NanYang Pet. Machinery, JC30/11700CZ (737HP)
NYPM, JJ-18938, 24’ x 147 ft.
405,000 lbs (static) with 10 lines
None
NYPM, ZP27-1/2”
NYPM, TC180/YG-180 – 180 Ton
NYPM, SL225 – 225 Ton
NYPM, Load casing 505,000 lbs.
VDX, 6-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
2 x Caterpillar 3408C, 530 Hp ea.
JC28/11
3 x Volvo – 530 HP ea.
Motor – 650 HP, Torque 20,300 ft-lbs.
None
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x QZ 3NB-800 – 800 HP ea.
1300 bbl.
2 x Derrick
1 x GQC250II – 800 GPM
1 x ZQJ100 – 800 GPM
1 x GLW458-842N – 200 GPM
1 x ZCQ/4 – 800 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, FKQ840-8, 224 gal.
3-1/8” San Yi Pet. Machinery, 5000 psi
Cameron Type-D 13-5/8” Annular, 3000 psi
Cameron Type-U 13-5/8” double ram, 3000 psi.
F)
Safety Equipment
:
50 Fire extinguishers, 4 H2S detectors, Cascade System, 10
SCBAs, 12SABAs, 2 portable gas / H2S monitors, 3
eye wash stations, 1 shower at mud pits, 1 Drager
H2S sniffer,1 Breathable air compressor, 2 Hydrant
G)
Drill Pipe & Drill Collars
1. Drill Pipe
HWDP
Drill collars
:
:
:
:
3-1/2” Grade E 13.3 ppf, 10,000 ft.
2-3/8” Grade E, 6.65 ppf, 8,000 ft.
None
10 of 6-1/4”, 20 of 4-3/4”, 20 of 3-3/8”
H)
Depth Capacity
:
10,000 ft. with 3-1/2” Drillpipe
I)
DF-GL Elevation
Clearance below DF
:
:
C)
D)
E)
2.
3.
66 of 102
19.5 ft
16.0 ft
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.7.3
SINO-3 (ONSHORE RIG)
A)
Year Built
:
2005
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
3H, JC40D – 1500HP with 336WCB2 Eton Brake
3H, JJ250/45K, 26 ft x 147 ft.
500,000 lbs with 10 lines
None
LPMP, ZP-275, 27 ½” – xxx Ton
LPMP, YC250 (Hook/Block Combination) – 250 Tons
LPMP, SL250 – 250 Ton
3H, Pyramid slingshot type, casing 500,000 lbs, setback 250,000 lbs.
VDX, 8-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
3 x Caterpillar 3512B, 1749 HP ea. with 1778KVA generators
2 x Make? YJ13A motor, 500 HP ea.
4 x Make? YJ13A motor, 500 HP ea.
YJ13A motor – 800 HP, Torque rating 24,000ft-lbs
None
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x BPMP F-1300 – 1300 HP ea.
1500 bbl. capacity, 70 bbl trip tank
2 x Derrick Flo-line cleaner
Derrick 2 x 12” – 800 GPM
Derrick 16 x 2” – 800 GPM
None
ZDRI, ZCQ/4 – 600 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs(CIW)
:
:
:
3000 psi WP, Beijing Pet. Machinery Plant, FKQ-800-8 stations
3-1/8”, 3H, 3000 psi WP, JLGH 3000 psi, sour service
Cameron 13 5/8” annular 3000 psi
Cameron U 13 5/8” double ram, 3000 psi
Cameron U 13-5/8” single ram, 3000 psi
All H2S trimmed
:
40 Fire extinguishers, 1 fire pump, 4 gas detector, 6 H2S Detector,
1 Cascade system, 14 x SCBAs, 2 Portable gas
Monitors, 6 eye wash stations, 2 showers, 4 wind
socks, 1 breathable air compressor
HWDP
Drill collars
:
:
:
:
:
5” Grade G-105, 19.5 ppf, 5000 ft.
3 ½”.Grade G-105, 15.5 ppf, 5000 ft.
2 3/8” Grade E, 6.6 ppf, 5000 ft.
20 of 5”
15 of 8 ¼”, 30 of 6 ¼”, 30 of 4 ¾”, 30 of 3 1/8”.
H)
Depth Capacity
:
8,000 feet
I)
DF – GL Elevation
Clearance below DF
:
:
29.6 ft.
24.0 ft.
C)
D)
E)
F)
G)
Safety Equipment
Drill Pipe & Drill Collars
1. Drill Pipe
2.
3.
67 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.7.4
SINO-5 (ONSHORE RIG)
A)
Year Built
:
2001
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Dreco D1500 AC 11 (1500 HP) with no Auxiliary Brake
Pyramid 25’ x 142 ft.
750,000 lbs. (static) with 12 lines
MH PTD-500-AC – 500 Ton
National D375, 37 ½” – 650 Ton
Dreco 650B-400 – 450 Ton (Hook/Block Combination)
SL450 – 450 Tons
Pyramid box-on-box type, casing 600,000 lbs, setback 450,000 lbs.
Martin Decker, 6 pen with Mud Watch
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
3 x Caterpillar 3512, 1750 HP ea. w/ 1150 KW generators
2 x GEB 22A1 motor – 1150 HP ea.
2 x GEB 22A1 motor – 1150 HP ea.
GEB22A1 motor – 1150 HP, Torque 24,000 ft-lbs.
Reliance motor, 400 HP, Torque 45,000ft-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x Baoji China F1600 (1600 HP ea.)
2000 bbl. capacity with 120 bbl trip tank
3 x Derrick liner motion Flo-line
Derrick 2 x 12” cone – 1200 GPM
Derrick 16 x 2” cone – 1200 GPM
None
Baoshi China ZCQ/4 – 1050 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs (CIW)
:
:
:
3000 psi WP, CAD 14 stations
3-1/16” Yan Cheng China 5000 psi WP, sour service
Cameron 13-5/8” Annular 5000 psi,
Cameron 13-5/8” double ram, 5000 psi w/SBR,
Cameron 13-5/8” single ram, 5000 psi, All H2S trimmed
Safety Equipment
:
60 Fire extinguishers, 1 fire pump, 4 gas detector, 6 H2S Detector,
cascade system, 14SCBAs, 2 Portable gas Monitors, 6
eye wash stations, 2 shower, 4 wind socks, 1
breathable air compressor
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
4” Grade-G 14.0 ppf, 16,000 ft.
3 ½” Grade-G 13.3 ppf, 5,000 ft,
2 3/8” Grade-E 6.6 ppf, 5,000 ft.
60 of 5”, 60 of 4”
30 of 6 ¼”, 30 of 4 ¾”, 30 of 2 7/8”
H)
Depth Capacity
:
18,000 ft.
I)
DF – GL Elevation
Clearance below DF
:
:
30.0 ft.
27.0 ft.
C)
D)
E)
F)
G)
68 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.7.5
SINO-6 (ONSHORE RIG)
A)
Year Built
:
2001
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Dreco D1500 AC 11 (1500 HP) with no Auxiliary Brake
Pyramid 25’ x 142 ft.
750,000 lbs. (static) with 12 lines
MH PTD-500-AC – 500 Ton
National D375, 37 ½” – 650 Ton
Dreco 650B-400 – 450 Ton (Hook/Block Combination)
SL450 – 450 Tons
Pyramid box-on-box type, casing 600,000 lbs, setback 450,000 lbs.
Martin Decker, 6 pen with Mud Watch
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
3 x Caterpillar 3512, 1750 HP ea. w/ 1150 KW generators
2 x GEB 22A1 motor – 1150 HP ea.
2 x GEB 22A1 motor – 1150 HP ea.
GEB22A1 motor – 1150 HP, Torque 24,000 ft-lbs.
Reliance motor, 400 HP, Torque 45,000ft-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x Baoji China F1600 (1600 HP ea.)
2000 bbl. capacity with 120 bbl trip tank
3 x Derrick liner motion Flo-line
Derrick 2 x 12” cone – 1200 GPM
Derrick 16 x 2” cone – 1200 GPM
None
Baoshi China ZCQ/4 – 1050 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs (CIW)
:
:
:
3000 psi WP, CAD 14 stations
3-1/16” Yan Cheng China 5000 psi WP, sour service
Cameron 13-5/8” Annular 5000 psi,
Cameron 13-5/8” double ram, 5000 psi w/SBR,
Cameron 13-5/8” single ram, 5000 psi, All H2S trimmed
Safety Equipment
:
60 Fire extinguishers, 1 fire pump, 4 gas detector, 6 H2S Detector,
cascade system, 14SCBAs, 2 Portable gas Monitors, 6
eye wash stations, 2 shower, 4 wind socks, 1
breathable air compressor
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
4” Grade-G 14.0 ppf, 16,000 ft.
3 ½” Grade-G 13.3 ppf, 5,000 ft,
2 3/8” Grade-E 6.6 ppf, 5,000 ft.
60 of 5”, 60 of 4”
30 of 6 ¼”, 30 of 4 ¾”, 30 of 2 7/8”
H)
Depth Capacity
:
18,000 ft.
I)
DF – GL Elevation
Clearance below DF
:
:
30.0 ft.
27.0 ft.
C)
D)
E)
F)
G)
69 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.7.6
SINO-7 (ONSHORE RIG)
A)
Year Built
:
2001
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Nan yang Pet. Machinery with Pneumatic Auxiliary Brake
NPMC, 20’ x 147 ft.
396,000 lbs (static) with 10 lines.
None
Lan Zhou Pet. Machinery, ZP-275, 27 ½”
YG-180 – 180 Ton
Lan Zhou Pet. Machinery, SL225 – 225 Ton
Nan yang Pet. Machinery, Slingshot. setback 200,000 lbs.
M.D., 8-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
2 x CAT 3408C DITA – 475 HP ea. w/ 343 KW generators
2 x CAT 3408C DITA – 475 HP ea.
2 x CAT 3412EC DITA – 800 HP ea
Nanyang Pet .Machinery – 700 HP, Torque 20,267 ft-lbs.
None.
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x Oilwell F-800 (800 HP ea.)
1500 bbl. capacity with 60 bbl trip tanks
2 x Kemtron Liner Motion Flo-Line
None
None
None
Drilling Research Institute, ZCQ/4 – 800 GPM
:
:
3000 psi WP, FKQ-800 with 8 stations
2 9/16” Yan Cheng San YIPEC Machinery, 3000 psi WP, sour
:
Shaffer 13 5/8” Annular 3000 psi,
Shaffer 13 5/8” double ram, 3000 psi with SBR,
Shaffer 11” single ram 3000 psi,
Shaffer 11” double ram 3000 psi w/ blind rams,
Shaffer 11” Annular 3000 psi, All H2S trimmed
:
40 Fire extinguishers, 1 fire pump, 4 gas detector, 6 H2S Detector,
1 cascade system, 14SCBAs, 2 Portable gas Monitors, 6 eye wash
stations, 2 shower, 4 wind socks, 1 breathable air compressor.
HWDP
Drill collars
:
:
:
:
3 ½” Grade-E, 13.3 ppf, 10,000 ft.
2 3/8” Grade-E, 6.6 ppf, 10,000 ft.
None
10 x 6 ¼”, 20 x 4 ¾”, 20 of 3 3/8”
H)
Depth Capacity
:
10,000 feet
I)
DF – GL Elevation
Clearance below DF
:
:
20.0 ft.
16.0 ft.
C)
D)
E)
BOP Equipment
1. Accumulator
2. Choke manifold
service
3. BOPs
F)
Safety Equipment
G)
Drill Pipe & Drill Collars
1. Drill Pipe
2.
3.
70 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.7.7
SINO-9 (ONSHORE RIG)
A)
Year Built
:
2005
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
ZJ50, Model3150D, 2180 HP with Eton WCBD336 Auxiliary Brake
3H, JJ315/45 –K3
700,000 lbs with 12 lines
BPM DQ70BSC – 450 Ton
LPMP, ZP-375, 37 ½” – 585Ton
LPMP, TC350 (Hook/Block Combination) – 350 Tons
LPMP, SL450 – 450 Ton
3H, Pyramid slingshot type, casing 700,000 lbs, setback 400,000 lbs.
VDX, 8-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
3 x Caterpillar 3512 – 1820 HP ea.
2 x GE 752 motor, 1000 HP ea.
4 x GE 752 motor, 1000 HP ea.
YZ08B motor – 800 HP, Torque 1150 Amps, 24,000 ft-lbs
2 x AC motor – 800 HP, Torque 36,000 ft-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x BPMP F-1600 – 1600 HP ea.
2000 bbl. capacity, 60 bbl trip tank
3 x Derrick Flo-line cleaner
Centrifugal 6 x 8” – 1600 GPM
Centrifugal 6 x 8” – 1600 GPM
None
ZDRI, ZCQ/4 – 880 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs(CIW)
:
:
:
3000 psi WP, Beijing Pet. Machinery Plant, FKQ1440-14stations
3-1/8”, 3H, 5000 psi WP, JLGH 5000 psi, sour service
Cameron 13 5/8” annular 3000 psi
Cameron U 13 5/8” double ram, 3000 psi
Cameron U 13-5/8” single ram, 3000 psi
All H2S trimmed
:
60 Fire extinguishers, 1 fire pump, 4 gas detector, 6 H2S Detector,
Cascade system, 14 x SCBAs, 2 Portable gas Monitors, 6 eye
wash stations, 2 showers, 4 wind socks, 1 breathable
air compressor
HWDP
Drill Collars
:
:
:
:
5” Grade G-105, 19.5 ppf, 5000 ft.
4”.Grade G-105, 15.9 ppf, 5000 ft.
20 of 5”, 60 of 4”
9 of 9-1/2”,16 of 8 ¼”, 25 of 6 ¼”, 20 of 4 ¾”,.
H)
Depth Capacity
:
18,000 feet
I)
DF – GL Elevation
Clearance below DF
:
:
29.6 ft.
25.43ft.
C)
D)
E)
F)
G)
Safety Equipment
Drill Pipe & Drill Collars
1. Drill Pipe
2.
3.
71 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.7.9
SINO-10 (ONSHORE RIG)
A)
Year Built
:
2006
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
3H, JC70D, 2000HP with 336WCB2 Eton Brake
3H, JJ450, 26 ft x 147 ft.
1,000,000 lbs (static) with 10 lines
Varco, TDS-11SA – 500 Ton
LPMP, ZP-375, 37 ½” – 500 Ton
LPMP, YC450 (Hook/Block Combination) – 450 Tons
LPMP, SL450 – 450 Ton
3H, Pyramid slingshot type, casing 700,000 lbs, setback 350,000 lbs
VDX, 8-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar 3512B, 1747 HP ea. w/ KATO 1778KW generators
2 x YZ08 motor, 1000 HP ea.
4 x YZ08 motor, 1000 HP ea.
YZ08 motor – 100 HP, Torque 000000 Amps, 24,000 ft-lbs
Make & Model? motor, 800 HP, Torque 000000 Amps, 00000 ft-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x Make? 3NB100 – 1600 HP ea.
2000 bbl. capacity, 2 x 60 bbl trip tanks
3 x Derrick Liner Motion Flo-line
Centrifugal 6” x 8” – 1600 GPM
Centrifugal 6” x 8” – 850 GPM
None
ZDRI, ZCQ/4 – 880 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, Beijing Pet. Machinery Plant, FKQ-1440-14 stations
3-1/8”, 3H, 5000 psi WP, JLGH 5000 psi, sour service
Cameron 21 ¼” annular 2000 psi, Cameron 13 5/8” annular 5000
psi, Cameron U 13 5/8” double ram, 5000 psi, Cameron U 13-5/8”
single ram, 5000 psi All H2S trimmed
:
40 Fire extinguishers, 1 fire pump, 4 gas detector, 6 H2S Detector,
1 Cascade system, 14 x SCBAs, 2 Portable gas
Monitors, 6 eye wash stations, 2 showers, 4 wind
socks, 1 breathable air compressor
HWDP
Drill collars
:
:
:
:
:
5” Grade-G, 19.5 ppf, 10,000 ft.
4”.Grade-G, 14.0 ppf, 18,000 ft.
2 3/8” Grade-E, 6.6 ppf, 5000 ft.
80 of 5”, 100 of 4”
12 of 9 ½”, 30 of 8 ¼”, 30 of 6 ½”, 30 of 4 ¾”, 30 of 2 7/8”.
H)
Depth Capacity
:
18,000 ft.
I)
DF – GL Elevation
Clearance below DF
:
:
30.0 ft.
25.0 ft.
C)
D)
E)
F)
G)
Safety Equipment
Drill Pipe & Drill Collars
1. Drill Pipe
2.
3.
72 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.7.9
SINO-12 (ONSHORE RIG)
A)
Year Built
:
2006
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
3H, JC50DB, 1500HP with 336WCB2 Eton Brake
3H, JJ450, 26 ft x 148 ft.
750,000 lbs (static) with 10 lines
Varco, PTD-500-AC – 500 Ton
LPMP, ZP-375, 37 ½” – 500 Ton
LPMP, YC350 (Hook/Block Combination) – 350 Tons
LPMP, SL450 – 450 Ton
3H, Pyramid slingshot type, casing 700,000 lbs, setback 350,000 lbs
VDX, 8-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
3 x Caterpillar 3512B, 1600 HP ea. w/ KATO 1778KW generators
2 x YJ31 motor, 1000 HP ea.
4 x YJ31 motor, 1000 HP ea.
YJ31 motor – 750 HP, Torque 000000 Amps, 24,000 ft-lbs
MH, AC motor, 800 HP, Torque 000000 Amps, 00000 ft-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x National F1600 – 1600 HP ea.
2000 bbl. capacity, 2 x 60 bbl trip tanks
3 x Derrick Liner Motion Flo-line
Centrifugal 6” x 8” – 1600 GPM
Centrifugal 6” x 8” – 850 GPM
None
ZDRI, ZCQ/4 – 880 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, Beijing Pet. Machinery Plant, FKQ-1440-14 stations
3-1/8”, 3H, 5000 psi WP, JLGH 5000 psi, sour service
Cameron 21 ¼” annular 2000 psi, Cameron 13 5/8” annular 5000
psi, Cameron U 13 5/8” double ram, 5000 psi, Cameron U 13-5/8”
single ram, 5000 psi All H2S trimmed
:
40 Fire extinguishers, 1 fire pump, 4 gas detector, 6 H2S Detector,
1 Cascade system, 14 x SCBAs, 2 Portable gas
Monitors, 6 eye wash stations, 2 showers, 4 wind
socks, 1 breathable air compressor
HWDP
Drill collars
:
:
:
:
:
5” Grade-G, 19.5 ppf, 10,000 ft.
4”.Grade-G, 14.0 ppf, 18,000 ft.
2 3/8” Grade-E, 6.6 ppf, 5000 ft.
80 of 5”, 100 of 4”
12 of 9 ½”, 30 of 8 ¼”, 30 of 6 ½”, 30 of 4 ¾”, 30 of 2 7/8”.
H)
Depth Capacity
:
8,000 ft.
I)
DF – GL Elevation
Clearance below DF
:
:
30.0 ft.
25.0 ft.
C)
D)
E)
F)
G)
Safety Equipment
Drill Pipe & Drill Collars
1. Drill Pipe
2.
3.
73 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.7.10
SINO-18 (ONSHORE RIG)
A)
Year Built
:
2006
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
3H, JC70D, 2000HP with 336WCB2 Eton Brake
3H, JJ450, 30 ft x 148 ft.
1,000,000 lbs (static) with 10 lines
Varco, PTD-500-AC – 500 Ton
LPMP, ZP-375, 37 ½” – 500 Ton
LPMP, YC450 (Hook/Block Combination) – 450 Tons
LPMP, SL450 – 450 Ton
3H, Pyramid slingshot type, casing 700,000 lbs, setback 350,000 lbs
VDX, 8-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar 3512B, 1749 HP ea. w/ KATO 1778KW generators
2 x YJ13A motor, 800 HP ea.
4 x YJ13A motor, 800 HP ea.
YJ13A motor – 800 HP, Torque rating 24,000ft-lbs
MH, AC motor, 800 HP, Torque rating 30,000ft-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x 3NB-1300 – 1300 HP ea.
2000 bbl. capacity, 2 x 60 bbl trip tanks
3 x Derrick Liner Motion Flo-line
Centrifugal 6” x 8” – 1600 GPM
Centrifugal 6” x 8” – 850 GPM
None
ZDRI, ZCQ/4 – 880 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, Beijing Pet. Machinery Plant, FKQ-1440-14 stations
3-1/8”, 3H, 5000 psi WP, JLGH 5000 psi, sour service
Cameron 21 ¼” annular 2000 psi, Cameron 13 5/8” annular 5000
psi, Cameron U 13 5/8” double ram, 5000 psi, Cameron U 13-5/8”
single ram, 5000 psi All H2S trimmed
:
40 Fire extinguishers, 1 fire pump, 4 gas detector, 6 H2S Detector,
1 Cascade system, 14 x SCBAs, 2 Portable gas
Monitors, 6 eye wash stations, 2 showers, 4 wind
socks, 1 breathable air compressor
HWDP
Drill collars
:
:
:
:
:
5” Grade-G, 19.5 ppf, 10,000 ft.
4”.Grade-G, 14.0 ppf, 18,000 ft.
2 3/8” Grade-E, 6.6 ppf, 5000 ft.
80 of 5”, 100 of 4”
12 of 9 ½”, 30 of 8 ¼”, 30 of 6 ½”, 30 of 4 ¾”, 30 of 2 7/8”.
H)
Depth Capacity
:
18,000 feet
I)
DF – GL Elevation
Clearance below DF
:
:
30.0 ft.
25.0 ft.
C)
D)
E)
F)
G)
Safety Equipment
Drill Pipe & Drill Collars
1. Drill Pipe
2.
3.
74 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.8.1
SP-101 (ONSHORE RIG)
A)
Year Built
:
2006
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
3H, JC70D, 2000HP with 336WCB2 Eton Brake
3H, JJ450, 30 ft x 148 ft.
1,000,000 lbs (static) with 10 lines
Varco, PTD-500-AC – 500 Ton
LPMP, ZP-375, 37 ½” – 500 Ton
LPMP, YC450 (Hook/Block Combination) – 450 Tons
LPMP, SL450 – 450 Ton
3H, Pyramid slingshot type, casing 700,000 lbs, setback 350,000 lbs
VDX, 8-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar 3512B, 1749 HP ea. w/ KATO 1778KW generators
2 x YJ13A motor, 800 HP ea.
4 x YJ13A motor, 800 HP ea.
YJ13A motor – 800 HP, Torque rating 24,000ft-lbs
MH, AC motor, 800 HP, Torque rating 30,000ft-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x 3NB-1300 – 1300 HP ea.
2000 bbl. capacity, 2 x 60 bbl trip tanks
3 x Derrick Liner Motion Flo-line
Centrifugal 6” x 8” – 1600 GPM
Centrifugal 6” x 8” – 850 GPM
None
ZDRI, ZCQ/4 – 880 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, Beijing Pet. Machinery Plant, FKQ-1440-14 stations
3-1/8”, 3H, 5000 psi WP, JLGH 5000 psi, sour service
Cameron 21 ¼” annular 2000 psi, Cameron 13 5/8” annular 5000
psi, Cameron U 13 5/8” double ram, 5000 psi, Cameron U 13-5/8”
single ram, 5000 psi All H2S trimmed
:
40 Fire extinguishers, 1 fire pump, 4 gas detector, 6 H2S Detector,
1 Cascade system, 14 x SCBAs, 2 Portable gas
Monitors, 6 eye wash stations, 2 showers, 4 wind
socks, 1 breathable air compressor
HWDP
Drill collars
:
:
:
:
:
5” Grade-G, 19.5 ppf, 10,000 ft.
4”.Grade-G, 14.0 ppf, 18,000 ft.
2 3/8” Grade-E, 6.6 ppf, 5000 ft.
80 of 5”, 100 of 4”
12 of 9 ½”, 30 of 8 ¼”, 30 of 6 ½”, 30 of 4 ¾”, 30 of 2 7/8”.
H)
Depth Capacity
:
18,000 ft.
I)
DF – GL Elevation
Clearance below DF
:
:
30.0 ft.
25.0 ft.
C)
D)
E)
F)
G)
Safety Equipment
Drill Pipe & Drill Collars
1. Drill Pipe
2.
3.
75 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.9.1
SSA-29 (ONSHORE RIG)
A)
Year Built
:
1980 (Sub Structure base cross members reinforced 2003)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National 110-UE (1500 HP) w/ Elmagco 7838 Dynamic Brake
Massarenti / Brenham 33 ft x 144 ft.
1,000,000 lbs (static) with 12 lines
Varco-TDS9SA – 400 Ton
National C-375 (37 ½”) – 590 Ton (static)
Ideco – 525 Ton
Ideco – 500 Ton
Massarenti self erecting, Load casing 600,000 lbs.
M.D. / Totco, 8 pen and Digital Mud Watch System
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar D399, (1200 HP ea.) with Kato 900 KW Generators
2 x GE 752R motor – 1000 HP ea.
4 x GE 752R – 1000 HP ea.
Ind. Dr. GE 752 motor – 1000 HP, Torque 1050 Amps / 65,000 ft-lbs
2 x Reliance AC motor – 350 HP ea, Torque 875 Amps / 48,000 ft-lbs.
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x Ideco T1600 (1600 HP ea.)
2500 bbl. capacity with 100 bbl trip tank
2 x Derrick Flo Line Cleaner
Derrick 3 x 12” cone – 800 GPM
Derrick 16 x 2” cone – 800 GPM
None
Swaco Horizontal Vacuum – 800 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, Koomey ABB 80, w / 3 stations and 24 x 10 gal bottles.
3 1/16” ECC 5000 psi WP, sour service
Hydril 21 ¼” Annular / Diverter 2000 psi with 8” hydraulic valve,
Hydril GK 13 5/8” Annular 5000 psi, Cameron U 13 5/8” double
ram, 10,000 psi, Cameron 13 5/8” single ram 10,000 psi. All H2S
trimmed.
F)
Safety Equipment
:
Complete H2S monitoring system, 75 Fire extinguishers, 1 Fire
pump, Air Cascade System, 30 x 5-min Breathing apparatus, 10 x
30-min. Breathing Apparatus, 16 x SCBA, Fixed Gas detection
System, Portable Gas Detection Equipment, 5 eye wash stations, 1
shower at mud pits 4 wind socks.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
HWDP
Drill collars
:
:
:
:
:
5” Grade G 105, 26.5 ppf, 6,000 ft.
5” Grade G 105, 19.5 ppf, 10,000 ft
4” Grade XD, 14.0 ppf, 18,000 ft.
91 of 5”, 88 of 4”
10 of 9-1/2”, 21 of 8-1/2”, 30 of 6-1/2”, 3 of 4-3/4”
H)
Depth Capacity
:
18,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
29.65 ft
24.70 ft
C)
D)
E)
2.
3.
76 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.9.2
SSA-46 (ONSHORE RIG)
A)
Year Built
:
1980
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
Ideco E-2100 (2000 HP) w/ Elmagco 740 Dynamic Brake
Pyramid 32 ft x 142 ft.
1,000,000 lbs (static) with 12 lines
Varco-TDS – 400 Ton
Ideco LR375 (37 ½”) – 650 Ton (static)
National 660G500 – 500 Ton
Ideco TL500 – 500 Ton
Pyramid swing up, casing 1,000,000 lbs, setback 60,000 lbs.
Totco, 8 pen and MD/Totco Digital Mud Watch System
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar D399, (1000 HP ea.) with GE 1162 KVA Generators
2 x GE 752R motor – 800 HP ea.
4 x GE 752R – 800 HP ea
Ind. Dr. GE 752 motor – 800 HP, Torque xxx Amps / 17500 ft-lbs
2 x make? AC motor, 350 HP ea, Torque 875 Amps / 32500 ft-lbs.
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x Ideco T1600 (1600 HP ea.)
2500 bbl. capacity, 100 bbl trip tank
2 x Derrick-Flo Line Cleaner
Derrick 2 x 12” cone – 800 GPM
Derrick 16 x 2” cone – 800 GPM
None
Burgess Magna Vac – 1000 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, CAD, w/ 14 stations
3 1/16” ECC 5000 psi WP, sour service
Shaffer 21 ¼” Annular / Diverter 2000 psi w/ 8” hydraulic valve,
Shaffer 13 5/8” Annular 5000 psi, Cameron U 13 5/8” single ram,
5000 psi, Cameron 13 5/8” double ram with shear booster, 5000
psi, All H2S trimmed.
F)
Safety Equipment
:
Complete H2S monitoring system, 75 Fire extinguishers, 1 Fire
pump, Air Cascade System, 30 x 5-min Breathing apparatus, 10 x
30-min. Breathing Apparatus, 16 x SCBA, Fixed Gas detection
System, Portable Gas Detection Equipment, 5 eye wash stations, 1
shower at mud pits 4 wind socks, PLEASE CHECK ALL.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
HWDP
Drill collars
:
:
:
:
:
5 ½” Grade G, 26.5 ppf, 4,992 ft.
5” Grade G-105, 19.5 ppf, 9,734 ft
4” Grade XD, 14 ppf, 16,692 ft.
76 of 5”, 98 of 4”
11 of 9 ½”, 28 of 8 ½”, 30 of 6 ½”, 30 of 4 ¾”
H)
Depth Capacity
:
18,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
28.65 ft
23.70 ft
C)
D)
E)
2.
3.
77 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.9.3
SSA-91 (ONSHORE RIG)
A)
Year Built
:
1979
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National 110-UE (1100 HP) with Baylor Dynamic Brake
Lee C. Moore 32 ft x 142 ft.
750,000 lbs (static) with 12 lines
Varco-TDS-9S
National C-375 (37 ½”) – 500 Ton
National Dynaplex 500T – 500 Ton
National P500 – 500 Ton
Lee C. Moore
MD / Totco, 6-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar D399 – 1150 HP ea.
2 x GE 752R3A motor – 1000 HP ea.
4 x GE 752R3A – 1000 HP ea
GE 752R3A motor – 1000 HP, Torque 800 Amps / 17500 ft-lbs.
2 AC motor, 350 HP ea, Torque 875 Amps / 32,500 ft-lbs.
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x National 12-P-160 (1600 HP ea.)
2000 bbl. capacity, 100 bbl trip tank
2 x Derrick-Flo Line Cleaner
Harrisburg 2 x 12” cone – 800 GPM
Harrisburg 16 x 2” cone – 800 GPM
None
Burgess Vacuum – 800 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, ABB Type 80, TX-336-15SB
4 1/16” Cameron 5000 psi WP, sour service
Cameron U 13-5/8” double ram, 5000 psi, Cameron U 13-5/8”
single ram, 5000 psi, All H2S trimmed.
F)
Safety Equipment
:
85 Portable Fire extinguishers, 1 Fire pump, Air Cascade System,
12 x 5-min. Breathing apparatus, 14 x 30-min. SCBA, Fixed Gas
detection System, Portable Gas Detection Equipment, 6 eye wash
stations, 1 shower at mud pits 4 wind socks.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
HWDP
Drill collars
:
:
:
:
:
5” Grade-G, 19.5 ppf, 15,000 ft.
4” Grade-CY 105, 14.0 ppf, 16,000 ft
2 3/8” Grade-E, 6.65 ppf, 3,000 ft.
60 of 5”, 80 of 4”
12 of 9 ½”, 30 of 8 ½”, 30 of 6 ¼”, 30 of 4 ¾”, 15 of 3 3/8”
H)
Depth Capacity
:
18,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
29.5 ft
xx.x ft
C)
D)
E)
2.
3.
78 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.9.4
SSA-95 (ONSHORE RIG)
A)
Year Built
:
1980
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National 110-UE (2000 HP) w / Elmagco 6032 Dynamic Brake
Lee C. Moore 32 ft x 142 ft.
1,000,000 lbs (static) with 10 lines
Varco-TDS-9 – 400 Ton
National C-375 (37 ½”) – 650 Ton
National 660G500 – 500 Ton
National P500 – 500 Ton
LCM self-erect Canti, casing 1,000,000 lbs, setback 600,000 lbs.
MD Totco, 8 pen with unitized Digital Mud Watch system
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x Caterpillar D398 (1150 HP ea.) w/ KATO 1050KW Generators
2 x GE 752R motor – 1000 HP ea.
4 x GE 752R – 1000 HP ea
GE 752R motor – 1000 HP, 800 Amps / 15,777 ft-lbs.
2 x AC motor, 350 HP ea, 875 Amps / 48,000 ft-lbs.
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x IDeco T-1600 (1600 HP ea.)
2500 bbl. capacity with 100 bbl trip tank
2 x Dual Derrick-Flo Line Cleaner
Derrick 2 x 12” cone – 800 GPM
Derrick 16 x 2” cone – 800 GPM
None
Swaco Horizontal Vacuum – 800 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, ABB Type 80, TX-336-15SB w/ 14 stations
3 1/16” ECC 5000 psi WP, sour service
Shaffer SPH 13-5/8” Annular 5000 psi, Cameron U 13-5/8” single
ram, 10000 psi, Cameron U 13-5/8” double ram, 10000 psi, with
Large Bore Shear Bonnet and tandem booster, All H2S trimmed.
Shaffer 21 ¼” Annular 2000 psi Diverter w/ 8” Hydraulic valve,
F)
Safety Equipment
:
85 Portable Fire extinguishers, 1 Fire pump, Air Cascade System,
12 x 5-min. Breathing apparatus, 16 x 30-min. SCBA, Fixed Gas
detection System, Portable Gas Detection Equipment, 4 eye wash
stations, 1 shower at mud pits 4 wind socks .
G)
Drill Pipe & Drill Collars
1. Drill Pipe
HWDP
Drill collars
:
:
:
:
5” Grade-G, 19.5 ppf, 10,000 ft, 5.5” Grade-G, 25.6 ppf, 5000 ft.
4” Grade-CY 105, 14.0 ppf, 18,000 ft
100 of 5”, 100 of 4”
12 of 9 ½”, 30 of 8”, 30 of 6 ¼”, 30 of 4 ¾”
H)
Depth Capacity
:
18,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
28.75 ft.
24.50 ft.
C)
D)
E)
2.
3.
79 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.9.5
SSA 101 (ONSHORE RIG)
A)
Year Built
:
1979 (Modified mast rising sheaves 2005)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National 1320-UE (2000 HP) w/Baylor 7838 Dynamic Brake
Derrick 32 ft x 142 ft.
1,110,000 lbs (static) with 12 lines
Varco-TDS 11S – 000 Ton
National C-375 (37 ½”) – 000 Ton
National 660G500 – 500 Ton
National P500 – 500 Ton
Derrick Lo-lift Cantilever, casing xxxxxx lbs, setback xxxxxx lbs.
Totco, 8 pen and MD/Totoco Digital Mud Watch System
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x Caterpillar D398, with 5 x GE 800KW Generators
2 x GE 752 motor – 800 HP ea.
4 x GE 752 – 800 HP ea
Ind. Dr. GE 752 motor – 800 HP, Torque 800 Amps / 17500 ft-lbs
2 x AC motor, 350 HP ea, Torque 875 Amps / 32500 ft-lbs.
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x National 12-P-160 (1600 HP ea.)
2500 bbl. capacity, 100 bbl trip tank
2 x Derrick-Flo Line Cleaner
Derrick 2 x 12” cone – 800 GPM
Derrick 16 x 2” cone – 800 GPM
None
Swaco Horizontal Vacuum – 800 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, ABB Type 80, TX-336-15SB w/ xx stations
3 1/16” 10000 psi WP, sour service
Shaffer 21 ¼” Annular 2000 psi, Cameron U 13-5/8” double ram,
5000 psi, Cameron U 13-5/8” single ram, 5000 psi, Shaffer 13-5/8”
Annular 5000 psi, All H2S trimmed.
F)
Safety Equipment
:
75 Fire extinguishers, 1 Fire pump, Air Cascade System, Breathing
5 min apparatus-12, Breathing 45 min SCBA -16, Fixed Gas
detection System, Portable Gas Detection Equipment, 5 eye wash
stations, 1 shower at mud pits 4 wind socks, PLEASE CHECK
ALL.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
HWDP
Drill collars
:
:
:
:
:
5 ½”” Grade G, 26.5 lbs/ft, 6,000 ft.
5” Grade G, 19.5 lbs/ft, 10,000 ft
4” Grade XD, 14 lbs/ft, 18,000 ft.
96 of 5”, 30 of 4”
11 of 9-1/2”, 24 of 8-1/2”, 30 of 6-1/2”, 30 of 4-3/4”
H)
Depth Capacity
:
18,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
30.1 ft
23 ft
C)
D)
E)
2.
3.
80 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.9.6
SSA-102 (ONSHORE RIG)
A)
Year Built
:
1979
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National 1320-UE (2000 HP) w/ Baylor 7838 Dynamic Brake
Derrick 32 ft x 142 ft.
1,000,000 lbs (static) with 12 lines
Varco-TDS 9SA – 000 Ton
National C-375 (37 ½”) – 000 Ton
National 660G500 – 500 Ton
National P500 – 500 Ton
Derrick Lo-lift Cantilever, casing xxxxxx lbs, setback xxxxxx lbs.
Totco, 8 pen and MD/Totco Digital Mud Watch System
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x Caterpillar D398, 925 HP ea. w/ GE 800KW Generators
2 x GE 752 motor – 800 HP ea.
4 x GE 752 – 800 HP ea
GE 752R motor – 1000 HP, Torque 800 Amps / 17500 ft-lbs
2 x AC motor, 350 HP ea, Torque 875 Amps / 32500 ft-lbs.
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x National 12-P-160 (1600 HP ea.)
2600 bbl. capacity, 120 bbl trip tank
2 x Derrick-Flo Line Cleaner
Derrick 3 x 12” cone – 800 GPM
Derrick 16 x 2” cone – 800 GPM
None
Swaco Horizontal Vacuum – 1000 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, ABB Type 80, TX-336-15SB w/ xx stations
3 1/16” 10000 psi WP, sour service
Shaffer 21 ¼” Annular 2000 psi, Cameron U 13-5/8” double ram,
5000 psi, Cameron U 13-5/8” single ram, 5000 psi, Shaffer 13-5/8”
Annular 5000 psi, All H2S trimmed.
F)
Safety Equipment
:
90 Fire extinguishers, 1 Fire pump, Air Cascade System, Breathing
5 min apparatus-12, Breathing 45 min SCBA -16, Fixed Gas
detection System, Portable Gas Detection Equipment, 5 eye wash
stations, 1 shower at mud pits 4 wind socks
G)
Drill Pipe & Drill Collars
1. Drill Pipe
HWDP
Drill collars
:
:
:
:
:
5 ½”” Grade-G, 26.5 ppf, 5,000 ft.
5” Grade-G, 19.5 ppf, 10,000 ft
4” Grade-G, 14.0 ppf, 18,000 ft.
100 of 5”, 100 of 4”
12 of 9 ½”, 30 of 8 ½”, 30 of 6 ½”, 30 of 4 ¾”
H)
Depth Capacity
:
18,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
30.6 ft
23.8 ft.
C)
D)
E)
2.
3.
81 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.9.7
SSA-201 (ONSHORE RIG)
A)
Year Built
:
1980
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National 1320-UE, w/ Baylor 7838 Dynamic Brake
Pyramid 144’ x 33’
1000,000 lbs.
Varco-TDS 9S
National C-375 (37-1/2”)
National – 500 Tons (Hook/Block Combination)
National P500 – 500 Tons
Type of substructure with load capacity?
Totco, 8 pen + SWACO Monitoring system
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar D399, 1215 HP ea. w/ xxxx KW Generator
2 x GE 752 motor – 1000 HP ea
4 x GE 752 – 1000 HP ea
GE 752 motor – 1000 HP, Torque 000 Amps / xxxxx ft.-lbs
2 x AC Motor, 350 HP ea, Torque 875 Amps / 32500… ft.-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x National 12-P-160
2000 bbl. capacity, 2 x 60 bbl trip tanks
3 x Derrick-Flo Line Cleaner
Derrick 3 x 10” cones – 1000 GPM
Derrick 20 x 3” cones – xxx GPM
None
TRI-FLO 1000 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, CAD 24-15 Control System
4 1/16” 10000 psi WP, sour service
2 x Cameron U 13-5/8” double ram, 10000 psi, Hydril GK 13-5/8” x
5000 psi, Hydril MSP 21 ¼” 2000psi, Shaffer 20 ¾” 3000 psi, all
H2S trimmed.
F)
Safety Equipment
:
100 Fire extinguishers, 1 Fire pump, Air cascade system, 12
Breathing 5 min apparatus, 19 SCBA 30 min Breathing Apparatus,
Fixed gas detection system, Portable gas detection equipment,
5 x eye wash stations, 1 emergency shower, 4 x wind socks
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2.
3.
HWDP
Drill collars
:
:
5 ½” Grade G, 24.7 lbs/ft, 12000 ft., 5” Grade G, 19.5 lbs/ft, 15000ft
3 ½” Grade G, 13.3 lbs/ft, 9000 ft.
15 x 6 5/8”, 30 x 5 ½”, 50 x 5”, 50 of 3-1/2”
18 of 9-1/2”, 30 of 8-1/2”, 30 of 6-1/4”, 30 of 4-3/4”
H)
Depth Capacity
:
19,000 feet
I)
DF – GL Elevation
Clearance below DF
:
:
34.5 ft
29.85 ft
C)
D)
E)
82 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
2.9.8
SSA-202 (ONSHORE RIG)
A)
Year Built
:
1980
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Sub-Structure
9. Geolograph
:
:
:
:
:
:
:
:
:
National 1320-UE (2000 HP) w/ Elmagco 7040 Dynamic Brake
Pyramid 32 ft x 144 ft.
1,000,000 lbs (static) with 12 lines
Varco-TDS – 400 Ton
National C375 (37 ½”) – 590 Ton (static)
National 660G500 – 500 Ton
National P500 – 500 Ton
Pyramid type?, casing 1,000,000 lbs, setback 60,000 lbs.
Totco, 8 pen and MD/Totco Digital Mud Watch System
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x Caterpillar D398, (1000 HP ea.) with GE 800 KVA Generators
2 x GE 752 motor – 800 HP ea.
4 x GE 752 – 800 HP ea
Ind. Dr. GE 752 motor – 800 HP, Torque xxx Amps / 17500 ft-lbs
2 x make? AC motor, 350 HP ea, Torque 875 Amps / 32500 ft-lbs.
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
:
2 x National 12-P-160 (1600 HP ea.)
2500 bbl. capacity, 100 bbl trip tank
2 x Derrick-Flo Line Cleaner
Derrick 2 x 12” cone – 800 GPM
Derrick 16 x 2” cone – 800 GPM
None
Swaco Horizontal Vac – 1000 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, Koomey ABB, w/ 14 stations
3 1/16” Make? 5000 psi WP, sour service
Shaffer 21 ¼” Annular / Diverter 2000 psi w/ 8” hydraulic valve,
Shaffer 13 5/8” Annular 5000 psi, Cameron U 13 5/8” single ram,
5000 psi, Cameron 13 5/8” double ram with shear booster, 5000
psi, All H2S trimmed.
F)
Safety Equipment
:
Complete H2S monitoring system, 75 Fire extinguishers, 1 Fire
pump, Air Cascade System, 30 x 5-min Breathing apparatus, 10 x
30-min. Breathing Apparatus, 16 x SCBA, Fixed Gas detection
System, Portable Gas Detection Equipment, 5 eye wash stations, 1
shower at mud pits 4 wind socks
G)
Drill Pipe & Drill Collars
1. Drill Pipe
HWDP
Drill collars
:
:
:
:
:
5 ½” Grade G, 26.5 ppf, 5,210 ft.
5” Grade G-105, 19.5 ppf, 9,453 ft
4” Grade XD, 14 ppf, 18,000 ft.
62 of 5”, 98 of 4”
12 of 9 ½”, 30 of 8”, 30 of 6 ½”, 30 of 4 ¾”
H)
Depth Capacity
:
18,000 ft
I)
DF – GL Elevation
Clearance below DF
:
:
29.6 ft
24.5 ft
C)
D)
E)
2.
3.
83 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
F
June 2006
GENERAL INFORMATION
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
3.0
RIG SPECIFICATIONS DATA SHEETS (OFFSHORE RIGS)
3.1
ARABIAN DRILLING COMPANY
3.1.1 ADC-17
3.2
ENSCO ARABIA LIMITED
3.2.1 ENS-76
3.2.1 ENS-95
3.2.1 ENS-96
3.2.1 ENS-97
3.3
POOL ARABIA LIMITED
3.3.1 PA-145
3.3.1 PA-656
3.3.1 OS-655
3.4
PRIDE ARABIA COMPANY
3.4.1 PM-1
3.4.1 PND-1
3.5
ROWEN ARABIA DRILLING CO.
3.5.1 RM-22
3.5.1 CR-36
3.5.1 AR-37
3.5.1 RC-42
3.6
SAUDI ARABIAN SAIPEM LIMITED
3.6.1 PN-2
3.6.1 PN-5
3.7
SAUDI ARAMCO DRILLING CO.
3.7.1 SAR-201
84 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
3.1.1
ADC-17 (OFFSHORE RIG)
A)
Year Built
:
1991
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Geolograph
:
:
:
:
:
:
:
:
National 1320 UE (2000 HP) with xxxxxxx auxiliary brake
DSI xx ft x 160 ft.
1,000,000 lbs static with 12 lines
Varco TDS 3
National C 375, 37 ½”
Make and model? – 550 Ton
Make and model? – 650 Ton
Totco, 7-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud Pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar D399, 1215 HP ea.
2 x GE 752 motor – xxxxx HP ea.
2 x GE 752 motor – xxxxx HP ea
1 x GE 752 motor– Torque xxxxx HP ea, xxxxx Amps/ xxxxx ft-lbs.
Power, make/model, HP – Torque xxxx HP, xxx Amps/xxxx ft-lbs
:
:
:
2 x National 12P-160 – 1600 HP ea.
1300 bbls capacity, 25 bbl trip tank
1 x Brandt dual tandem, 2 x Derrick Flo-Line Cleaners
Derrick Hi-G Dryer, no. of cones and capacity xxxx GPM
None
Derrick Vacu Flo, xxx GPM?
C)
D)
E)
Mud System & Pump
1. Mud Pumps
2. Mud Pits & Storage
3. Shale Shakers
4. Desander / Desilter
5. Centrifuge
6. Degasser
:
:
BOP Equipment
1. Accumulator
2. Choke Manifold
3. BOPs
:
:
:
3000 psi, Ross Hill C-180
4-1/16” Make? 10,000 psi WP, sour service
Hydril MSP 21-1/4” annular, 2000 psi Hydril GL 13-5/8” annular,
5000 psi, Cameron U 13-5/8” double ram, 5000 psi, Cameron U 135/8” single ram, 5000 psi
F)
Safety Equipment
:
2 x 61-man Lifeboats, 6 x 25-man Liferafts, xxx Life Jackets, 18
Survival suits, 10 Working vests, xx 30-min. Scott air packs, xx x
15-min. Scott air packs, Fire/Smoke monitoring system, 000 fire
extinguisher, 80 Fire extinguishers, 1 fire pump, 3 gas detector, 10
H2S detector, 1 cascade system, 97 Scott SCBAs, 4 portable gas
monitors, 7 eye wash stations, 1 shower at mud pits, 3 wind socks,
1 foam units, 2 breathable air compressor.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
2. HWDP
3. Drill Collars (Spiral)
:
:
5 ½” Grade-G, 24.7 lbs/ft, 5000 ft; 5” Grade-G, 19.5 lbs/ft, 12000 ft,
3 ½” Grade-G, 13.3 lbs/ft, 16,000 ft.
30 of 5 ½”, 60 or 5”, 60 of 3 ½”
12 of 9 ½”, 24 of 8 ½”, 18 of 6 ½”, 24 of 4 ¾”
H)
3.2.1
Design Criteria
1. Depth Capacity
2. Max. Water Depth
3. Cantilever
:
:
:
:
:
4.
Sub-Structure
5.
6.
Variable Deck Load :
Accommodation
:
20,000’
250 ft
40’ Max. forward / backward movement
10’ Transverse on each side from centerline of hole
Upper – 29’ (Derrick Floor to Base of Cantilever)
Lower – 49’ (Derrick Floor to Base of the Hull)
xxxx Kips
xx people
ENSCO-76 (OFFSHORE RIG)
85 of 102
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CHAPTER 1
GENERAL INFORMATION
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RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
A)
Year Built
:
1999 (Upgrade/Refurbishment completed in 2005)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Geolograph
:
:
:
:
:
:
:
:
National 1625 UDBE (3000 HP) with Baylor 7838 auxiliary brake
Dreco Beam Leg 40’ x 32’ x 170 ft.
1,500,000 lbs static with 14 lines
Varco TDS-8AS – 750 Ton
National D-495, 49 ½” – 800 Ton
National Oilwell B760GA650 – 650 Ton
Integrated with Top Dive
National Oilwell SDI Hi-Tech, 28-parameter recorder
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar 3606 – 2514 HP ea.
3 x GE 752 – 1085 HP ea.
2 x GE 752 – 1085 HP ea
GE 752 – 1085 HP, Torque 1050 Amps/ 52,654 ft.-lbs. Low Gear
Varco Motor – 1200 HP, Torque 1200 Amps/ 62,500 ft.-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander / Desilter
5. Centrifuge
6. Degasser
:
:
:
:
:
:
3 x National 14-P-220, 2200 HP ea.
4563 bbls capacity (active & reserve), 297 bbl trip tanks
5 x Brandt, LCM 3D-CM2 – 500 GPM ea.
Brandt, LCM 3D-MC – 2,000 GPM / LCM 2D-CMC – 1000 GPM
2 x Brandt HS-2172 – 600 GPM ea.
2 x Brandt DG-10, 1000 GPM ea.
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, Massco SSB240-3S11, capacity 402 Gal.
3 1/16” Cameron 15,000 psi WP, sour service
Hydrill GL 18 3/4” annular 5000 psi, Cameron Type-U 18 ¾ annular
10,000 psi, Cameron 18 ¾ Double Ram 10000 psi, Cameron DL
13-5/8” annular 10000 psi, 2 x Cameron Type-U 13-5/8” single ram
15000 psi, Cameron U 13-5/8” double ram, 15000 psi.
F)
Safety Equipment
:
3 x 50-man Lifeboats, 8 x 25-man Life Rafts, 1 Fast Rescue Craft,
Heli-Deck Foam System, 80 Fire extinguishers, 2 x 700 GPM Fire
pumps, 14 cascade system, 5 Scott Air Pack SCBAs general use.
23-30 min, 166-15 min packs for H2S service, 5 portable gas / H2S
monitors, 4 eye wash stations w/ showers, 1 Drager H2S sniffer, 10
Fresh Air bug blowers, H2S & Combustible gas monitoring system.
34 fire hydrants, Fire / Smoke detectors through out rig
G)
Drill Pipe & Drill Collars
1. Drill Pipe
2. HWDP
3. Drill collars
:
:
:
5 7/8” Grade S-135, 29.5 lbs/ft, 24,000 ft.
5 7/8” Grade S-135, 57.42 lbs/ft, 2,500 ft.
24 of 10”, 24 of 8”, 24 of 6 ½, 24 of 4 ¾”
Sub-Structure
:
:
:
:
:
5. Variable Deck Load
Accommodation
:
:
30,000 ft
300 ft
86.6’ Max. forward / backward movement with load 750,000 lbs.
15’ Transverse on each side from center line of hole
Upper – 46’ (Derrick Floor to Base of Cantilever)
Lower – 72’ (Derrick Floor to Base of the Hull)
– 58’ (Base of Hull to Top of Jack Housing)
xxx Kips
xxx people
C)
D)
E)
H)
Design Criteria
1. Depth Capacity
2. Max. Water Depth
3. Cantilever
4.
86 of 102
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CHAPTER 1
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RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
3.2.2
ENSCO-95 (OFFSHORE RIG)
A)
Year Built
:
1982 (New Accommodation, Refurbished Drawworks and Mud Pits)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Geolograph
:
:
:
:
:
:
:
:
National Oilwell 1320 UE (2000 HP) with Baylor Auxiliary Brake
Superior 30’ x 30’ x 160 ft.
1,000,000 lbs (static) with 12 lines.
Varco TDS-4 – 650 Ton
National C375, 37 ½” – 400 Ton
National P650 – 550 Ton
None (Becket Hook – 650 Ton)
M.D./Totco – Rig Sense
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
3 x EMD V-12-645 E8 – 1650 HP ea. w/ MD 1180 KW generators
2 x EMD D79, 1000 HP ea.
4 x EMD D79, 1000 HP ea.
GE 752, 1085 HP, Torque 800 Amps / 43,200.ft.-lbs
GE 751shunt motor, 1000 HP, Torque 1000 Amps / 29,200.ft.-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander / Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
2 x National Oilwell 12-P-160 – 1600 HP ea.
1602 bbl. capacity (active and reserve) with 2 x 40 bbl. trip tanks
3 x Derrick Flo-Line PMD-500
Derrick Hi-G, 2 x 10” cone / 20 x 4” cone – 1000 GPM
None
Derrick Vacu.-Flo 1000 – 1000 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, Koomey 80, 8 stations w/ 28 x 11 gal. bottles
10,000 psi WP, T-3 Energy Systems FC-3, sour service.
Shaffer Spherical 21 ¼” annular 3000 psi, Shaffer Spherical 13 5/8”
annular 5000 psi, Cameron U 13 5/8” single ram, 10000 psi,
Cameron U 13 5/8” double ram, 10000 psi. All H2S trimmed.
F)
Safety Equipment
:
H2S and Combustible Gas Monitoring System, Fire/Smoke
detection system, 2 x 58-man Lifeboats, 8 x 25-man Life Rafts, 1
Fast Rescue Craft, Sprinkler system, Heli-Deck Foam System, 75
Portable Fire extinguishers, 2 Fire pumps, 10 H2S detectors, 7
cascade system, 189 Scott Air Pack SCBAs, 6 eye wash stations, 6
emergency showers, 1 Drager H2S sniffer.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
2. HWDP
3. Drill collars
:
:
:
5” Grade-G, 19.5 ppf, 14,000 ft, 3 ½” Grade-G, 13.3 ppf, 14,000 ft.
60 of 5”, 100 of 3 ½”
12 of 9 ½”, 24 of 8 ½”, 24 of 6 ½” and 24 of 4 ¾”
:
:
:
:
:
25,000 ft
250 ft
40’ Max. forward / backward movement w/ 650,000 lbs setback load.
12’ Transverse on each side from center line of hole
Upper – 28.5’ (Derrick Floor to Base of Cantilever)
Lower – 51.3’ (Derrick Floor to Base of the Hull)
– 46’ (Base of Hull to Top of Jack Housing)
C)
D)
E)
H)
Design Criteria
1. Depth Capacity
2. Max. Water Depth
3. Cantilever
4.
Sub-Structure
5.
6.
Variable Deck Load :
Accommodation
:
5,020 Kips
103 people
87 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
3.2.3
ENSCO 96 (OFFSHORE RIG)
A)
Year Built
:
1982 (Refurbished in 2002)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Geolograph
:
:
:
:
:
:
:
:
National Oilwell 1320-UE (2000 HP) w/ Baylor 740W Auxiliary Brake
Load Master 40’ x 32’ x 170 ft.
1,000,000 lbs static with 12 lines
Varco TDS 4H – 500 Ton
National C375, 37 ½”, – 650 Ton
National Oilwell 660-H-500 – 500 Ton
C. Emsco LB-650 – 650 Ton
M.D./Totco - RF8, 8-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
3 x EMD V-12 645E8 – 1650 HP ea. w/ 1050 KW generators
2 x EMD D79, 1000 HP ea.
4 x EMD D79, 1000 HP ea.
EMD D79, 1000 HP, Torque 800 Amps / 43,200 ft.-lbs
GE 752, 1085 HP, Torque 1325 Amps / 58200 ft.-lbs in Low Gear
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander / Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
2 x National Oilwell 12-P-160 – 1600 HP ea.
1753 bbls capacity (active and reserve) with 2 x 50 bbl trip tanks
3 x Derrick Hi-G Flo-Line 2000
Derrick Hi-G, 2 x 10” cone / 20 x 4” cone – 1000 GPM
(2 KMC Rental)
Derrick Vacu-Flo 1000 – 1000 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, Shaffer 80, 8 stations w/ 32 x 11 gal. bottles
10,000 psi WP, T-3Energy Systems FC-3 1/16 x 10 K sour service
Shaffer 13 5/8” annular 5000 psi, Cameron Type-U 13-5/8” single
Ram, 10000 psi, Cameron Type-U 13-5/8” double rams, 10000 psi.
All H2S trimmed
F)
Safety Equipment
:
H2S and Combustible Gas Monitoring System, Fire/Smoke
detection system, 2 x 58-man Lifeboats, 9 x 25-man Life Rafts, Fast
Rescue Craft, Sprinkler system, Heli-Deck Foam System, 79
Portable Fire extinguishers, 2 Fire pump, 6- H2S / 6 LEL detectors,
7 cascade system, 193 Scott Air Pack SCBAs, 2 portable H2S
monitors, 6 eye wash stations, shower at mud pit, MSA H2S sniffer.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
2. HWDP
3. Drill collars
:
:
:
5” Grade-G, 19.5 ppf, 15,000 ft, 3 ½” Grade-G, 13.3 ppf, 15,000 ft.
52 of 5”, 100 of 3 ½”
12 of 9 ½”, 12 of 8 ½”, 25 of 6 ¾” and 14 of 4 ¾”
:
:
:
:
:
25,000 ft
246 ft
40’ Max. forward / backward movement w/ 650,000 lbs setback load
12’ Transverse on each side from center line of hole
Upper – 30.30’ (Derrick Floor to Base of Cantilever)
Lower – 51.33’ (Derrick Floor to Bottom of the Hull)
– 25.0’ (Base of Hull to Top of Jack Housing)
5,060 Kips
100 people.
C)
D)
E)
H)
88 of 102
Design Criteria
1. Depth Capacity
2. Max. Water Depth
3. Cantilever
4.
Sub-Structure
5.
6.
Variable Deck Load :
Accommodation
:
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
3.2.4
ENSCO 97 (OFFSHORE RIG)
A)
Year Built
:
1980 (Refurbishment, New Derrick and New Living Qtrs. in 2005)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Geolograph
:
:
:
:
:
:
:
:
C. Emsco C-2 (2000 HP) with 7838 auxiliary brake
Load Master 30’ x 30’ x 160 ft.
1,000,000 lbs. static with 12 lines
Varco TDS 4H – 500 Ton
National D375, 37 ½” – 650 Ton
National Oilwell 750 FA – 650 Ton
National Oilwell P650 – 650 Ton
M.D. / Totco, RF8
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
3 x EMD 1650 HP ea.
2 x EMD M79, 750 HP ea.
4 x EMD M79, 750 HP ea.
1 x EMD M79, 750 HP, Torque 800 Amps / 43,200 ft.-lbs
1 x GE 752, 1100 HP, Torque 1000 Amps / 29,200 ft.-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander / Desilter
5. Centrifuge
6. Degasser
:
:
:
:
:
:
2 x Emsco FB-1600, 1600 HP ea.
1900 bbls capacity (active and reserve) with 86 bbl trip tanks
2 x National DTS-L1 and 3 x Derrick Flo-500/513
Derrick DSI 3 x 10” cone / DRND-CM 20 x 4” cones – 1000 GPM ea.
Mission 6 x 8 x14 (Aramco Rental)
Derrick Vacu-Flo – 1200 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, Shaffer T20160-35ac-62 with 758 gal. capacity
5000 psi WP, T3 Energy Service FC/PSE3G, sour service
Shaffer 21 ½” annular 2,000 psi, Shaffer 13 5/8” annular 5,000 psi,
Cameron Type-U 13-5/8” single ram, 10,000 psi
Cameron Type-U 13-5/8” double ram, 10,000 psi.
F)
Safety Equipment
:
2 x 50-man Lifeboats, 4 x 25-man Life Rafts, 1 Fast Rescue Craft,
Sprinkler system, Heli-Deck Foam System, 59 Fire extinguishers, 3
Fire pump, 10 H2S detectors, 7 cascade system, 192 Sabrre Air
Pack SCBAs, 2 portable H2S monitors, 6 eye wash stations, 6
shower at mud pits, 2 Rikei H2S sniffer.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
2. HWDP
3. Drill collars
:
:
:
5” Grade G, 19.5 ppf, 22,000 ft., 3 ½” Grade G, 13.3 ppf, 12,000 ft.
50 of 5”, 100 of 3 ½”
6 of 9 ½”, 23 of 8”, 24 of 6 ½”, 24 of 4 ¾”
:
:
:
:
:
20,000 ft
250 ft
40’ Max. forward / backward movement
10’ Transverse on each side from center line of hole
Upper – 27’ (Derrick Floor to Base of Cantilever)
Lower – 48’ (Derrick Floor to Bottom of the Hull)
– 46’ (Base of Hull to Top of Jack Housing)
4,390 Kips
100 people.
C)
D)
E)
H)
Design Criteria
1. Depth Capacity
2. Max. Water Depth
3. Cantilever
4.
Sub-Structure
5.
6.
Variable Deck Load :
Accommodation
:
89 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
3.3.1
PA-145 (OFFSHORE RIG)
A)
Year Built
:
1982
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Geolograph
:
:
:
:
:
:
:
:
IDECO E1200 (2000 HP) w/ Dretech 250 (8042) Auxiliary Brake
Pool Company, Square top, 13’ x 17’ x 139 ft.’
700,000 lbs
None (5 ¼” Hexagonal 42 ft Kelly)
Ideco 162 LR375E, 37 ½”
Ideco – 350 Ton
C. Emsco LB-400 – 400 Ton
Totco 6-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud Pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar D399 – 1215 HP ea. w/ 1030 KW generators
2 x GE752 motor – 1000 HP ea.
2 x GE752 motor – 1000 HP ea
GE752 motor – 1000 HP, Torque 800 Amps / 11,800 ft-lbs.
None
Mud System & Pump
1. Mud Pumps
2. Mud Pits & Storage
3. Shale Shakers
4. Desander/Desilter
5. Centrifuge
6. Degasser
:
:
:
:
:
:
2 x Gardner Denver PZ-9 – 1000 HP ea.
1500 bbl. capacity with 68 bbl slig pit and 45 bbl trip tank
2 x Derrick 2E48-90F-3TA – 1600 GPM
Derrick DSI-10-2, 3 x 12” cone / RND-CM4, 12 x 4” cone – 1000 GPM
None
SWACO vacuum type w/ 5 HP motor – 1200 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, CAD with 240 gal. capacity
3 1/8 “ Cameron 5000 psi WP w/ 2 x 2 9/16” adjustable super chokes
Shaffer 11” annular – 5000 psi, Shaffer LWS, 11” single ram, 5000 psi,
Shaffer LWS, 11” single ram, 5000 psi.
F)
Safety Equipment
:
H2S & Combustible Gas Monitoring System, Fire / Smoke detection
system, Portable H2S & combustible gas monitors, 2 x 900 GPM
fire pumps, 73 Fire Extinguishers, CO2 monitoring system, Sprinkler
System in accommodations, 4 x Portable Foam system at HeliDeck, Cascade Breathing System, 2 x 58-man Lifeboats, 2 x 25man life rafts , 2 x 20-man life rafts, 1 x Fast Rescue Craft.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
:
:
:
:
5” Grade-E, 19.5 ppf, 10,000 ft, 3 ½” Grade-E, 13.3 ppf 10,000 ft.
3 ½” Grade-G, 13.3 ppf, 5,000 ft.’
60 of 3 ½”
12 of 9 ½”, 30 of 8 ¼”, 30 of 6 ¼”, 30 of 4 ¾”
:
:
:
:
:
15,000 ft.
150 ft.
40’ Max. forward / backward movement
8’ Transverse on each side from centerline of hole
Upper – 26.6’ (Derrick Floor to Base of Cantilever)
Lower – 43.0’ (Derrick Floor to Base of the Hull)
xxxx Kips
xxx people
C)
D)
E)
2.
3.
H)
90 of 102
HWDP
Drill Collars
Design Criteria
1. Depth Capacity
2. Max. Water Depth
3. Cantilever
4.
Sub-Structure
5.
6.
Variable Deck Load :
Accommodation
:
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
3.3.2
PA-656 (OFFSHORE RIG)
A)
Year Built
:
1975 (Upgrade/Refurbishment completed in 2005)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Geolograph
:
:
:
:
:
:
:
:
Oilwell E 2000, xxxxx HP with xxxxxx auxiliary brake
Pyramid x’W x x’L x 156’H
1,000,000 lbs static with xx lines
Can Rig 1050E – xxx Ton
Oilwell B37 ½” – xxx Ton
Oilwell Model? – 500 Ton
Integrated with Top Dive
National Oilwell SDI Hi-Tech, 28-parameter recorder
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar 3606 – 2514 HP ea.
3 x GE 752 – 1085 HP ea.
2 x GE 752 – 1085 HP ea
GE 752 – 1085 HP, Torque, ----- Amps/ 52,654 ft.-lbs Low Gear
Varco Motor?, 1200 HP, Torque , ----- Amps/ 62,500 ft.-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander
5. Desilter
5. Centrifuge
6. Degasser
:
:
:
:
:
:
:
3 x National 14-P-220, 2200 HP ea.
4563 bbls capacity (active & reserve), 297 bbl trip tanks
5 x Brandt, LCM 3D-CM2 – 500 GPM ea.
Brandt, LCM 3D-MC – 2,000 GPM
Brandt, LCM 2D-CMC – 1000 GPM
2 x Brandt HS-2172, ----- GPM ea.
2 x Brandt DG-10, 1000 GPM ea.
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, Massco SSB240-3S11 capacity 402 Gal.
15,000 psi WP, 3 1/16” Cameron, sour service
Hydrill GL 18 3/4” 5K annular, 1-Cameron Type-U 18 ¾ 10K,
Cameron 18 ¾ 10K Double, 13-5/8” Cameron DL 10K annular, 2 x
Cameron Type-U 13-5/8” single ram, 15000 psi, Cameron Type-U
13-5/8” double ram, 15000 psi.
F)
Safety Equipment
:
3 x 50-man Lifeboats, 8 x 25-man Life Rafts, 1 Fast Rescue Craft,
Heli-Deck Foam System, 80 Fire extinguishers, 2 x 700 GPM Fire
pumps, 4 H2S detectors, 14 cascade system, 5 Scott Air Pack
SCBAs general use. 23-30 min, 166-15 min packs for H2S service,
5 portable gas/ H2S monitors, 4 eye wash stations w/ showers, 1
Drager H2S sniffer, H2S & Combustible gas monitoring system
G)
Drill Pipe & Drill Collars
1. Drill Pipe
2. HWDP
3. Drill collars
:
:
:
5” Grade-G, 19.5 lbs/ft, 14000 ft, 3 ½” Grade-G 13.3 lbs/ft, 14000 ft.
60 of 5”, 100 of 3 ½”
12 of 9 ½”, 24 of 8 ½”, 24 of 6 ¼” 24 of 4 ¾”
:
:
:
:
:
20,000 ft
xxx ft
xxx’ Max. forward / backward movement with load 750,000 lbs.
xx’ Transverse on each side from center line of hole
Upper – xx’ (Derrick Floor to Base of Cantilever)
Lower – xx’ (Derrick Floor to Base of the Hull)
xxx Kips
xxx people
C)
D)
E)
H)
3.3.3
Design Criteria
1. Depth Capacity
2. Max. Water Depth
3. Cantilever
4.
Sub-Structure
5.
6.
Variable Deck Load :
Accommodation
:
OS-655 (OFFSHORE RIG)
91 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
A)
Year Built
:
1979
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Geolograph
:
:
:
:
:
:
:
:
OIME 1200 HP, w/ Baylor Elmagco 6032 eddy current brake.
Pyramid 147’
750,000 lbs
None
National C-375 (37 ½”)
Ideco TB-360-5-42 – 360 Ton
National P-400 – 400 Ton
M.D./Totco, 6-pen w/ Epoch Rig-Watch RW964 monitoring system
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
3 x Caterpillar 3516B 1855 HP ea. w/ 1505 KW generators
2 x GE-752, 1000 HP ea.
4 x GE-752, 1000 HP ea.
GE-752, 1000 HP
None
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander./ Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
2 x Gardner Denver PZ-10 – 1500 HP ea.
1500 bbls
2 x Derrick FLC-2000, 4 panel shale shakers.
Derrick D-RND-CM-4-20 – 1000 GPM / DSI-10 – 1000 GPM
None
Swaco vacuum type – 750 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 Psi, M-series SB280-11SB3K w/ 28 x 11 gal. bottles
5000 psi WP, sour service
Shaffer 11” annular 5000 psi
Shaffer 11” single ram, 5000 psi
Shaffer 11” double ram, 5000 psi.
F)
Safety Equipment
:
2 x 50 man Lifeboats, 4 x 25 Life Rafts, 1 Fast Rescue Craft,
Sprinkler system-Accommodation, Heli-Deck Foam System, 51 Fire
extinguishers, 1 Fire pump, 4 H2S detectors, cascade system, Scott
Air Pack SCBAs, 2 portable gas/ H2S monitors, 3 eye wash
stations, 1 shower at mud pits, 1 Drager H2S sniffer,
G)
Drill Pipe & Drill Collars
1. Drill Pipe
2. HWDP
3. Drill collars
:
:
:
5” Grade G, 19.5 ppf, 12,000’, 3 ½” Grade G, 13.3 ppf, 9,000 ft.
50 of 5”, 100 of 3 ½”
12 of 8 ½”, 24 of 6 ½”, 24 of 4 ¾”, 24 of 3 3/8”.
:
:
:
:
:
18,000 ft.
150 ft
40’ Max. forward / backward movement
10’ Transverse on each side from center line of hole
Upper – 25.7’ (Derrick Floor to Base of Cantilever)
Lower – 48.7’ (Derrick Floor to Base of the Hull)
3,741 Kips
112 person
C)
D)
E)
H)
92 of 102
Design Criteria
1. Depth Capacity
2. Max. Water Depth
3. Cantilever
4.
Sub-Structure
5.
6.
Variable Deck Load :
Accommodation
:
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
3.4.1
PM-1 (OFFSHORE RIG)
A)
Year Built
:
1982 (New Accommodation, Refurbished Drawworks and Mud Pits)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Geolograph
:
:
:
:
:
:
:
:
National Oilwell 1320 UE (2000 HP) with Baylor Auxiliary Brake
Superior 30’ x 30’ x 160 ft.
1,000,000 lbs (static) with 12 lines.
Varco TDS-4 – 650 Ton
National C375, 37 ½” – 400 Ton
National P650 – 550 Ton
None (Becket Hook – 650 Ton)
M.D./Totco – Rig Sense
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
3 x EMD V-12-645 E8 – 1650 HP ea. w/ MD 1180 KW generators
2 x EMD D79, 1000 HP ea.
4 x EMD D79, 1000 HP ea.
GE 752, 1085 HP, Torque 800 Amps / 43,200.ft.-lbs
GE 751shunt motor, 1000 HP, Torque 1000 Amps / 29,200.ft.-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander / Desilter
6. Centrifuge
7. Degasser
:
:
:
:
:
:
2 x National Oilwell 12-P-160 – 1600 HP ea.
1602 bbl. capacity (active and reserve) with 2 x 40 bbl. trip tanks
3 x Derrick Flo-Line PMD-500
Derrick Hi-G, 2 x 10” cone / 20 x 4” cone – 1000 GPM
None
Derrick Vacu.-Flo 1000 – 1000 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, Koomey 80, 8 stations w/ 28 x 11 gal. bottles
10,000 psi WP, T-3 Energy Systems FC-3, sour service.
Shaffer Spherical 21 ¼” annular 3000 psi, Shaffer Spherical 13 5/8”
annular 5000 psi, Cameron U 13 5/8” single ram, 10000 psi,
Cameron U 13 5/8” double ram, 10000 psi. All H2S trimmed.
F)
Safety Equipment
:
H2S and Combustible Gas Monitoring System, Fire/Smoke
detection system, 2 x 58-man Lifeboats, 8 x 25-man Life Rafts, 1
Fast Rescue Craft, Sprinkler system, Heli-Deck Foam System, 75
Portable Fire extinguishers, 2 Fire pumps, 10 H2S detectors, 7
cascade system, 189 Scott Air Pack SCBAs, 6 eye wash stations, 6
emergency showers, 1 Drager H2S sniffer.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
2. HWDP
3. Drill collars
:
:
:
5” Grade-G, 19.5 ppf, 14,000 ft, 3 ½” Grade-G, 13.3 ppf, 14,000 ft.
60 of 5”, 100 of 3 ½”
12 of 9 ½”, 24 of 8 ½”, 24 of 6 ½” and 24 of 4 ¾”
:
:
:
:
:
25,000 ft
250 ft
40’ Max. forward / backward movement w/ 650,000 lbs setback load.
12’ Transverse on each side from center line of hole
Upper – 28.5’ (Derrick Floor to Base of Cantilever)
Lower – 51.3’ (Derrick Floor to Base of the Hull)
– 46’ (Base of Hull to Top of Jack Housing)
5,020 Kips
103 people
C)
D)
E)
H)
Design Criteria
1. Depth Capacity
2. Max. Water Depth
3. Cantilever
4.
Sub-Structure
5.
6.
Variable Deck Load :
Accommodation
:
93 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
3.4.2
PND-1 (OFFSHORE RIG)
A)
Year Built
:
1981
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Geolograph
:
:
:
:
:
:
:
:
C. Emsco C-3 (3000 HP) with Elmagco 7838 Auxiliary Brake
C. Emsco 20-RD, 160 ft.
1,300,000 lbs (static) with 12 lines.
Maritime Hydraulics DDM 650C – 650 Ton
C. Emsco Model T3750, 37 ½”
C. Emsco RA-60-7 – 650 Ton
None
Petron IDS 2000, 10-channel computer data recorder
Rig Power
1. Engine Power
:
2.
3.
4.
5.
:
:
:
:
4 x EMD 645 12E-8, 1520 HP ea. w/ 1120 KW generator ea.
Emergency Cat 3508 with generator
3 x GE 752 Motor – 1000 HP ea.
2 x GE 752 Motor – 1000 HP ea.
GE 752 Motor – 850 HP ea. Torque 1200 Amps / 38,455 ft-lbs.
GE 752 HT Motor – 1130 HP; Torque 1060 Amps / 50,000 ft-lbs.
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander / Desilter
5. Centrifuge
6. Degasser
:
:
:
:
:
:
2 x C. Emsco FB-1600 – 1600 HP ea.
1870 bbl. active system with 2 x 50 bbl. Trip Tank
2 x Derrick FLC 2000 super G, Brandt CDX-18-8340 Cleaner
Demco 2x 12” cone – 1000 GPM / Brandt 16 x 4” cone – 960 GPM
Brandt 1850 – 250 GPM
Swaco Horizontal 6” x 8” vacuum type – 800 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, Ross Hill C 180-2E25-2AG w/ 11 x 24 gal. bottles
3-1/16” Cameron 10000 psi WP sour service
Shaffer 13-5/8” annular 5,000 psi, Cameron 13-5/8” single ram,
10,000 psi, Cameron U 13-5/8” double ram, 10,000 psi.
F)
Safety Equipment
:
5 x H2S portable Gas detectors & 4 x Multi Gas detectors, Portable
gas monitors, Fire/Smoke Detection system, 102 x Fire
Extinguishers, 2 x fire pumps – 300GPM, 140 SCBA’s, 3 x
breathable Air Compressors, 4 x eye-wash stations, 2 x showers,
4 windsocks, CO2 system in Engine/SCR/E-Gen/Paint Locker
rooms, Foam system at Heli-Deck, Cascade Breathing System, 2
x 50-man Lifeboats, 4 x 20-man Life rafts, Fast Rescue Craft.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
2. HWDP
3. Drill collars
:
:
:
4” Grade CY, 14.5 ppf, 14,000 ft; 2-3/8” Grade E; 6.65 ppf, 9,000 ft.
101 of 4”
12 of 6-1/2”, 12 of 4-3/4”, 12 of 3-3/8”
:
:
:
:
:
30,000 ft
250 ft
40’ Max. forward / backward movement
10’ Transverse on each side from center line of hole
Upper – 26.0 ft (Derrick Floor to Base of Cantilever)
Lower – 51.0 ft (Derrick Floor to Base of the Hull)
Lower – 47.0 ft (Base of the Hull to top of jack housing)
3,500 Kips
C)
D)
E)
H)
94 of 102
Drawworks
Mud pumps
Rotary
Top Drive
Design Criteria
1. Drilling Depth Cap.
2. Max. Water Depth
3. Cantilever
4.
Sub-Structure
5.
Variable Deck Load :
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
6.
3.5.1
Accommodation
:
85 people
RM-22 (OFFSHORE RIG)
A)
Year Built
:
1985
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Geolograph
:
:
:
:
:
:
:
:
National 1320 UE (1500 HP) with xxxxx Auxiliary Brake
Pyramid 149 ft.
1,100,000 lbs (static) with 12 lines.
VARCO TDS 3 B20 – xxx Ton
National C375, 37 ½” – xxx Ton
National 660 - G500 – 500 Ton
National P-500 – xxx Ton
M.D./Totco Spectrum 1000, 8-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x Caterpillar D399 – xxxx HP ea. with1250 KVA ea.
2 x GE 752 Motor – 1000 HP ea.
2 x GE 752 Motor – 1000 HP ea.
GE 752 Motor – 1000 HP, Torque 1060 Amps / 5300.ft.-lbs
GE 752 Motor – 1000 HP, Torque 1060 Amps / 5300.ft.-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander / Desilter
5. Centrifuge
6. Degasser
:
:
:
:
:
:
2 x National 12 P 160, 1600 HP ea.
1762 bbls – xx bbls Trip Tank
3 x Derrick FLC 2000
Brandt 12” x 2 cones / 4” x 12 cones – 1000 GPM
None
Swaco Vaccum type, model and capacity in GPM ?
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, Koomy with xxx stations
3 1/8 “ Cameron 10000 psi WP sour servic
Make And size? annular 5000 psi, Make And size? single ram,
xxxxxx psi, Make And size? double ram, xxxxx psi.
F)
Safety Equipment
:
H2S & Combustible Gas Monitoring System, Fire / Smoke detection
system, Portable H2S & combustible gas monitors, 2 x 0000GPM
fire pumps, CO2 monitoring system in Engine Room/SCR/EGen/Paint Locker, Sprinkler System in accommodations, Foam
system at Heli-Deck, Cascade Breathing System, 2 x 50man
Lifeboats, 4 x 20man Life rafts, 1 x Fast Rescue Craft
G)
Drill Pipe & Drill Collars
1. Drill Pipe
2. HWDP
3. Drill collars
:
:
:
5” Grade-G 19.5 lbs/ft, 12,000 ft.
50 of 5”, 100 of 3 ½”
12 of 6 ½”, 21 of 4-3/4”, 12 of 3-3/8”
:
:
:
:
:
20,000 ft
160 ft
40’ Max. forward / backward movement
10’ Transverse on each side from center line of hole
Upper – 25.7’ (Derrick Floor to Base of Cantilever)
Lower – 48.7’ (Derrick Floor to Base of the Hull)
– 49.0’ (Base of Hull to Top of Jack Housing)
xxx Kips
xx people
C)
D)
E)
H)
Design Criteria
1. Depth Capacity
2. Max. Water Depth
3. Cantilever
4.
Sub-Structure
5.
6.
Variable Deck Load :
Accommodation
:
95 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
3.5.2
CR-36 (OFFSHORE RIG)
A)
Year Built
:
1979
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Geolograph
:
:
:
:
:
:
:
:
National 1320 UE (xxxx HP) w/ xxxx Auxiliary Brake
Dreco Derrick 1000000 lbs
1,100,000 lbs (static) with 12 lines.
VARCO TDS 3 B20 – xxx Ton
National C375, 37 ½” – xxx Ton
National 660 - G500 – 500 Ton
National P-500 – xxx Ton
M.D./Totco Spectrum 1000, 8-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x Caterpillar D399 – xxxx HP ea. with1250 KVA ea.
2 x GE 752 Motor – 1000 HP ea.
2 x GE 752 Motor – 1000 HP ea.
GE 752 Motor – 1000 HP, Torque 1060 Amps / 5300.ft.-lbs
GE 752 Motor – 1000 HP, Torque 1060 Amps / 5300.ft.-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander / Desilter
5. Centrifuge
6. Degasser
:
:
:
:
:
:
2 x National 12 P 160, 1600 HP ea.
1762 bbls – xx bbls Trip Tank
3 x Derrick FLC 2000
Brandt 12” x 2 cones / 4” x 12 cones – 1000 GPM
None
Swaco Vaccum type, model and capacity in GPM ?
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, Koomy with xxx stations
3 1/8 “ Cameron 10000 psi WP sour servic
Make And size? annular – 5000 psi, Make And size? single ram,
xxxxxx psi, Make And size? double ram, xxxxx psi.
F)
Safety Equipment
:
H2S & Combustible Gas Monitoring System, Fire / Smoke detection
system, Portable H2S & combustible gas monitors, 2 x 0000GPM
fire pumps, CO2 monitoring system in Engine Room/SCR/EGen/Paint Locker, Sprinkler System in accommodations, Foam
system at Heli-Deck, Cascade Breathing System, 2 x 50man
Lifeboats, 4 x 20man Life rafts, 1 x Fast Rescue Craft
G)
Drill Pipe & Drill Collars
1. Drill Pipe
2. HWDP
3. Drill collars
:
:
:
5” Grade-G 19.5 lbs/ft, 12,000 ft.
50 of 5”, 100 of 3 ½”
12 of 6 ½”, 21 of 4-3/4”, 12 of 3-3/8”
:
:
:
:
:
20,000 ft
160 ft
40’ Max. forward / backward movement
10’ Transverse on each side from center line of hole
Upper – 25.7’ (Derrick Floor to Base of Cantilever)
Lower – 48.7’ (Derrick Floor to Base of the Hull)
– 49.0’ (Base of Hull to Top of Jack Housing)
xxx Kips
xxx people
C)
D)
E)
H)
96 of 102
Design Criteria
1. Depth Capacity
2. Max. Water Depth
3. Cantilever
4.
Sub-Structure
5.
6.
Variable Deck Load :
Accommodation
:
SAUDI ARAMCO
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
F
DRILLING MANUAL
June 2006
GENERAL INFORMATION
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
97 of 102
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
3.5.3
AR-37 (OFFSHORE RIG)
A)
Year Built
:
1981 (Major Upgrades 2006)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Geolograph
:
:
:
:
:
:
:
:
National 1625 DE (2,000 HP) with Elmagco 7820 auxiliary brake
Lee C. Moore, (T Leg type) 30 ft x 160 ft
1,000,000 lbs
National PS-2 650 – 650 Ton
National C-375 (37 ½”) – 650 Ton
National – 500 Ton
National, 650 Ton
None
Rig Power
1. Engine Power
2. Drawworks
3. Mud Pumps
4. Rotary
5. Top Drive
:
:
:
:
:
6 x Caterpillar.D399 – 1320 HP ea. + One D379 Emergency
2 x GE motor – 1000 HP ea.
6 x GE motor – 1000 HP ea
Drawwork Driven – 1000 HP, Torque 1060 Amps / 53,000 ft-lbs.
GE 752 motor – 1130 HP, Torque 1200 Amps / 55,511 ft-lbs.
Mud System & Pump
1. Mud Pumps
2. Mud Pits & Storage
3. Shale Shakers
4. Desander / Desilter
5. Centrifuge
6. Degasser
:
:
:
:
:
:
3 x National 12-P-160, 1600 HP ea.
1759 bbl. Capacity, 54 bbl. Trip Tank
4 x Brandt Cobra-S
Brandt Cobra-S 2 x 12“ cone / 16 x 4“ cone – 1000 GPM ea.
None
Swaco 255 type 30 – 1000 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi WP, CAD 523 with 15 stations
3 1/16” Energy Equipment Corp, 10,000 psi, H2S trimmed
Shaffer 30” Annular, 1000 psi, Cameron D 13 5/8” Annular 5000 psi,
Cameron 21 ¼ Annular, 2000 psi, Cameron U 13 5/8 Double Ram
10000 psi, Cameron U 13 5/8 Single Ram 10000 psi. All H2S
trimmed
F)
Safety Equipment
:
2 x 54-man Lifeboats, 4 x 25-man Liferafts, 4 x 20-man Self
Inflatable Life rafts, 130 Life Jackets, 10 Working vests, 10 x 30-min.
Scott air packs, xx x 15-min. Scott air packs, Fire/Smoke monitoring
system, 95 fire extinguisher, 2 fire pump, 8 x combustible / H2S gas
detectors, Cascade system, 180 SCBA, 4 portable gas monitor, 4
eye station, 2 shower, 3 breathing air compressor.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
2. HWDP
3. Drill collars
:
:
:
5” Grade-G 19.5 ppf, 14,000ft, 3 ½” Grade-G 13.30 ppf, 14,000ft
30 of 5”, 100 of 3 ½”
12 of 9 ½“, 24 of 8 ½“, 24 of 6 ½“, 24 of 4 ¾”
:
:
:
:
:
25,000 ft.
275 ft.
45’ max. Forward / backward movement, Pipe Rack 800,000 lbs.
12’ transverse on each side from centerline of hole
Upper - 30’ (derrick floor to base of cantilever)
Lower - 56’ (derrick floor to base of the hull)
xxxx Kips
xxxx people
C)
D)
E)
H)
98 of 102
Design Criteria
1. Depth Capacity
2. Max. Water Depth
3. Cantilever
4.
Sub-Structure
5.
6.
Variable Deck Load :
Accommodation
:
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
3.5.4
RC-42 (OFFSHORE RIG)
A)
Year Built
:
1983 (derrick extended in 1987, 5th engine installed in 1993)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Geolograph
:
:
:
:
:
:
:
:
National 1625 DE (1625 HP) with Elmagco 7838 auxiliary brake)
Lee C. Moore 30 x 30 x 160 ft.
1,230,000 lbs with 12 lines
National PS2 650/650 – 650 Ton
National C 375 (37 ½”)
National 660 H500 – 500 Ton
None
OEM computerized system with 2 monitors.
Rig Power
1. Engine Power
2. Drawworks
3. Mud Pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x Caterpillar.D399 – 1325 HP ea. + One D379 Emergency Gen.
2 x GE motors 752 – 1000 HP ea.
4 x GE motors 752– 1000 HP ea
Draw works driven - Torque 1060 Amps / 5300 ft-lbs
GE 752 motor – 1130 HP, Torque 1250 Amps / 47,860 ft-lbs.
Mud System & Pump
1. Mud Pumps
2. Mud Pits & Storage
3. Shale Shakers
4. Desander / Desilter
5. Centrifuge
6. Degasser
:
:
:
:
:
:
2 x National 12P-160 – 1600 HP ea.
1392 bbl. capacity, 45 bbl. trip tank
4 x Brant King Cobra
Brant LCM, 3 x 12“ cone / 24 x 4“ cone – 1600 GPM
None
Swaco Total Mud Degasser – 1000 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, CAD 523 with 15 stations
3 1/16” EEC, 10,000 psi WP sour service
Varco 30” Annular, 1000 psi, Hydril 13 5/8” Annular 5000 psi, Hydril
21 ¼ Annular, 2000 psi, Cameron U 13 5/8 Double Ram 10000 psi,
Cameron U 13 5/8 Single Ram 10000 psi. All H2S trimmed.
F)
Safety Equipment
:
1 x 54-man, 1 x 38-man lifeboats, 4 x 25-man davit launched life
rafts, 4 x 25-man throw over life rafts. 110 life jackets, 130 Survival
suits, 12 Working vests, 23 Sabre 30-min. air packs, 139 x 15-min.
Sabre air packs, Fire/Smoke monitoring system, 98 fire
extinguisher, 2 fire pump, 9 x combustible gas / H2S gas detectors,
1 cascade system, 6 portable gas monitors, 4 eye station, 3
shower, 3 breathing air compressors.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
2. HWDP
3. Drill collars
:
:
:
5” Grade-G 19.5 ppf, 14,000ft, 3 ½” Grade-G 13.30 ppf, 14,000ft
50 of 5”, 100 of 3 ½”
12 of 9 ½“, 24 of 8 ½“, 24 of 6 ½“, 24 of 4 ¾”
:
:
:
:
:
25,000 ft.
280 ft.
45’ max. Forward / backward movement
12’ transverse on each side from centerline of hole
Upper - 29’ (derrick floor to base of cantilever)
Lower - 56’ (derrick floor to base of the hull)
- 52’ (base of hull to top of jack housing)
xxxx Kips
xxx people
C)
D)
E)
H)
Design Criteria
1. Depth Capacity
2. Max. Water Depth
3. Cantilever
4.
Sub-Structure
5.
6.
Variable Deck Load :
Accommodation
:
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CHAPTER 1
GENERAL INFORMATION
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SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
3.6.1
PN-2 (OFFSHORE RIG)
A)
Year Built
:
1980 (Refurbished in 2002)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Geolograph
:
:
:
:
:
:
:
:
Oilwell E2000 (2,000 HP) with Elmagco 7040 auxiliary brake
Brenham 45 ft x 160 ft
1,000,000 lbs (static) with 12 lines
Varco TDS-4 – 500 Ton
Oilwell A 37 (37 ½”)
Ideco UTB-525 – 475 Ton
Oilwell PC-500 – 500 Ton
Spectrum computerized system with 2 monitors, 6 pens
Rig Power
1. Engine Power
2. Drawworks
3. Mud Pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x Caterpillar.D399 – 1150 HP ea. + One D399 Emergency
2 x GE motors DM7661 – 1000 HP ea.
4 x GE motors DM7661 – 1000 HP ea
GE motor DM7661 – 1000 HP, Torque 1060 Amps / 53,000 ft-lbs.
Varco TDS-4 – 1100 HP, Torque 45,500 ft-lbs.
Mud System & Pump
1. Mud Pumps
2. Mud Pits & Storage
3. Shale Shakers
4. Desander/Desilter
5. Centrifuge
6. Degasser
:
:
:
:
:
:
3 x Oilwell A-1700PT – 1600 HP ea.
2839 bbls Capacity with 69 bbl Trip Tank
3 x Derrick Flow Line Cleaners
Derrick 10“ x 3 cones / 4“ x 20 cones – 1000 GPM ea.
Derrick CV 1000 – 1000 GPM
Brandt DG10 – 1200 GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
3000 psi, CAD 523 with 15 stations
3 1/16” Cameron 10,000 psi WP, sour service
Shaffer 30” Annular, 1000 psi, Cameron D 13 5/8” Annular 5000 psi,
Shaffer 21 ¼” Annular 2000 psi, Cameron U 13 5/8 Double Ram
10000 psi, Cameron U 13 5/8 Single Ram 10000 psi. All H2S
trimmed.
F)
Safety Equipment
:
2 x 61-man Lifeboats, 6 x 25-man Liferafts, 1 x 20-man Self
Inflatable boat, 223 Life Jackets, 18 Survival suits, 10 Working
vests, 44 x 30-min. Scott air packs, 280 x 15-min. Scott air packs,
Fire/Smoke monitoring system, 2 fire pump, 10 x combustible gas
detector, H2S gas detector,1 cascade system, 180 SCBA, 4
portable gas monitor, 4 eye station, 4 shower, 3 breathing air
compressor.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
2. HWDP
3. Drill collars
:
:
:
5” Grade-G 19.5 ppf, 14,000ft, 3 ½” Grade-G 13.30 ppf, 14,000ft
60 of 5”, 100 of 3 ½”
12 of 9 ½“, 24 of 8 ½“, 24 of 6 ½“, 24 of 4 ¾”
:
:
:
:
:
20,000 ft.
300 ft.
45’ max. Forward / backward movement, Pipe Rack 800,000 lbs.
12’ transverse on each side from centerline of hole
Upper – 29’ (derrick floor to base of cantilever)
Lower – 55’ (derrick floor to bottom of the hull)
4,234 Kips
112 people.
C)
D)
E)
H)
100 of 102
Design Criteria
1. Depth Capacity
2. Max. Water Depth
3. Cantilever
4.
Sub-Structure
5.
6.
Variable Deck Load :
Accommodation
:
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
3.6.2
PN-5 (OFFSHORE RIG)
A)
Year Built
:
1980 (Major maintenance / refurbishment in 2005)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Geolograph
:
:
:
:
:
:
:
:
National 1320-UE (2000 HP) with Baylor xxxx Auxiliary Brake
Dreco 30’ x 149 ft.
1,000,000 lbs. (static) with 12 lines
Varco TDS 3 B20 – 500 Ton
National Type C - 37-1/2” – 500 Ton
National 750-FA & 760-FA – 500 Ton
National P-500 – 500 Ton
Martin Decker, 8-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
5 x Caterpillar D399 – 1200 HP ea. with 1250 KW Generators
2 x GE 752 Motor – 1000 HP ea.
4 x GE 752 Motor – 1000 HP ea.
GE 752 Motor 1000 HP, Torque 1060 Amps / 5300 ft.-lbs
GE 752 Motor 1000 HP, Torque 1060 Amps / 5300 ft.-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander / Desilter
5. Centrifuge
6. Degasser
:
:
:
:
:
:
2 x National 12-P-160 – 1600 HP ea.
1450 bbl. capacity with 30 bbl. Trip Tank
3 x Derrick Flo-Line Cleaner 2000
Brandt SRS-2, 0 x 00” cone / 0 x 00” cone – 1000 GPM
Mission Magnum 6” x 8”–1400 GPM (Brandt 1850 Solid– 250 GPM)
Brandt DG 10 – 1000 GPM
C)
D)
E)
BOP Equipment
1. Accumulator
: 3000 psi, CAD EE 14K 1NR 3 Stations (No. of control levers and
no. of bottles with capacity in gallons)
2. Choke manifold
: 3 1/8 “ EEC, 10000 psi WP Sour service?
3. BOPs
: Hydril GK 13 5/8” annular 10000 psi
Cameron U 13-5/8” single ram, 10000 psi
Cameron U 13-5/8” double ram, 10000 psi.
F)
Safety Equipment
:
H2S & Combustible Gas Monitoring System, Fire / Smoke detection
system, Portable H2S & combustible gas monitors, 2 x 600 GPM fire
pumps, CO2 monitoring system, oo x Portable Fire Extinguishers,
Sprinkler System in accommodations, Foam system at Heli-Deck,
Cascade Breathing System, 2 x 60-man Lifeboats, 4 x 25-man Life
rafts, 1 x Fast Rescue Craft.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
2. HWDP
3. Drill collars
:
:
:
4” Grade-G 14.0 ppf, 14,000 ft, 2 3/8” Grade-E, 6.65 ppf, 8700 ft.
100 of 4”
12 of 6 ½”, 15 of 4 ¾”, 12 of 3 3/8”
Sub-Structure
:
:
:
:
:
5. Variable Deck Load
6. Accommodation
:
:
13,000 feet
160 feet
40’ Max. forward / backward movement
10’ Transverse on each side from center line of hole
Upper – 25.7’ (Derrick Floor to Base of Cantilever)
Lower – 48.7’ (Derrick Floor to Base of the Hull)
– 49’ (Base of Hull to Top of Jack Housing)
0000 Kips
000 people
H)
Design Criteria
1. Depth Capacity
2. Max. Water Depth
3. Cantilever
4.
101 of 102
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DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
GENERAL INFORMATION
F
SECTION
June 2006
RIG SPECIFICATIONS
___________________________________________________________________________________________________________________________
3.7.1
SAR-201 (OFFSHORE RIG)
A)
Year Built
:
1982 (Completely Refurbished in 1998)
B)
Rig Equipment
1. Drawworks
2. Derrick
3. Hook Load
4. Top Drive
5. Rotary Table
6. Blocks
7. Swivel
8. Geolograph
:
:
:
:
:
:
:
:
Continental Emsco C2 – 2000 HP with auxiliary brake
Pyramid 30’ x 160 ft.
1,300,000 lbs static with 12 lines
Varco TDS 3
C. Emsco T3750, 37 ½”, xxx Ton
C. Emsco Model, 500 Ton
Make and Model? 500 Ton
Martin Decker/Totco, 8-pen
Rig Power
1. Engine Power
2. Drawworks
3. Mud pumps
4. Rotary
5. Top Drive
:
:
:
:
:
4 x Caterpillar D399, xxx HP ea. with xxxx KW generator
2 x EMD M79 – 750 HP ea.
2 x EMD M79 – 750 HP ea.
1 x EMD M79 – 750 HP ea, Torque xxx Amps / xxxxx ft.-lbs
1 x GE 752 – 1000 HP, Torque xxx Amps / xxxxx ft.-lbs
Mud System & Pump
1. Mud Pumps
2. Mud pits & storage
3. Shale Shakers
4. Desander / Desilter
5. Centrifuge
6. Degasser
:
:
:
:
:
:
2 x C. Emsco FB-1600, 1600 HP ea
1900 bbl. Capacity (active and reserve) 60 bbl trip tank
3 x Derrick Flo-Line Cleaner
Brandt model? xxxx GPM? / None
Mission Fluid, 11-1/2” impeller, xxxx GPM
Brandt model?, xxxx GPM
BOP Equipment
1. Accumulator
2. Choke manifold
3. BOPs
:
:
:
Type 80, Koomey
5000 psi WP, sour service
Shaffer 30” annular – xxx psi, Make? 13-5/8” annular – xxx psi,
Cameron Type-U 13-5/8” single ram – 5000 psi
Cameron Type-U 13-5/8” double ram – 5000 psi.
F)
Safety Equipment
:
H2S & Combustible Gas Monitoring System, Fire/Smoke Detection
system, Portable H2S & Combustible gas monitors, 2 x 300 GPM
fire pumps, CO2 system in Engine Room/SCR/Gen/Paint rooms,
Sprinkler System in accommodations, Heli-deck Foam system,
Cascade Breathing System, 2 x 50man Lifeboats and Life rafts, 1 x
Fast Rescue Craft.
G)
Drill Pipe & Drill Collars
1. Drill Pipe
2. HWDP
3. Drill collars
:
:
:
5” Grade G, 19.5lbs/ft, 8000 ft. 3 ½” Grade G, 13.3 lbs/ft, 10,500 ft.
112 of 5”, 90 of 3 ½”
15 of 8 ½”, 20 of 6 ¼”, 20 of 4 ¾”
:
:
:
:
:
20,000 ft
230 ft
60’ Max. forward / backward movement
10’ Transverse on each side from center line of hole
Upper – 32’ (Derrick Floor to Base of Cantilever)
Lower – 18’ (Derrick Floor to Base of the Hull)
– 42’ (Base of Hull to Top of Jack Housing)
xxx Kips
xxx people
C)
D)
E)
H)
102 of 102
Design Criteria
1. Depth Capacity
2. Max. Water Depth
3. Cantilever
4.
Sub-Structure
5.
6.
Variable Deck Load :
Accommodation
:
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
G
June 2006
GENERAL INFORMATION
RIG CONTRACTS
___________________________________________________________________________________________________________________________
RIG CONTRACTS
1.0
GENERAL INFORMATION
1.1 The Document
1.2 Conditions
1.3 Amendments
2.0
CONTENTS OF A RIG CONTRACT
2.1 Schedule “A”
2.2 Schedule “B”
2.3 Schedule “C”
2.4 Schedule “D”
2.5 Schedule “E”
2.6 Schedule “F”
2.7 Schedule “G”
2.8 Schedule “H”
3.0
ABIDING BY THE RIG CONTRACT
3.1 Responsibilities
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
G
June 2006
GENERAL INFORMATION
RIG CONTRACTS
___________________________________________________________________________________________________________________________
RIG CONTRACTS
1.0
GENERAL INFORMATION
1.1
The Document
The contract is an agreement between Saudi Aramco (the Company) and the
Contractor, which clearly defines the equipment and services that are to be
provided by the Contractor to the Company. It also documents the
Company’s obligations towards the Contractor. The contract consists
primarily of a signed document with attached schedules, drawings, standard
specifications, and any other pertinent references/documents.
1.2
Conditions
The following are some key conditions of the existing rig contracts:
A)
B)
C)
D)
1.3
The contract has a specified time limit, which means that the conditions
of the contract have to be met by both the Contractor and the Company
for as long as the contract is in effect. At the end of the specified
contract period, there usually is a provision to extend the contract at the
discretion of the Company. At the end of the contract term, the
Company has the option of not renewing the contract or renegotiating
the contract for another term.
When the Company decides to terminate a contract at its own
convenience, prior to the term expiration date, the contract provides for
compensation payment to the Contractor at a pre-determined rate.
When there are disputes or different interpretation of the contract
conditions by both parties, the contract provides for problem resolution
through arbitration.
The contract is very specific in identifying the minimum equipment and
services that are to be provided by the Contractor for drilling and
working over wells with a rig. At the same time, the Company has
certain responsibilities and obligations that are also spelled out in the
contract. Section 2.0 below summarizes the key items of the contract.
Amendments
When an addition or change to the signed and approved contract is
necessary, and waiting for end-of-term contract renewal is not an option, then
an Amendment is issued. The Amendment can replace any clause or
statement in the original contract and is valid until the contract is terminated
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CHAPTER 1
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G
June 2006
GENERAL INFORMATION
RIG CONTRACTS
___________________________________________________________________________________________________________________________
or expires. It is important to note that an Amendment cannot take effect
unless both the Company and the Contractor agree to the contents by signing
the document.
2.0
CONTENTS OF A RIG CONTRACT
2.1
Schedule “A”, General Terms and Conditions
This section of the contract addresses the following:
A)
B)
C)
D)
E)
F)
G)
H)
I)
J)
K)
L)
M)
N)
O)
P)
Q)
R)
S)
T)
2 of 7
Definition of terms used in the contract
Qualification and requirements of Contractor’s personnel
Access to well location by contractor
Housing and medical responsibilities of Contractor for its personnel
Inspection and testing of Contractor equipment
Contractor’s warranty of defect-free equipment, materials and
workmanship
Contractor’s and Saudi Aramco’s liabilities in cases of loss, damage,
and injury.
Required Insurance coverage of the contractor.
Contractor’s responsibility to prevent pollution and liability in case it
does occur.
Both Contractor and Saudi Aramco will use tools, equipment or material
that have valid patents, trademarks and are not trade secrets of another
company.
Claims settlement.
Contractor’s and Saudi Aramco’s positions when work cannot be
performed due to uncontrollable situations such as storm, strikes, etc.
This is known as ‘Force Majeure’.
Saudi Aramco’s recourse when the Contractor does not meet
performance expectations.
Termination of contract for cause.
Termination of contract at Saudi Aramco’s convenience.
Contractor’s obligation to keep Saudi Aramco information confidential.
Limits of what the contractor can offer to Saudi Aramco employees so
as not to influence the awarding of any contract.
Conditions under which work can be subcontracted out to a third party.
Contractor’s obligation to obtain approval prior to releasing any
information from this contract for publicity reasons.
Where possible, the contract should be translated into Arabic except for
sections C & G which are highly technical in nature.
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
G
June 2006
GENERAL INFORMATION
RIG CONTRACTS
___________________________________________________________________________________________________________________________
U)
V)
2.2
Contractor is responsible for conducting all Government relations
activities within Saudi Aramco. If requested, Saudi Aramco may provide
general guidance.
General provisions.
Schedule “B”, Scope of Work and Technical Provisions
A)
B)
C)
D)
E)
F)
G)
H)
I)
J)
Introduction.
Contractor’s responsibility to drill, core, test complete, workover,
abandon and perform other rig operations.
Well Programs: Saudi Aramco will provide the Well Programs, 18,000’
is the maximum drill depth unless agreed by both parties, some wells
might be horizontal, Company shall notify Contractor at least 24 hours
before rig release, and downhole tools and tubulars are subject to 0-8%
H2S exposure.
Casing: The Well Program will dictate the hole size, depth and size of
casing to be run. The casing will be run and cemented per Program.
Surveys: Sets the guidelines for single shot surveys in vertical and
directional wells.
Drilling Fluids: The Company will determine the type of drilling fluid to
be used and the Contractor will maintain the fluid characteristics.
Measurements: Contractor will measure drill string length with steel tape
whenever requested by the Company.
Contractor shall be ready to commence operations on the date specified
in this section.
Contractor shall perform the work on a 24 hour, 7-day a week basis.
Contractor shall provide its own office and workshop facilities in a local
community.
Contractor shall provide all services, equipment, machinery, tools,
instruments, materials, supplies, support personnel and labor when
performing rig work.
Contractor is obligated to make all reports to and receive from the
Company Representative on rig activities.
Contractor shall drill wells according to acceptable industry practices.
Contractor will also clean location within 5 days of rig release or well
abandonment.
If a hole is damaged or lost due to Contractor’s negligence, then
reimbursement payment will be made to the Company.
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DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
G
June 2006
GENERAL INFORMATION
RIG CONTRACTS
___________________________________________________________________________________________________________________________
2.3
Schedule “C”, Contract Price and Payment Provisions
In this section of the contract, the following are covered:
A)
B)
C)
D)
E)
F)
G)
Contract pricing conditions
Payable rates for mobilization, demobilization, daywork, special
daywork rate, downtime, rig and camp move rates, meals, force
majeure, equipment and services
Termination for cause or at Saudi Aramco’s convenience
Handling of Invoices and currency of payment
Saudi Aramco’s rights to audit the contractor’s books and records
Adjustment of rates and deductions/reimbursements of equipment and
services
Setoff. This is Saudi Aramco’s right to deduct amounts that are due and
payable to the contractor
The appendix at the end of this section contains the actual rig rates for labor
related items and services performed.
2.4
Schedule “D”, Safety, Health and Environmental Requirements
The main topics covered in this section include:
4 of 7
A)
General Provisions
•
Compliance with safety, health and environmental requirements
•
Deviations from Safety Requirements
•
Failure to comply
•
Saudi Aramco Assistance
B)
Safety and Health Requirements
•
Loss prevention program
•
Work permits
•
Well control
•
Personnel safety
•
Welding and cutting equipment
•
Personal protective equipment
•
Tools and portable power tools
•
Cartridge operated tools
•
Electrical installations and equipment
•
Cranes and rigging equipment
•
Mechanical equipment
•
Saudi Aramco plant operations
•
Transportation
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
June 2006
GENERAL INFORMATION
G
RIG CONTRACTS
___________________________________________________________________________________________________________________________
•
•
•
•
•
•
•
C)
2.5
Injury and damage reporting
Work over/or adjacent to water (Gulf)
Fire Prevention
Ionizing Radiation
First Aid Facilities
Explosives
Contractor Camps
Environmental Requirements
•
Introduction
•
Applicable Saudi Aramco and/or other engineering requirements
•
Waste management program
•
Water supply protection
•
Wastewater management
•
Spill control
•
Solid waste management
i)
Waste disposal program
ii)
Containers and storage
iii) Hazardous waste storage and handling
iv) Method of collection
v)
Requirements for establishing a landfill disposal site
vi) Classification of landfill disposal site
vii) Solid waste disposal, site design and operations
viii) Offshore disposal
•
Air pollution mitigation
•
Noise control
Schedule “E”, Settlement of Disputes, Arbitration and Choice of Law
This section of the contract defines the procedures for the Contractor to file a
claim against the company. It also addresses the steps involved towards
settling a claim through arbitration.
2.6
Schedule “F”, Taxes, Duties and Obligations
In this section, Contractor’s tax liabilities to the Kingdom are discussed, along
with recourse when tax payments are delinquent. Also, custom clearance
and duties, plus reimbursement to Saudi Aramco are presented.
5 of 7
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DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 1
SECTION
G
June 2006
GENERAL INFORMATION
RIG CONTRACTS
___________________________________________________________________________________________________________________________
2.7
Schedule “G”, Saudi Aramco & Contractor Supplied Materials, Tools,
Equipment and Services.
In this section, the following main points are addressed:
A)
B)
C)
D)
E)
F)
G)
H)
Contractor’s and the Company’s obligation statement to supply items
and services.
The Company’s discretion of providing items for rent which the
Contractor is responsible for.
Contractor’s obligation to rent items at the Company’s request.
Inspection and reporting of defective items when the Contractor rents
items from the Company.
Condition and maintenance of Contractor’s ancillary equipment.
Care of materials, tools and equipment rented from the Company.
Maintenance of Company supplied tools and equipment.
Contractor’s right to obtain a refund on custom duties when re-exporting
tools and equipment OOK.
Attachment 1 is a detailed listing of the Contractor supplied minimum
equipment and services. This includes
A) Rig and Ancillary Equipment
Drawworks, power units, mud pumps, mast and substructure; BOP
equipment, crown block, traveling block, hook, swivel; drill pipe
elevators and slips; drill collar elevator and slips; kellys and kelly
spinner; rotary table and top drive systems; spinning wrench; mud
mixing unit, mud tanks, mud mixers, trip tank, flowline cleaners,
desander, desilter, mud cleaners, rotary hoses, air hoist, etc.
B) Other Supplies and Equipment
Drilling water, fuel and lubricants, potable water, safety equipment,
internal communication, and mud material storage boxes.
C) Services
Transportation for rig move and other equipment/materials, field camp
facilities and requirements, and electrical repairs/maintenance of
Company owned equipment at rig site.
D) Deep remote desert additional requirements
One 30-ton minimum grove rough terrain crane (or equivalent) with 24hour operator.
Attachment 2 itemizes the equipment and services that the company shall
provide. These are
A) Wash pipe, wash over shoes, handling tools, etc.
B) Fishing tools
C) Roads and locations
D) Drilling water
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Drilling & Workover Engineering Department
CHAPTER 1
SECTION
June 2006
GENERAL INFORMATION
G
RIG CONTRACTS
___________________________________________________________________________________________________________________________
E)
F)
G)
2.8
Radio equipment for communication
Transportation
Equipment not supplied by Contractor, as specified in the contract.
Drill pipe elevators and slips, back pressure valves and kelly cocks,
drill pipe safety valves, drill pipe, drill collars and subs, and heavy
weight drill pipe.
Schedule “H”, Special Terms and Conditions
This section covers the following:
A)
B)
C)
D)
E)
F)
G)
H)
I)
3.0
Contractor workforce Saudization.
The land which the Company has to provide to the Contractor for its use
as a yard, storage area and office structure.
Right of the Company to extend term of the contract by one year.
Payment conditions to the Contractor in case of early termination of
contract.
Reaffirming Contractor’s handling and disposal of hazardous material in
accordance with acceptable industry practices.
Contractor approval requirements prior to camp move.
Financial penalties in case Contractor cannot commence on specified
date.
The right for the Contractor to rent required tools/equipment from a third
party.
The Company’s option to elect not to utilize the Topdrive unit.
ABIDING BY THE RIG CONTRACT
3.1
Responsibilities
The Drilling Foreman has the responsibility of ensuring the Contractor meets
the contract obligations while drilling or working over a well. He should be
very familiar with terms of the contract and ask his Superintendent for advice
when unsure. He should know which piece of equipment or service is to be
supplied by the Contractor, and which by the Company. Whenever he
observes contract violations, it is his duty to notify the Contractor for
immediate correction. If the violation is not corrected within a reasonable
time, then the Drilling Foreman should highlight the problem to his
Superintendent for further action.
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SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
A
June 2006
DRILLING PRACTICES
WELL LOCATIONS
__________________________________________________________________________________________________________________________
WELL LOCATIONS
1.0 INTRODUCTION
2.0 CONSTRUCTION REQUIREMENTS
2.1
2.2
2.3
2.4
2.5
2.6
General Specifications
2.1.1 Development Locations
2.1.2 Exploration Locations
2.1.3 Drilling Islands
Location Specifications for Different Rigs
Access Road
Rig Campsite
Cellar
Clean Up Operations
3.0 WELLSITE SAFETY REQUIREMENTS
3.1
3.2
General Spacing Requirements
Producing Wells in Populated Areas
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
A
June 2006
DRILLING PRACTICES
WELL LOCATIONS
__________________________________________________________________________________________________________________________
WELL LOCATIONS
1.0
INTRODUCTION
Preparation of the drillsite location is a comprehensive process. It involves
locating/building the site to (a) meet construction specifications, (b) accommodate
rig dimensions, and (c) comply with well safety requirements. This chapter will
discuss the construction and wellsite safety requirements for Saudi Aramco
onshore well locations.
2.0
CONSTRUCTION REQUIREMENTS
2.1
General Specifications
2.1.1
Development Locations
Surveying Services Division will set the preliminary positions of
development well locations. A site review committee shall visit the
location to determine the feasibility of wellsite construction at the
proposed surface location. If the well location is moved for
construction purposes, an authorized person from Reservoir
Engineering and Facilities & Projects Division shall approve the move.
Drilling and Workover Engineering will be informed of the magnitude
and direction of move. Final survey sheets will indicate the direction
and distance of move, reason for moving location, names of
representatives from Wellsites, Facilities & Projects, and Loss
Prevention.
General specifications for Development well location construction are
as follows:
A)
The preferred orientation of the well location is East/West and
drainage to South.
If topography dictates a North/South
orientation, drainage should be to the East. Drainage should
never be West or North.
B)
The required well location sizes for the Saudi Aramco onshore
rigs are as follows:
SAR-151:
SAR-153:
SAR-103:
130m x 100m
122m x 117m
100m x 90m
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2.1.2
C)
Development well locations for active Nadrico rigs are
constructed 122m x 91m, with the exception of NAD-212 which
is 130m x 100m.
D)
Development well locations for active Pool Arabia rigs are
constructed 122m x 91m in the local area and 122m x 122m in
central area.
E)
Development well locations for active Arabian Drilling Company
rigs are constructed 122m x 100m.
F)
Flare line and flare pit construction is in accordance with Saudi
Aramco Engineering Standard; SAES-B-062 dated January 23,
1995 for Onshore Wellsite Safety.
G)
The finished location should be capped with 0.3m dry marl and
0.15m wet compacted marl.
Exploration Locations
The Exploration Department will set the preliminary position of
exploratory well locations. If the proposed location is in an inhabited
area, a full site review committee will be required. The review will be
limited to the Wellsites representative when the location is in a remote
area. If the well location is moved for construction purposes, an
authorized person from Exploration shall approve the move.
General specifications for Exploration well location construction are as
follows:
A)
The preferred orientation of the well location is East/West and
drainage to South. Drainage should never be West or North.
B)
Khuff/Pre-Khuff gas well locations for the current rigs are
constructed 152m x 136m with cellar orientation East/West,
drainage to South, and two flare pits. The only exceptions are
the Santa Fe rigs, which require a 161m x 133m location.
C)
Each rig has its own designed drainage area and offset for flare
line road.
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2.1.3
D)
Each Exploration location will have a water well location
constructed 90m x 90m (a minimum of 500m North of the
location) and a campsite 90m x 60m (a minimum of 1000 m
North of location). All Khuff/Pre-Khuff gas well campsites should
be 3-4kms, preferably North of drillsite location.
E)
The gas buster dike will be constructed on the South side of the
location (305m long).
F)
The finished location should be capped with 0.3m dry marl and
0.15m wet compacted marl. Water well locations and campsites
should be capped with0.3m dry marl.
G)
Flare line and flare pit construction is in accordance with Saudi
Aramco Engineering Standard; SAES-B-062 dated January 23,
1995 for Onshore Wellsite Safety.
Drilling Islands
A drilling island is a multiple well pad, which enables the drilling of
more than one development well from the same well location. This
practice is used in areas where topography limits feasible drillsites, as
in the Shaybah Field.
General specifications for drilling island construction are as follows:
A)
The preferred orientation of the drilling island is East/West and
drainage to South. If topography dictates a North/South
orientation, drainage should be to the East. Drainage should
never be West or North.
B)
The well spacing on the drilling island should be 50m minimum.
C)
Drainage area, flare line dike, and flare pit position/ dimensions
should conform to the relevant drilling rig development location
specifications.
D)
The finished location should be capped with 0.3m dry marl and
0.15m wet compacted marl.
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2.2
Location Specifications for Different Rigs
The following diagrams illustrate the location layout and dimensions required
for the active rigs currently operating in Saudi Aramco (also included are
stacked rigs, which may be activated in the future).
Note: Location drawings with the second flare pit on Khuff/Pre-Khuff wells
will be addressed in future manual updates.
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SAR-151
LOCATION: 130m x 100m
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SAR-153
LOCATION: 122m x 117m
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SAR-103
LOCATION: 100m x 90m
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ADC-3
LOCATION: 122m x 100m
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ADC-4 and 12
LOCATION: 122m x 100m
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ADC-14
LOCATION: 122m x 108m
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NAD-60 and 88
LOCATION: 122m x 91m
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NAD-283, 284, & 288
LOCATION: 130m x 115m
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NAD-211
LOCATION: 130m x 100m
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NAD-212
LOCATION: 130m x 100m
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PA-201
LOCATION: 122m x 91m
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PA-214
LOCATION: 122m x 91m
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PA-215
LOCATION: 122m x 91m
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PA-235
LOCATION: 122m x 91m
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PA-236
LOCATION: 122m x 91m
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ADC-15 and 21
LOCATION: 152m x 136m
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DPS-43, 44, & 45
LOCATION: 152m x 136m
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PA-202
LOCATION: 152m x 136m
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PA-203
LOCATION: 150m x 130m
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PA-304
LOCATION: 152m x 136m
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NAD-70
LOCATION: 150m x 130m
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NAD-117
LOCATION: 152m x 136m
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SF-173 and 174
LOCATION: 161m x 133m
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2.3
Access Road
General specifications for access (skid) road construction are as follows:
2.4
A)
Development and Exploration skid roads should be 14m or 21.5m in
width (depending on the size of rig) with marl 9m wide (0.30m thick)
longitudinally along the center.
B)
The edge of 9m marl should be taken down at a 1 to 1 slope to
shoulders.
C)
If the skid road is constructed over 1m above the existing ground level,
then the embankment slopes should be at a maximum gradient of 1 to 4
(25 percent grade).
D)
The maximum inclination of the access road should be 1 to 20 (5
percent grade).
E)
Skid roads in Shaybah should be constructed with marl 1.0m thick for
the full width of the skid road. Embankment slopes should be at a
maximum gradient of 1 to 4 (25 percent grade).
F)
The minimum radius of curves should be 70m. In the case of SAR-151
and SAR-153, the minimum radius will be 152m. Access road curvature
for larger Exploration rigs is not as critical, as all loads are broken down.
G)
Junctions with other skid and black top roads should be widened with a
minimum filet size of 30m x 30m.
Campsites
General specifications for campsite construction are as follows:
A)
The standard campsite for all rigs consists of 90m x 60m with a 0.30m
marl cap.
B)
The campsite should be within a distance of 5kms from the location. On
Khuff gas wells, the campsite shall be no less than 3-4kms and
preferably North of the location.
C)
Wellsites will determine if an existing campsite will fit the above
specifications or if a new campsite is to be constructed.
D)
A garbage pit and sump pit will be constructed at the campsite.
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2.5
Cellar
General specifications for cellar construction are as follows:
A)
The Construction Engineering Supervisor should approve the final
elevation of the well location before construction of the cellar begins.
B)
The cellar work should start prior to the actual pad construction. This
will identify problems with hard rock in the cellar area.
C)
If the cellar is located over hard rock, the Construction Engineer will
determine whether or not there is a need to excavate or raise the
location elevation to save time.
D)
Excavation size should include 25m x 25m with cellar centrally located.
The depth of cellar should be 0.30m deeper than required to allow for a
pad of compacted marl, which will provide an adequate base for cellar.
Ramps should be built on both sides of the cellar to allow for access of
construction equipment.
E)
The Construction Engineering Supervisor will arrange for cellar delivery.
An inspector will be assigned to escort the crane and cellar to location.
A surveyor will be on site to ensure the cellar is properly set.
Arab-D Cellar:
3m in diameter (fiberglass pipe)
4’ deep for vertical and horizontal wells
Hanifa Cellar:
3m in diameter (fiberglass pipe)
4’ deep for vertical wells
5’ deep for horizontal wells
Khuff/Expl. Cellar:
20’ x 12’ (steel box)
14’ deep
F)
Controlled fill procedures will be required over the area within 25m of
the cellar. Marl should be placed in layers of uniform thickness not
exceeding 15cm after compaction with a heavy vibratory drum roller.
Each compacted lift should be tested for density and material gradation
prior to placing additional lifts.
G)
The Construction Engineering Supervisor will arrange to install a fence
around the cellar after completing construction.
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2.6
Clean Up Operations
Wellsite clean up operations will begin the day the rig moves to the next
drilling location. The goal of Wellsites Division is to complete the clean up no
later than 7 days after the rig move. General specifications for clean up
operations are as follows:
3.0
A)
Location and campsite will be graded if deeply rutted or badly marked.
B)
Any washouts or excavations on location will be filled with marl.
C)
All pits will be back filled after removing liquid with material from
surrounding dikes (or sand if dike material is not adequate) for both
location and campsite.
D)
All refuse, garbage, and debris will be collected within 90m of the well
location and campsite.
E)
Cellars on Arab-D wells and Khuff wells should not be filled with sweet
sand at rig release.
F)
Any re-usable drilling material remaining on the wellsite/campsite will be
noted and reported to the Wellsites Supervisor.
WELLSITE SAFETY REQUIREMENTS
3.1
General Spacing Specifications
The following spacing requirements regarding wellsite safety are taken from
Engineering Standard SAES-B-062 (as shown in Appendix 2A). These
specifications apply to onshore oil/gas wells with shut-in wellhead pressure <
3600 psi. All oil/gas wells with shut-in wellhead pressure > 3600 psi and all
gas injection wells are to be determined by a case by case basis, with
concurrence with the Chief Fire Prevention Engineer.
A)
The minimum distance from an adjacent well to outer edge of wellsite
location shall be 105m.
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B)
The minimum distances from flare pit to control point are as follows:
Flare pit to overhead power lines (150m)
Flare pit to cathodic protection (105m)
Flare pit to highway/camel fence/paved road/railroad (105m)
Flare pit to above ground pipelines (60m)
Flare pit to under ground pipeline (15m)
3.2
C)
A minimum distance of 450m from wellsite to any of the following:
process areas; major shipping pump, blending/booster pump, or fire
pump areas; tetraethyl lead (TEL) facilities; LPG loading racks;
atmospheric or pressured vessels; boilers and power generation
facilities; major electric distribution centers; buildings, property lines,
and residential areas.
D)
The minimum distance from oil/gas wells to overhead power lines is
200m.
E)
The minimum distance from oil/gas wells to cathodic protection or other
noncritical power lines is 105m.
F)
A minimum distance of 105m from oil/gas wells to any of the following:
right-of way, camel fence, Saudi Aramco or Government highway,
paved roads, or railroads.
G)
The minimum distance from oil/gas wells to pipelines is 105m.
H)
Water gravity injectors, power injectors, or supply wells must have a
105m spacing requirement from all other facilities.
Producing Wells in Populated Areas
The following requirements apply to producing wells in populated areas. In
addition, these requirements may also apply to wells that are located near
areas of potential concern, such as roads, parking areas, or campsites. The
Proponent Operating/Engineering Department shall determine whether these
additional precautionary measures are taken.
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A)
On oil wells, the upper wellhead master valve shall be a spring assisted
fail-safe Surface Safety Valve (SSV), triggered when an abnormally low
pressure is sensed. Triggering by abnormally high pressure is required
only when necessary to protect the downstream flowline. A fusible
device with a melting point 30 degrees Celsius above the higher of the
flowing wellhead temperature or maximum design ambient temperature,
shall be installed on the wellhead to trigger the SSV.
B)
A Sub-Surface Safety Valve (SSSV) per API RP 14B specification shall
be installed more than 60m below ground level in oil/gas wells. The
SSSV shall be controlled by the low pressure pilot. Closure triggered by
an abnormal condition in the high pressure piping downstream of the
choke shall be provided when required by the Proponent Operating
Department. A fusible device with a melting point 30 degrees Celsius
above the higher of the flowing wellhead temperature or maximum
design ambient temperature, shall be installed on the wellhead to
separately trigger the SSSV.
C)
Wellsites in populated areas shall be enclosed by a fence meeting the
specifications of SAES-M-006 (Type III). The fence shall have four
lockable vehicle gates, one in each quadrant. Two gates shall be 18m
wide rig-access gates. The location of these rig-access gates will permit
access to all wells on the wellsite.
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JUNE 2006
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CASING
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CASING
1.0
CASING DESIGN FACTORS
2.0
CASING POINT REQUIREMENTS
2.1
Abqaiq Field
2.2
Ain Dar Field
2.3
Abu Hadriya Field
2.4
Abu Jifan Field
2.5
Abu Safah Field
2.6
Berri Field
2.7
Dammam Field
2.7
Fadhili Field
2.9
Fazran Field
2.10 Haradh Field
2.11 Harmaliyah Field
2.12 Hawiyah Field
2.13 Khurais Field
2.14 Khursaniyah Field
2.15 Manifa Field
2.16 Marjan Field
2.17 Mazalij Field
2.18 Qatif Field
2.19 Qirdi Field
2.20 Rimthan Field
2.21 Safaniyah Field
2.22 Shaybah Field
2.23 Shedgum Field
2.24 Uthmaniyah Field
2.25 Zuluf Field
3.0
CASING INSPECTION
3.1
Khuff, Deep & Exploration Wells
3.2
Development Wells
4.0
SAUDI ARAMCO CASING DATA
5.0
KHUFF CASING & TUBING DATA
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JUNE 2006
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CASING
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CASING
1.0
CASING DESIGN FACTORS
Exact values of loading are difficult to predict throughout the life of the well. For
example, if mud of 75 pcf is on the outside of the casing during the running of the
casing, this value cannot be expected to remain constant for the entire life of the
well. The mud will become deteriorated with time and will reduce this value to
perhaps a saltwater value of 64 pcf. Therefore, calculations of burst values
assuming a column of mud at 75 pcf are not realistic throughout the life of the well.
If the initial casing design is marginal, then over a period of time a tubing leak may
result in casing burst.
Since casing design is not an exact technique and because of the uncertainties in
determining the actual loading as well as the deterioration of the casing itself due
to corrosion and wear, a safety factor is used to allow for such uncertainties in the
casing design and to ensure that the rated performance of the casing is always
greater than any expected loading. In other words the casing strength is always
down rated by a chosen design factor value.
The minimum casing design factors for Saudi Aramco are as follows:
Collapse:
Tension:
Burst:
1.125
1.6
1.33
The design factor is the ratio of the rated casing strength/resistance to the
magnitude of the applied force/pressure.
Note:
x
x
x
x
The biaxial effect to tension on casing collapse should be calculated in
addition to using these design factors.
The biaxial effect of tension on casing burst is not required as this is an
additional safety factor.
The minimum design factor for tension assumes bouyancy and applies to
the weakest point (pipe body or joint strength).
Other assumptions (such as the extent of casing evacuation, H2S service
and maximum SICP) will vary with the well type and casing string.
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2.0
CASING POINT REQUIREMENTS
2.1
Abqaiq Field
26” Conductor Pipe
This is set at 100’± below the surface. It serves to keep the unconsolidated
sand from washing out under the rig. Actual size of the casing used for this
may vary, depending upon the well program.
18-5/8” Casing Point
Nominal casing point is the top of the RUS formation. Actual setting depths
have varied widely over the years. It has been set as high as the top of the
Eocene. Range is from 315’ above to 201’ below the top of the RUS, with
most in the range of 25’ above to 50’ below the top.
The purpose of the string is to separate the waters of the Alat and Khobar
from the Umm er Radhuma water, and to support the hole after circulation is
lost in the Umm er Radhuma) Static water level + 85’ mean sea level).
The casing point is readily picked on samples, at the first occurrence of a
chalky white gypsiferous anhydrite. This point may also be picked on drill
time. Drill time decreases at the top of the RUS, as the lithology changes
from blue and gray marl and the thin brown shale of the Midra to a thin
limestone and the soft anhydrite.
13-3/8” Casing Point
Nominal casing point for the string is 50’ into the Lower Aruma shale. Actual
setting depths have varied from 990’ above the Lower Aruma shale (stuck
casing) to 375’ below the top.
The purpose of the casing is to shut off the lost circulation zone of the Umm
er Radhuma from the water flow of the Wasia, and allow drilling the Wasia
with mud to control the water. Since this interval is usually drilled without
returns, the top of the lower Aruma shale must be picked on drill time. It is
generally characterized by a gradual decrease in drill time and may be
determined by comparison with nearby wells. The lithology at the upper
portion of the Lower Aruma shale, as picked in the Abqaiq field, is actually
limestone.
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In crestal part of the field the section between pre Aruma unconformity and
K.S. Member is eroded and not possible to pick lower Aruma shale from drill
time. In such cases setting 13-3/8” casing 50-100’ above the Pre Aruma
unconformity or 600-800’ below Aruma will be adequate.
9-5/8” Casing Point
Nominal casing point is 300’ into the greenish-gray shale (Biyadh formation).
Actual setting depths have varied from 290’ above to 525’ below the top, with
most in the range of 250-350’ below the top.
The purpose of the casing is to shut off the lost circulation of the Dolomitic
Limestone (Shu’aiba) and allow water drilling of the section below, to the top
of the Arab-D zone.
The section between the 13-3/8” and 9-5/8” casing points is drilled with mud
to control the Wasia water, and prevent the Wasia shales from sloughing.
Circulation is occasionally lost in the Wasia. If returns can not be gained by
LCM pills or cement plugs, then drilling from this point to the casing point
must be done with mud and mud cap across the Wasia. Circulation is
commonly lost in the Dolomitic Limestone (Shu’aiba), and drilling from this
point to the casing point is done with water and a mud cap across the Wasia.
The upper portion of the greenish-gray shale is water sensitive, if exposed for
more than a short period of time. In order to drill the section below with water,
the casing must be set through this upper section. Probable minimum safe
setting point for this is 200’ below the top. Since the actual thickness of the
water-sensitive section may be variable, well programs should specify 300’
penetration.
In recent injection and observation wells the 9-5/8” is programmed to be set
in the Mid-Thamama L.S. This gets all the Biyadh sand and shales behind
the casing and improves coring conditions in the formations below.
Top of Mid-Thamama is a slight increase of drill time but it is not a good pick
on the drill time log. A fairly good estimate can be made by projecting from
the Biyadh top and by comparing with offset wells.
The section to the top of the Arab zone may be drilled with water, but mud
should be used in the Arab-D reservoir. The change may be made while
drilling the anhydrite section just above the D reservoir, or at the casing point
if 7” is to be set above the reservoir.
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7” Casing Point
Nominal casing point is at the top of the Arab-D Reservoir, or below the base
of the porosity if the set-through option is used, as in the more recent wells.
Actual casing points have varied from 191’ above to 18’ below the top, with
most in the range of 10-50’ above. Those that have been set through the
reservoir have ranged from 219-301’ below the top.
The top of the Arab-D may be picked on samples or drill time. The casing
point can be determined readily by comparison of the drill time pattern
through the Arab zones with nearby wells.
In recent wells 7” casing is programmed to be set below the base of Hanifa
Reservoir. The top of the Hanifa can be easily picked off the drill time log.
The drill time shows a marked decrease. The base of porosity can also be
determined readily by drill time comparison with offset wells.
2.2
Ain Dar Field
26” Conductor Pipe
This is set at 100’± below the surface. It serves to keep the unconsolidated
sand from washing out under the rig. Actual size of casing used for this may
vary, depending upon the well program.
18-5/8” Casing Point
Setting point for this casing is the top of the Eocene. Nominal point is 50’
below the Eocene-Neogene unconformity, but actual setting depths have
varied from 23 to 236’ below the unconformity with most strings in the 50-100’
range. The lithologic unit directly below the unconformity may be either the
Alat limestone or the Alat marl (“Orange Marl” depending on location. Actual
size of casing used for this may vary.
Most wells in the area have been drilled without setting casing in the Eocene
using only a short conductor pipe, until setting 13-3/8” in the Lower Aruma
shale.
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The purpose of the string is to separate the Neogene and Eocene aquifers,
and to support the sides of the hole while drilling with lost circulation below
the casing point. Obviously, in places where the Neogene is composed of
competent beds, it is not needed for this purpose. The data below, taken from
water well records, shows a marked difference in static water levels (SWL) of
the aquifers in the area, with the lower units having the lower SWL’s. This
means that if the aquifers are left in communication, some drainage of the
upper aquifers may result, with the exception of the Neogene, which may be
recharged. However, it is believed that the volumes concerned would be
small.
Water Data
Aquifer
Neogene
Alat
Khobar
RUS
Umm-er Radhuma
Aruma
450’
520’
460’
440’
415’
375’
SWL
MSL
MSL
MSL
MSL
MSL
MSL
Total Solids (ppm)
1600-7200
±1800
±1800
±3600
±1800
±1800
Circulation has been lost in all of the above units at one place or another in
Ain Dar.
The top of the Eocene is picked on the change from sandy limestone or marl
above the unconformity to non-sandy limestone or marl below. It can usually
be picked on an increase in drill time at the contact. Where circulation is lost
above the unconformity, drill time must be relied on. In high structural wells,
where the unconformity cuts into the Alat marl, drill time may decrease
sharply at the contact.
13-3/8” Casing Point
Nominal casing point is 50’ into the Lower Aruma shale or Ahmadi limestone.
Purpose of the casing is to separate the Wasia water sands from the
overlying aquifers. The Wasia has a pressure about 190 psi greater than the
overlying formations so that a large upward flow is possible. The casing point
should be below possible lost circulation zones in the Aruma and Ahmadi
formations so that circulation can be maintained while drilling the Wasia with
mud.
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In several wells, circulation was lost while drilling the Upper Wasia after
cementing 13-3/8” casing in the Lower Aruma Shale. If nearby wells show
lost circulation in the upper Wasia, it is advisable to set the 13-3/8” casing 50’
into the Ahmadi limestone.
The Lower Aruma shale may be difficult to pick from drill time, but a fair
estimate can be made. The Ahmadi is a much clearer pick.
9-5/8” Casing Point
The 9-5/8” casing is set in the top of the greenish-gray shale (Biyadh
formation). Nominal point is 300’ below the top, but actual setting depths
have varied with most wells in the 250-350’ range.
Purpose of the casing is to shut off the lost circulation zone of the Dolomitic
limestone (Shu’aiba formation) and/or the Wasia sands. It must also be set
through the hydroscopic, sloughing shales at the top of the greenish- gray, so
that the section below the casing point can be drilled with water. Thickness
of these shales varies from place to place. Probable absolute minimum safe
setting depth for this casing is 200’ below the greenish-gray top. Otherwise,
mud will have to be used to control the shale, and drilling will be slower,
particularly through the Hith anhydrite section.
Top of the Dolomitic limestone (Shu’aiba formation) is easily recognized both
on samples and drilling time from the fast drilling sands and shales of the
Wasia above it. Loss of circulation shortly thereafter is also a sure indication,
although circulation may also be lost above the contact in the Wasia.
Top of the greenish-gray shale is less easy to pick, but usually is
characterized by decreased drill time at the contact. Thickness of the
Shu’aiba is usually 200-250’, which helps to locate the greenish-gray top.
Drill time comparison with nearby wells serves to locate it.
7” Casing Point
The 7” casing is the production string. It has normally been set just above
the top of the Arab-D Reservoir but some trouble has been encountered with
the so called sub-C stringer. This is a water bearing stringer just above the D
reservoir, and as the reservoir pressure declines, the water has a tendency to
break through into the oil zone around the casing shoe. Several wells have
had to be worked over for this reason.
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The section from the 9-5/8” casing point to the top of the Arab-D is drilled with
water. It consists of sand, some thin shales, and a thick section of limestone
and anhydrite. The Yamama Detrital zone (Sulaiy formation) flows a modest
amount of hot (180o) water, but this has no effect on the drilling operation.
The change to mud is usually made while drilling the anhydrite just above the
D reservoir. Relatively light mud must be used to drill in with to avoid lost
circulation.
Current practice is to set a liner rather than a full string of 7” casing. The 7”
liner is set just above the top of the D reservoir, and below the sub-C stringer.
The stringer is determined on the drill time as a decease for 5’+ and
increasing again to the top of the D reservoir, which is 20’+ below the sub-C
stringer. The 7” liner is set before drilling into the D reservoir. The D
reservoir top and base can be easily picked from samples or drill time log.
When picking 7” casing point, it is important to remember that the D reservoir
is not to be penetrated and that the stringer should be behind the pipe when
the casing is cemented. Drill with mud the last 50’ above the casing point.
2.3
Abu Hadriya Field
26” Conductor
Nominal casing point for this string is 50’ into the Eocene. Actual setting
depths have varied from 126’ above to 56’ below the top.
The purpose of the casing is to shut off the loose unconsolidated sand of the
Neogene.
The top of the Eocene may be picked on drill time. It coincides in most
instances with a considerable increase in drilling time, due to passing from
the Neogene sand into the Eocene limestone. The lithologic break is also
characteristic, either sand or sandy limestone, overlying the non-sandy
Eocene limestone. The first Eocene member encountered is the Alat. Partial
to complete lost circulation may be encountered in the underlying Khobar.
18-5/8” Casing Point
Nominal casing point is 100’ into the RUS. Actual setting points have varied
from 48’ above to 204’ below the top. Probable safe range is from 50-200’
below the top. Size of casing may vary depending on program.
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The purpose of the casing is to separate the Umm er Radhuma water flow,
some 100,000 bbl per day of poor water (26,000 ppm total solids), from the
overlying Alat and Khobar. If not separated, this flow would further
contaminate the upper aquifers and might cause flooding in low places.
The top of the RUS is picked either on samples or drill time. The lithologic
change is from the blue and blue gray clays of the Alveoline zone to
limestone or dolomite, followed within a few feet by anhydrite. The drill time
pattern generally shows a slight decrease in drilling time at the top, followed
by an increase as the anhydrite is penetrated.
13-3/8” Casing Point
Nominal casing point is 200’ into the Lower Aruma shale. Actual casing
points have varied from 196’ to 694’ below the top, with most in the 200’
range.
The purpose of the casing is to shut off the water flow of the Umm er
Radhuma, so that the Wasia formation below may be drilled with mud and full
returns to control the sand and water in the Wasia. Higher wells in the field
encountered intermittent lost circulation rather than a steady water flow from
the Umm-er Radhuma, since the Umm er Radhuma static water level is 130’.
The top of the Lower Aruma shale is characterized by a decrease in drill time,
and by a lithologic change from light gray limestone to light gray pyritic shale.
It may easily be picked on either samples or drill time comparison with nearby
wells.
9-5/8” Casing Point
Nominal casing point is 30’ into the mid-Thamama. Higher setting points may
preclude the use of water to drill below the casing.
The purpose of the casing is to shut off the lost circulation sometimes
encountered in the dolomitic limestone and case off the water sensitive
shales of the Biyadh. By setting deep enough, water may be used to drill the
next section of the hole.
Tops of the dolomitic limestone (Shu’aiba) and the greenish-gray shale
(Biyadh) may be picked easily on either samples or drill time.
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The section above this casing point, drilled with mud, contains considerable
sloughing shale in the Wasia, as well as a strong potential water flow. Some
hole trouble from the sloughing shale may be encountered.
The Dolomitic limestone (Shu’aiba) may be cavernous, or relatively compact.
Some wells have maintained circulation throughout while others have had
partial or complete loss.
7” Casing Point
This string is a liner and is set in various places, depending on the type of
completion. For routine wells designed to produce from the Hadriya zone,
this point is about 100-200’ below the base of Hanifa Reservoir. The
production string is set before penetrating the post Hadriya stringer, which is
usually about 65’ above the top of Hadriya Reservoir and contains a high
pressure, low volume gas zone in those wells where this porosity stringer is
encountered.
The purpose of setting the casing about Hadriya zone is to shut off the upper
producing zones before encountering the gas zone. Attempt should be made
to bleed down and deplete pressure in the stringer when drilling below the 7”
casing. The Arab, Haifa and Hadriya Reservoirs can be easily picked on drill
time. The base of porosity of all the reservoirs are also clear on drill time logs.
In addition to the Hadriya zone, wells at Abu Hadriya have been completed in
mid-jubaila and Arab zones.
2.4
Abu Jifan Field
18-5/8” or 20” Casing Point
Nominal casing point is at top of Pre-Neogene unconformity which is
sloughing after circulation is lost in the Umm er Radhuma. However, the
Neogene is composed of competent limestone beds which will stand by
themselves, so use of the casing depends on surface conditions.
The Alat and Khobar are missing at Abu-Jifan, and the Eocene-Neogene
unconformity cuts into the Umm er Radhuma formation. Circulation is
commonly lost at about 100’ below the surface, and not regained until casing
is set in the Wasia sand.
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13-3/8” Casing Point
Nominal casing point is the Wasia-Aruma unconformity. Actual casing depths
have varied from 150-200’ below the unconformity.
The purpose of the casing is to shut off the lost circulation of the Umm er
Radhuma formation and prevent the Wasia from charging the upper horizons.
Circulation is frequently lost below the casing shoe in the Wasia. The Wasia
is the main aquifer in the area; water quality is about 2000 ppm total solids.
Static water level is about 1200’ mean sea level, surface elevations are about
1600-1700’.
The unconformity may be picked on drill time. An increase of varying
magnitude commonly occurs at, or just above, the unconformity. The lithology
above the unconformity is limestone. Below it is a short section of shale or
sandy shale and then the main Wasia sand is penetrated.
Probable safe range for the setting depth is from 50’ to 150’ below the Wasia
Aruma unconformity.
9-5/8” Casing Point
Nominal casing point is 100’ into the Buwaib formation. Actual setting points
have varied from 124’ to 345’ below the top.
The purpose of the casing is to shut off the lost circulation zones of the
Wasia, Shu’aiba and Biyadh formations. All are potential sources of trouble.
Once this string is set, the remaining hole, to the top of the D member, may
be water drilled.
Top of the Buwaib may be easily picked either on samples or drill time. The
lithologic change is from a long continuous sand section (Biyadh formation) to
the compact limestones of the Buwaib. It is accompanied by a definite
increase in drilling time. Main concern in setting the casing is to obtain a good
cement job, so probable minimum penetration for this would be about 100’
below the top.
7” Casing Point
Nominal casing point is below the base of the Arab-D reservoir. The purpose
of the casing is to act as the production string.
Top of the D or base of the C are distinctive picks on either lithology or drill
time, and may be easily picked by correlation with other wells in the field.
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2.5
Abu Safah Field
Conductor Pipe
This is a 30” pile driven into the Gulf floor at the time that the well platform is
installed prior to the rig moving on the location. The purpose of this conductor
is simply to return the drilling fluid and cuttings to the surface while drilling to
the first casing point in the RUS.
13-3/8” Casing Point
Nominal casing point is 50’ into the RUS formation.
The purpose of the casing is to protect the hole after circulation is lost in the
Umm er Radhuma.
Top of the RUS may be picked on samples or drill time. The lithologic change
is from the light blue and light gray clay and marl of the Alveolina zone to the
underlying light gray dolomitic limestone of the RUS. The RUS is 100-200’
thick, and contains no anhydrite. Circulation may be lost immediately below
the RUS in the Umm er Radhuma. Definite information on the aquifers is not
available, but indications are that the Alat is potable while the Khobar and
Umm er Radhuma are not. The Umm er Radhuma pressure may be slightly
higher than the Alat and Khobar, so that shut off’s should be established
between them.
9-5/8” Casing Point
Nominal casing point is 50” into the Ostracod Formation.
The purpose of the casing is to shut off the lost circulation zone of the Umm
er Radhuma so that the remaining section may be drilled with mud.
The Ostracod Formation may be picked on drill time. This is readily done by
comparison with nearby wells in the field. The drill time pattern shows a
prominent decrease in drilling time in the Ostracod Formation after 50’± of
higher drill time pattern.
This is the last casing set before the production string. Circulation is
maintained through the Shu’aiba and no casing is set in the Biyadh. In this
field there is very little shale in the Biyadh, it being nearly all in a limestone
facies.
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Small amounts of heavy (11-12° API) oil are encountered in the upper and
lower Ratawi zones (Sulaiy). No abnormal pressure zones are encountered,
so normal mud weights (74-78 pcf) are adequate.
7” Casing Point
The producing zone is the Arab-D. Casing may be set either at the top of the
zone, or set through it and perforated for production. Procedure had been to
drill to TD, than set the 7” casing at the top of the zone, using a packer shoe
and cementing in a single stage. The current practice is to set the 7” casing
at the top of the ‘D’ reservoir and then drill out to total depth.
Nominal casing point is 20’± above the Arab-D reservoir. The casing point
can be determined readily by comparison of the drill time pattern through the
Arab zones with nearby wells. A section of dense anhydrite and dolomite
(about 30’ thick) immediately overlies the Arab-D porosity. This makes a good
casing point.
2.6
Berri Field
Conductor Pipe – 30” (Offshore)
This is a conductor pile driven into the sea floor when the platform is set, prior
to moving the rig on location.
The purpose of the conductor is to return drilling fluid to the surface while
drilling to the first casing point.
Conductor Pipe –26” (Onshore)
This is set at 100’± below the surface. It serves to keep the unconsolidated
sand from washing out under the rig. Actual size of the casing used for this
may vary, depending upon the well program.
18-5/8” Casing Point
Normal casing point is 150’± above RUS. Actual casing points have varied
from 250’ above to 100’ into the RUS. A hard section of 60’± is encountered
below the Khobar which is 150-200’ above RUS, this section is adequate to
set the casing.
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The purpose of the casing is to separate the relative potable water of the Alat
and Khobar from the Umm er Radhuma water. Static water level of UER is
98’ so it flows at most Berri locations.
This casing point is not easy to pick. The drill time shows a higher drilling
time pattern in this section (60’±) compared to 50’± of section above and
below. The size of this string might very depending on well program.
13-3/8” Casing Point
Nominal casing point is 50’ into the Lower Aruma shale. Actual setting depths
have varied.
The purpose of the casing is to shut off the water flow or lost circulation of the
Umm er Radhuma, so that Wasia may be drilled with mud to control the shale
and water flow. It must be set low enough so that all possible water flows and
loss circulation zones in Aruma are behind the pipe.
The top of Lower Aruma shale may be picked on either samples or drill time.
Lithologically, the Unit is a limestone rather than a shale. The drill time
pattern shows a gradual increase at the top of Lower Aruma shale. The top
can be picked by drill time comparison with nearby wells. Samples are
composed of light gray pyritic limestones with some light gray marl.
9-5/8” Casing Point
Nominal casing point is 50’ into Buwaib. Actual setting depths have varied
from top to 180’ below top of Buwaib.
In water injection wells which are drilled as a straight hole this string is
omitted at this point if circulation is maintained. Producers and directional
water injectors should be programmed to set 9-5/8” casing in Buwaib.
The Buwaib is not a good pick, the drill time pattern shows a slight increase
in drilling time. The top of Buwaib is 400’± below the top of Biyadh. The top of
Shu’aiba may be easily picked on drill time. It coincides with a considerable
increase in drilling time due to passing from the Wasia sand into the
Dolomitic limestone. The top of Biyadh (greenish-gray shale) coincides with
an increase in drilling time for about 30’ and then decreases gradually.
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7” Casing Point
The 7” liner is set at various points depending on the objective reservoir. The
Arab zones, Hanifa, and Hadriya reservoirs are easily picked from drill time.
In vertical water injection wells the 9-5/8” casing is set at the top of the
injection zone if no lost circulation is encountered in the Shu’aiba.
In wells that are drilled to the base of lower Fadhili reservoir, the 7” liner is set
at total depth and selectively perforated.
2.7
Dammam Field
The Dammam field was Saudi Aramco’s original field discovery. Casing and
drilling programs have been many and varied over the course of field
development, and have been somewhat complicated by faulting in the field.
The most recent wells drilled have been a deep test of the Khuff gas zone
(DW-43) and a sweet gas supply well (DW-44).
The casing program outlined here is recommended for a new well in the field.
13-3/8” Casing Point
This casing is set at the Wasia/Aruma unconformity. Nominal casing point is
50’ below the unconformity in what is called the “Blue Shale”. The surface
location is in either RUS or Umm er Radhuma formations, and circulation is
lost within the first 300’ in the Umm er Radhuma. Drilling proceeds to the
casing point with water.
The purpose of the casing is to shut off the Umm er Radhuma so that drilling
can proceed through the Wasia, which contains water and the sweet gas
zone, with mud.
The Wasia-Aruma unconformity can be picked on drill time by comparison
with other wells in the field; and by inference from structural position.
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9-5/8” Casing Point
Nominal casing point is 300’ into the Biyadh Formation (greenish-gray shale).
In drilling to this point, circulation may be lost in the Shu’aiba (Dolomitic
Limestone) or possibly in the Wasia section above. A mud cap must be kept
in the hole to control the Wasia water, shales, and the gas zone. The
Shu’aiba and Biyadh tops may be picked on drill time.
The purpose of this casing is to shut off the lost circulation and the Wasia
above, so that the remaining hole may be drilled with full circulation. The
section to the top of the Arab zone may be drilled with water. The change to
mud must be made above the Arab formation, as all of the zones may contain
oil.
7” Casing Point
This casing point is variable through the field, both in depth and casing size.
In some cases it has been set in the Hith above the Arab zone to shut off lost
circulation in the Yamama Detrital zone; in this case a liner was run and set
either above or through the Arab D. In other cases, the casing has been set
either at the top or base of the D member.
The preferred completion, under present conditions, is to set through the D
and then perforate for production in the C or D member, or both. Mud weight
must be watched carefully to balance the Yamama Detrital without losing
circulation either to it or the Arab zones.
The purpose of the casing is to act as the production string, and to seal off
the production zone or zones from the overlying water zones.
A number of wells originally completed with a short liner across the Arab
zones have been worked over to shut off casing leaks, etc. by running a full
string from the top of the liner to the surface. Any new wells in the field should
be completed with full strings rather than liners to avoid workovers.
The Arab zones are distinctive on drill time and lithology and may be picked
on either basis.
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2.8
Fadhili Field
26” Casing Point
This is a surface conductor pipe and serves to case off unconsolidated sand.
It is set in the first hard beds in the Neogene, commonly in marl. Nominal
casing point is 100’± below surface.
18-5/8” Casing Point
Nominal casing point 50’ above RUS.
A 100’ thick section of chalky limestone 150’± below the top of Khobar
extends to the top of RUS. Casing point in this section is adequate.
The purpose of this string is to isolate the high salinity Khobar 15000 ppm)
from the relatively fresh UER (2500 PPM) immediately below. Caution should
be exercised not to penetrate the RUS formation before setting 18-5/8”
casing.
The drill time pattern shows an increase in drilling time in the Khobar as
compared to the overlying Eocene. The casing point can be picked by
comparison with nearby wells.
13-3/8” Casing Point
Nominal casing point is 200’ above Lower Aruma shale. Probable safe range
is from 300’ above to 100’ below the top of LAS which occurs in limestone.
The purpose of the casing is to shut off the water flow or lost circulation of the
Umm er Radhuma formation so that Wasia may be drilled with mud. The
casing should be set low enough below any porosity so that a good cement
job is obtained, and circulation will not be lost when drilling below the shoe.
The top of Aruma can be picked on drill time by comparison with nearby
wells. The casing point is 1100’± below the top of Aruma in limestone
showing high drill time pattern.
9-5/8” Casing Point
Nominal casing point is at the top of Mid Thamama limestone Earlier wells in
the field have omitted this casing and a full string of 7” was run.
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The purpose of the casing is to shut off the lost circulation of Shu’aiba and to
get all the Biyadh sand and shales behind the casing. This provides improved
coring and drilling condition in the zones below.
It is not possible to pick the top of Mid Thamama from drill time, however, a
fairly good estimate can be made by comparison with nearby wells and
projecting down from Shu’aiba and Biyadh.
A section of shale about 40’ thick overlays the Shu’aiba (Dolomitic
limestone). The contact of Wasia sands and the shale is distinct on drill time.
The drilling time shows a marked increase at the contact. The Biyadh shows
an erratic pattern but is usually about 150’ below Shu’aiba and can be picked
by comparison with other wells.
7” Casing Point
Nominal casing point is 80’ below the pre Hanifa unconformity (Tuwaiq mtn.)
Upper Fadhili reservoir is about 110’ below the pre Hanifa unconformity and
casing should be set before penetrating the Fadhili zone.
The Fadhili field has two producing zones, the Arab-D and the Fadhili. The 7”
liner is set between the two producing zones.
The drill time pattern shows an increase below the pre-Hanifa unconformity.
The overlying Hanifa and Arab zones are easily picked on drill time and
samples and the casing point can be picked by comparison with other wells
in the field.
2.9
Fazran Field
26” Casing Point
This is a surface conductor pipe set at 100’± below the surface. It serves to
keep the unconsolidated sand from washing out under the rig.
18-5/8” Casing Point
Nominal casing point is 50’ into the RUS. Actual casing setting depths have
varied.
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The purpose of the casing is to separate the lost circulation zone in the
overlaying Khobar and case off the sloughing shales and marl of the RUS
formation. The casing also separates the Umm er Radhuma from the
overlaying aquifers.
The RUS formation is not easy to pick on drill time. The drilling time
increases at the top of Khobar and RUS and shows a low drilling time pattern
in between.
13-3/8” Casing Point
Nominal casing point is 50’ into the Lower Aruma shale. Probable safe range
is from 50’ above to 100’ below the top of Lower Aruma shale.
The purpose of the casing is to shut off the lost circulation of Umm er
Radhuma from Wasia water flow and to allow mud drilling of Wasia. The
casing point has to be picked from drill time as circulation is usually lost in
Umm er Radhuma.
The top of Lower Aruma shale occurs in limestone. The drilling time shows
an increases at the top and gradually decreases. The Lower Aruma shale
can be picked by comparison with other wells.
9-5/8” Casing Point
The 9-5/8” casing is set in the Biyadh formation. Nominal casing point is 300’
below the top of Biyadh.
The purpose of the casing is to shut off the lost circulation zone of the
Shu’aiba or Wasia sands. It must also be set through the sloughing shales of
Biyadh so that the formations below the casing may be drilled with water. The
Biyadh shale is water sensitive, if exposed for more than a short period of
time. If mud is conditioned with LCM prior to drilling is Shu’aiba lost
circulation can be controlled to a large extent as has been exhibited on a few
wells in the field and would reduce hole problems.
The top of Sub’aiba and Biyadh is easily picked on drill time. The drilling time
increases at the top of Shu’aiba as compared to the Wasia above. Drill time
shows a gradual increase at the top of Biyadh.
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7” Casing Point
Nominal casing point is at the base of D reservoir, or at the top of D reservoir
if open hole option is used.
The Arab zones in this field are very clear on drill time and can be picked
easily by comparison with other wells in the field. The 7” is run as a liner.
2.10 Haradh Field
18-5/8” Casing Point
Nominal casing point for the string is 50’ into the RUS formation. Setting
depths have varied from above the RUS, in the Khobar, to below the top of
the Umm er Radhuma.
Many high structural wells were drilled without using this string. Since there is
little water in the formations above the Umm er Radhuma, the casing is not
needed there for hole support. However, the Neogene thickens rapidly going
off structure, and becomes sandy. On flank wells or doubtful cases, the
casing should be set in the RUS to prevent hole collapse when circulation is
lost in the Umm er Radhuma. Static water level of the Umm er Radhuma is
about 590’± mean sea level which brings it stratigraphically as high as the
base of the Neogene on flank wells. Surface elevations range from 10001100’ in the area.
13-3/8” Casing Point
Nominal setting point for this casing is 50’ into the Lower Aruma shale. On
high structural wells this brings it somewhat below the Wasia-Aruma
unconformity.
The purpose of this casing is to shut off the lost circulation zone of the Umm
er Radhuma so that the Wasia can be drilled with mud. This also separates
the Wasia and Umm er Radhuma aquifers with their differing pressures.
The casing point must be picked on drill time due to the lack of samples
through the lost circulation zone above. The top of the Lower Aruma shale is
not a distinctive pick on drill time.
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The drill time pattern shows a decrease in drilling time at the top of Lower
Aruma shale. In crestal parts of the field it occurs about 200’ below a
prominent increase in drill time and can be determined by comparison with
nearby wells. On wells situated at the flank this section is less thick.
9-5/8” Casing Point
The nominal casing point is 300’ into the Biyadh formation. Actual setting
points have varied from more than 300’ below the top to below the top of the
Mid-Thamama limestone.
The purpose of the string is to separate the fresh (±1300 ppm total solids)
waters of all the formations above the Biyadh top from the salty (21000 ppm
total solids or more) waters of the Biyadh itself, and those below. It also shuts
off the partial to complete lost circulation of the Shu’aiba or Wasia sand
section and allows the next section of hole to be drilled with water. Those
holes where no casing was set in the interval were mud drilled and had some
difficulty with lost circulation.
The drill time pick on the top of the Biyadh is not particularly distinctive.
However, the top of the overlying Shu’aiba formation is easily picked at a
distinct increase in drill time, and on samples by a change from sand to
dolomite or dolomitic limestone. Thickness of this unit is relatively constant at
about 200’, which enables the Biyadh top to be picked by drill time
comparison with other wells.
7” Casing Point
Nominal casing point is the top of the Arab-D member. Actual setting depths
have varied with most in the range of 25-50’ above, in a dense anhydrite unit.
The purpose of the string is to inject into, or produce the well, and separate
the oil zone from the water bearing zones above. If desired, the casing may
be run to TD through the Arab-D and perforated for production without
encountering difficulty.
In most parts of the field the top and base of Arab zones may be readily
picked by either samples or drill time comparison with nearby wells.
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In the North Haradh area, some difficulty has been faced in picking Arab
zones off drill time logs. This can be overcome if the top Sulaiy drill time
break is used as a guide. The interval from the top of Sulaiy formation which
is a very marked and easily recognized drill time break, to the base of C
Reservoir (a fairly good pick) is fairly consistent at about 1450’. If the 7”
casing is set 150’± below the base of C Reservoir, the sub C stringer (if
present) should be behind the casing and shoe above the top of Arab-D
reservoir.
Present practice is to run a 7” liner rather than a full string and cement the
liner before drilling out to total depth.
2.11 Harmaliyah Field
18-5/8” Casing Point
Nominal setting point for this casing is anywhere from top of Khobar to top of
RUS.
The purpose of this casing is to shut off lost circulation above Khobar and to
prevent hole collapse when circulation is lost in the Umm er Radhuma.
The drill time pattern shows an increase at top of Khobar and decrease at top
of RUS.
13-3/8” Casing Point
Nominal setting point for this casing is 50’ into the Lower Aruma shale.
The purpose of this casing is to shut off the lost circulation zone of the Umm
er Radhuma so that the Wasia can be drilled with mud. This also separates
the Wasia and Umm er Radhuma aquifers with their differing pressures.
The casing point must be picked on drill time, due to the lack of samples
through the lost circulation zone above. The top of the Lower Aruma shale is
not a distinctive pick on drill time.
The drill time pattern shows a decrease in drilling time at the top of Lower
Aruma shale. In crestal parts of the field it occurs about 200’ below a
prominent increase in drill time and can be determined by comparison with
nearby wells. On wells situated at the flank this section is less thick.
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9-5/8” Casing Point
Nominal casing point is 300’ into Biyadh.
The purpose of the casing is to shut off the lost circulation of Shu’aiba or
Wasia and to allow drilling below with water. The top of Shu’aiba can be
picked on samples and drill time. The lithologic change is from sand above
to dolomite below, and is accompanied by a marked increase in drill time.
The top of Biyadh (greenish gray shale) is picked on drill time. It is less
obvious than the Shu’aiba pick, but occurs about 300’ below the top of
Shu’aiba and may be picked from drill time pattern comparison with other
wells.
7” Casing Point
Nominal casing point is the top of the Arab-D member.
Actual setting depths have varied with most in the range of 25’–50’ above, in
a dense anhydrite unit.
The casing point is usually 150’± below the base of ‘C’ reservoir which puts it
10’± above the top of ‘D’ reservoir. The sub C stringer (if present) should be
behind the casing and shoe above the top of Arab-D reservoir. The top and
base of ‘D’ reservoir is easily picked on drill time. The other Arab members
above are not very clear on drill time but can be picked from drill time pattern
comparison with nearby wells. A fairly good estimate can be made if top of
Sulaiy is used as a guide. Present practice is to run a 7’ liner rather than a
full string and cement the liner before drilling out to total depth.
2.12 Hawiyah Field
26” Casing Point
Nominal setting depth is 100’± below the surface. The purpose of the casing
is to prevent unconsolidated sand from washing out under the rig. Use of this
casing depends on surface conditions.
18-5/8” Casing Point
Nominal setting point is 50’ into the RUS
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Neogene static water level is about +500’ mean sea level. Khobar and Umm
er Radhuma are both about +555’ mean sea level, and water quality of all
three is about 1200-1400 ppm total solids. No shut off is needed between
them. 18-5/8” casing may be run if necessary to support the hole through the
Neogene. Data from the few wells in the area indicates that the Neogene
contains considerable running sand just above the Eocene/Neogene
unconformity, so that casing should be run into the Eocene. Second unit
below the unconformity is the RUS..
The top of the Eocene is easily picked at a marked increase in drilling time
from the Neogene sands into the Khobar dolomite. Since circulation is lost
near the top of the Neogene sandy section, no samples will be available.
Drilling time increases at top of Khobar and decreases at top of RUS.
Probable safe range is form top of Khobar to base of RUS.
13-3/8” Casing Point
Nominal casing point is 50’ into the Ahmadi.
The casing separates the Umm er Radhuma and Wasia aquifers and also the
lost circulation zone in Umm er Radhuma or Mishrif. In the crestal part of the
field no loss of circulation has occurred in the Mishrif but the section between
Lower Aruma shale and Ahmadi is 100’±, therefore, it is a good practice to
set casing in Ahmadi. Probable safe range for casing point on crestal wells is
from the top of Lower Aruma shale to the Ahmadi. The wells situated on the
flanks have had lost circulation in Mishrif and 50’ into Ahmadi is adequate for
the casing point.
The top of Lower Aruma shale may be picked on drill time. The drill time
increases at or just above, the top and decreases gradually. The
Praealveolina and Ahmadi are distinct on drill time. Three clear kicks are
seen on drill time, the top of the second is Praealveolina dn. base of third is
Ahmadi.
9-5/8” Casing Point
Nominal casing point is 300’ into Biyadh. The purpose of the casing is to shut
off the lost circulation of Shu’aiba or Wasia and to allow drilling below with
water.
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The top of Shu’aiba can be picked on samples and drill time. The lithologic
change is from sand above to dolomite below, and is accompanied by a
marked increase in drill time. The top of Biyadh (greenish-gray shale) is
picked on drill time. It is less obvious than the Shu’aiba pick, but occurs about
200-250’ below the top of Shu’aiba, and may be picked from drill time pattern
comparison with other wells. Minimum safe depth for setting the 9-5/8” casing
is 150’ into the Biyadh, as sloughing water sensitive shale is not a major
problem in this area.
7” Casing Point
Nominal casing point is at the top of the Arab-D reservoir at the base of
porosity if set-through option is use.
The casing point is usually 150’± below the base of C reservoir which puts it
10’± below the base of C reservoir which puts it 10’± above the top of D
reservoir. The presence of sub C stringer in this area makes this point critical
and care must be taken so that the sub C stringer should be behind the pipe.
The top and base of D reservoir is easily picked on drill time. The other Arab
members above are not very clear on drill time but can be picked from drill
time pattern comparison with nearby wells. A fairly good estimate can be
made if top of Sulaiy is used as a guide. The interval between top Sulaiy to
base of C reservoir is about 1425’ thick on the crestal walls and about 1450’
thick at the flanks.
2.13 Khuff and Deep/Exploratory Wells
(Casing sizes will be determined by the type of well drilled)
Conductor
This is set at 110’± below the surface. It serves to keep the unconsolidated
sand from washing out under the rig.
RUS Casing Point
Nominal casing point for this string is 50’r into the RUS formation.
Ahmadi Casing Point
Nominal casing point is 50’r into the Ahmadi. The casing separates the Umm
er Radhuma and Wasia aquifers and also the lost circulation zone in Umm er
Radhuma or Mishrif.
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The top of Lower Aruma shale may be picked on drill time. The drill time
increases at or just above, the top and decreases gradually. The Prealveolina
and Ahmadi are distinct on drill time. Three clear kicks are seen on drill time,
the top of the second is Prealveolina and base of third is Ahmadi.
Arab-D Casing Point
Nominal casing point is the top of the Arab-D member. Actual setting depths
have varied with most in the range of 25-50’ above, in a dense anhydrite unit.
In most parts of the field the top and base of Arab zones may be readily
picked by either samples or drill time comparison with nearby wells.
In the North Haradh area, some difficulty has been faced in picking Arab
zones off drill time logs. This can be overcome if the top Sulaiy drill time
break is used as a guide. The interval from the top of Sulaiy formation which
is a very marked and easily recognized drill time break, to the base of C
Reservoir (a fairly good pick) is fairly consistent at about 1450’. If the 7”
casing is set 150’± below the base of C Reservoir, the sub C stringer (if
present) should be behind the casing and shoe above the top of Arab-D
reservoir.
Note:
An alternate casing point is 100’ into the Hith may be selected if
severe loss circulation in the Wasia/Shu’aiba persists.
Jilh Dolomite Casing Point
Nominal casing point is 30’r below the base of the Jilh dolomite. This casing
string isolates the major oil producing reservoir of the Arab-D in the Ghawar
field and covers the probably lost circulation that may be encountered in the
Arab-D, the Hanifa, and Hadriya formations. A10,000 psi WP BOP stack is
nippled up after running this casing string.
Khuff Casing Point
If the lower Jilh is over pressured then the casing point is 15’r into the top of
the Khuff formation, to isolate the high pressure. In normal cases, drilling
would continue through the Khuff formation to a depth of at least 450’ below
the base of the Khuff-D anhydrite. In certain wells targeted for the Pre-Khuff,
this casing point is selected at +100’ above the pre-Khuff unconformity.
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Liner Point
If the lower Jilh is over pressured then the liner point is 15’r into the top of the
Khuff formation, to isolate the high pressure. Liner point is 450’r below the
top of the Khuff D anhydrite or below the base of the pre-Khuff formation.
2.13 Khurais Field
18-5/8” or 20” Casing Point
Nominal casing point is at top of Pre Neogene unconformity which is about
50’ below the surface. Its The purpose is to prevent the Neogene from
sloughing after circulation is lost in the Umm er Radhuma. However, the
Neogene at Khurais is composed of competent limestone beds which will
stand by themselves, so use of the casing depends on surface conditions.
The Alat and Khobar are missing at Khurais, and the Eocene-Neogene
unconformity cuts into the Umm er Radhuma formation. Circulation is
commonly lost at about 100’ below the surface, and not regained until casing
is set in the Wasia sand.
13-3/8” Casing Point
Nominal casing point is at the top of the Wasia-Aruma unconformity. Actual
casing depths have varied from 746’ above to 459’ below the unconformity.
The purpose of the casing is to shut off the lost circulation of the Umm er
Radhuma formation and prevent the Wasia from charging the upper horizons.
Circulation is frequently lost below the casing shoe in the Wasia. The Wasia
is the main aquifer in the area; water quality is about 1200 ppm total solids.
Static water level is about 930’ mean sea level, surface elevations are about
1400-1500’. In some cases, aerated mud has been used to maintain
circulation.
The unconformity may be picked on drill time. An increase of varying
magnitude commonly occurs at, or just above, the unconformity. The
lithology above the unconformity is limestone. Below it is a short section of
shale or sandy shale and then the main Wasia sand is penetrated.
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Probable safe range for the setting depth is from 50’ above to 50’ below the
Wasia Arum unconformity.
9-5/8” Casing Point
Nominal casing point is 100’ into the Buwaib formation.
2.14 Khursaniyah Field
26” Casing Point
Nominal casing point for this string is at the top of the Eocene.
The purpose of the casing is to shut off the loose sand in the Neogene. The
Neogene in Khursaniyah is exceptionally sandy, and can be very
troublesome if not cased off. This sand may be particularly bad if circulation
is lost in the Khobar, a not uncommon occurrence. Most recent wells have
set this casing between 100’ and 200’ below the surface.
18-5/8” Casing Point
Nominal casing point is 50’ into the RUS. Actual setting depths have ranged
from 0 to 239’ below the top. The deeper points were actually set in the top
of the Umm er Radhuma formation.
The purpose of the casing is to separate the Alat and Khobar members from
the water flow of the Umm er Radhuma. The Umm er Radhuma has a
considerably higher pressure, and if not isolated, would flow into the upper
zones.
Top of the RUS is somewhat difficult to pick on drill time. Some wells show
an increase, others a decrease, and still others have no character at all.
However, by comparison with structurally similar wells, an approximate pick
can be made. Lithologically, it is a dolomitic limestone quite similar to the
overlying Khobar. Fortunately the safe setting range is fairly large, extending
some 100’ into the top of the Umm er Radhuma, so an error of some
magnitude may be made in picking the top without serious consequences.
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13-3/8” Casing Point
Nominal setting point for this casing is 50’ into the Lower Aruma shale.
Actual setting points have varied from 32’ above to 202’ below the top.
The purpose of the casing is to shut off the water flow or lost circulation of the
Umm er Radhuma and Aruma formations, and separate them from the high
pressure water of the Wasia. It also allows the Wasia to be drilled with mud to
control the shales and water flow. A small amount of 12° API oil is also
present in the top of the Wasia. The top of the Lower Aruma Shale is not
easy to pick on drill time. Lithologically, the unit is limestone similar to the
overlying Aruma. Circulation may be lost in the Aruma, even though the
Umm er Radhuma produces a water flow. Ditch samples caught from the
water flow are generally poor.
9-5/8” Casing Point
Nominal casing point is 400’ into the Biyadh formation. Actual casing points
have varied. However, the minimum penetration which will allow drilling with
water below the casing point is probably about 350’.
The purpose of the casing is to shut off the lost circulation of the Shu’aiba
and isolate the Wasia from the lower formations so that the next section of
the hole can be drilled with water.
Tops of the Shu’aiba and Biyadh can be picked on drill time from nearby
wells. The lithological break is also distinctive from sand and shale to
dolomite or dolomitic limestone at the Shu’aiba top, and then back into shale
and sand at the top of the Biyadh.
The upper shales of the Biyadh (greenish-gray) are very water sensitive, and
must be cased off if the next section is to be water drilled. KW-6, with casing
set 305’ into the Biyadh drilled out of the shoe with water and encountered
such severe sloughing that the hole had to be abandoned. On wells which
do not lose circulation in the Dolomitic, the string may be omitted, if drilling
the next section of the hole with mud is acceptable.
7” Casing Point
This casing point is variable depending on the desired completion. Nominal
casing points have been either a few feet above the producing zone, or
completely through the porosity into the dense limestone below, and
selectively perforated.
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The tops and bases of the Arab zones may be picked easily from drill time or
samples.
If water is used to drill below the 9-5/8” casing point, a modest water flow will
be encountered at the Sulaiy zone. The change to mud must be made in the
upper portion of the Hith anhydrite, since this formation contains some
calcarenite stringers which contain oil and gas.
2.15 Manifa Field
18-5/8” Casing Point
Nominal casing point is 25’ into the pre-Neogene unconformity.
The purpose of the casing is to shut off the considerable amounts of loose
sand in the Neogene.
Drill time at the unconformity is not diagnostic. The pick must be made on
samples, at the change from sandy limestone or marl to non-sandy limestone
or dolomite.
If circulation is lost above the unconformity, then an
approximation can be made on drill time.
The Manifa field has both offshore and onshore wells. The casing string at
the Pre-Neogene unconformity has been successfully omitted in four recent
wells (two onshore and two offshore). These wells all had shallow
conductors set. For onshore wells the 18-5/8” string set 25’ into the PreNeogene at 200-300’ will serve as a conductor. For offshore wells, where a
large conductor is installed, the 18-5/8” casing can be omitted.
Water data for the Neogene, Alat and Khobar are scarce, but indications are
that all are non-potable so that no shut off is necessary between them.
13-3/8” Casing Point
The purpose of the casing is to separate the highly saline sulfurous water
flow of the Umm er Radhuma from the upper formations. The casing point is
non-critical, any depth into the RUS is sufficient to assure a good cement job
since circulation is not normally lost in either the Alat or Khobar. Thus, the
range of safe setting points would be from the top to the base of the RUS, an
interval of 300-400'.
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The drill time pattern is not distinctive, but the top may be picked by
comparison with other wells in the field. On lithology, it occurs below the light
blue gray marl and clays of the Alveolina zone. Anhydrite and gypsum are
encountered at, or just below the top of the RUS, making the determination
positive. Minor traces of oil have been noted in the overlying Khobar
member.
9-5/8” Casing Point
Nominal setting point for this casing is 50’ into the Lower Aruma shale.
The purpose of the casing is to shut off the water flow of the Umm er
Radhuma formation, so that the Wasia section can be drilled with mud to
control the shales and water flow.
The top of the Lower Aruma shale may be picked on drill time by comparison
with other wells in the field, or on a lithologic change from an off-white
limestone or dolomitic limestone to underlying light green or light gray
calcareous shale.
7” Casing Point
This is the production string. Setting depth varies according to the desired
completion. Immediately above the Manifa zone, is approximately 250’ of
dense limestone, while below is the anhydrite and limestone or calcarenite
stringers of the Hith. Either makes a suitable casing seat, assuring isolation
of the zone.
The Wasia sands, productive in Safaniya, contain salt water at Manifa. This
will flow to the surface, so that mud must be used to control it and the water
sensitive Wasia shales as well. Circulation is normally maintained through
this interval, including the Shu’aiba so that no casing is needed in the Biyadh.
In those instances when circulation has been lost in the Wasia, it has been
regained with lost circulation material and/or cement. The mud drilled interval
from the 9-5/8” casing point to below the Manifa zone is about 4000’.
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2.16 Marjan Field
Conductor Pipe – 30”
This is a conductor pile driven into the sea floor when the platform is set, prior
to moving the rig on location. It is driven to refusal, but not cemented. The
purpose of the conductor is to return drilling fluids to the surface while drilling
to the first casing point at the top of the Eocene.
13-3/8” Casing Point
This is set at the top of the Pre-Neogene unconformity to shut off
unconsolidated sands in the Neogene. Nominal setting depth is 50’ into the
Pre-Neogene unconformity. It is cemented to surface. In instances where
cement is not circulated, a surface bridge is established.
The top of the Pre-Neogene unconformity is picked on samples and drill time.
The change of lithology is from sand and marl, or sandy limestone of the
Neogene, to a non-sandy limestone of the Eocene. There is usually, but not
always, a distinct increase in drill time for a short interval at the change in
lithology. This may be determined by comparison with nearby wells.
9-5/8” Casing Point
The nominal setting point is 50-100’ into the Lower Aruma shale. Recent
practice has been to set about 50’ below the Lower Aruma shale top.
The interval between the 13-3/8” casing point and the 9-5/8” is composed of
the RUS, the very porous limestones of the Umm er Radhuma formation, and
the somewhat porous limestones of the Aruma formation. The section is
drilled with water due to the large water flow encountered in the Umm er
Radhuma.
The purpose of the casing is to shut off this water flow and any lost circulation
zones below it, so that mud, with full circulation, may be used to drill into the
oil zones (Wasia formation). The casing point must be picked deep enough
into the Aruma so that there is no chance of a water flow or lost circulation
below the shoe.
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Thickness of the Lower Aruma shale is extremely variable. However, a
relatively consistent increase in drilling time occurs in the lower portion of the
Aruma formation. This represents a change to a more dense limestone, and
casing may safely be set any time after penetrating about 100’ of this
lithology. The increase in drilling time is a sufficient indicator of this point.
Ditch samples are badly contaminated due to the water flow. The casing is
usually cemented in two stages, using a DV packer collar inside 13-3/8”
casing.
7” Casing Point
Setting point of this casing varies according to the type of completion desired.
It is set through the producing zone, and then perforated for production.
Normal completions are either in the Safaniya or Khafji members, with lowest
perforations about 100’ above the oil-water contact.
The section below the 9-5/8” casing point consists mainly of the sandstones,
shales, and then limestones of the Wasia formation. The section down to the
top of the Caprock limestone may be drilled with water, but the drilling fluid
should be changed to mud before drilling the Caprock and the producing
zones below. Low water loss, fresh water mud is used to minimize formation
damage and provide proper logging environment.
2.17 Mazalij Field
18-5/8” or 20” Casing Point
Nominal casing point is at top of Pre Neogene unconformity which is about
50’ below the surface. Its The purpose is to prevent the Neogene from
sloughing after circulation is lost in the Umm er Radhuma. However, the
Neogene at Mazalij is composed of competent limestone beds which will
stand by themselves, so use of the casing depends on surface conditions.
The Alat and Khobar are missing at Mazalij and the Eocene-Neogene
unconformity cuts into the Umm or Radhuma formation. Circulation is
commonly lost at about 100’ below the surface, and not regained until casing
is set in the Wasia sand.
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13-3/8” Casing Point
Nominal casing point is the Wasia-Aruma unconformity. Actual casing
depths can vary from 100’ above to 200’ below the unconformity.
The purpose of the casing is to shut off the lost
Radhuma formation and to prevent the Wasia
horizons. Circulation is frequently lost below the
The Wasia is the main aquifer in the area; water
total solids. Static water level is about 1100’
elevations are about 1350-1550’.
circulation of the Umm er
from charging the upper
casing shoe in the Wasia.
quality is about 1300 ppm
mean sea level, surface
The unconformity may be picked on drill time. An increase of varying
magnitude commonly occurs at, or just above, the unconformity. The
lithology above the unconformity is limestone. Below it is a short section of
shale or sandy shale and then the main Wasia sand is penetrated.
9-5/8’ Casing Point
Nominal casing point is 100’ into the Buwaib formation.
The purpose of the casing is to shut off the lost circulation zones of the
Wasia, Shu’aiba and Biyadh formations. All are potential sources of trouble.
Once this string is set, the remaining hole, to the top of the D member, may
be water drilled.
Top of the Buwaib may be easily picked either on samples or drill time. The
lithologist change is from a long continuous sand section (Biyadh formation)
to the compact limestones of the Buwaib. It is accompanied by a definite
increase in drilling time. Main concern in setting the casing is to obtain a
good cement job, so probable minimum penetration for this would be about
100’ below the top.
7” Casing Point
Nominal casing point is below the base of the Arab-D Reservoir
The purpose of the casing is to act as the production string. A full string has
been set in all wells.
Top of the D or base of the C are distinctive picks on either lithology or drill
time, and may be easily picked by comparison with other wells in the field.
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2.18 Qatif Field
26” Casing Point
Nominal casing point is 100± below the surface.
The purpose of the casing is to case off the unconsolidated sand and prevent
washing out under the rig.
18-5/8” Casing Point
Nominal casing point is 25’ into the Alat. In some cases, this string has been
26”.
The purpose of the casing is to separate the water zone of the Neogene from
those of the Alat and Khobar. Without a shut off at this point, the Alat and
Khobar waters tend to flow up and recharge the Neogene, causing flooding in
some areas. This shut off is critical in this area due to the widespread
habitation of the oasis. Without this shut off, water is wasted from the Alat
and Khobar aquifers, and the reservoirs which are used locally for water
supply are unnecessarily depleted.
The top of the Alat, which is just below the pre-Neogene unconformity, is
picked on sample evidence, where the lithology changes from sandy to nonsandy limestone. It is also characterized by an increase in drilling time, and
may be picked on this basis by comparison with nearby wells.
13-3/8” Casing Point
Nominal casing point is 50’ below the top of the RUS formation. Actual setting
points have varied from 100’ above to 57’ below the top, with most in the
range of 25’ above to 50’ below.
The purpose of the casing is to isolate the potable water of the Alat and
Khobar aquifers (2,000 ± ppm total solids) from the underlying non-potable
(50,000 ± ppm total solids) Umm er Radhuma. This shut off is important to
prevent contamination of the Alat and Khobar, which are the aquifers used by
the local population for water supply. If it were possible to assure a good
shut off of the aquifers by cementing, the 18-5/8” string above could be
eliminated. However, circulation is normally lost in the Alat or Khobar, so that
a continuous cement job across all zones is not readily obtainable.
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The top of the RUS must usually be picked on drill time since samples are
not normally available due to the lost circulation. Drill time increases through
the marls and clays of the Alveolina zone just above the RUS, and then
decreases when the limestone of the RUS is penetrated. Casing set in the
Alveolina zone is deep enough, although the cement job may be
questionable if the base of the Khobar is porous. All these acquifers are
probably in communication to some extent in some of the older wells. The
RUS is all limestone in Qatif, no anhydrite.
9-5/8” Casing Point
The nominal casing point is 25’ in the Pre-Aruma unconformity.
The purpose of this casing is to shut off the lost circulation (or water flow,
depending on surface elevation of the location) of the Umm er Radhuma from
the underlying Wasia formation and permit drilling the Wasia with mud to
control the sloughing shales and the Wasia water flow.
The Pre-Aruma unconformity must be picked on drill time. It is picked at a
decrease in drill time following a general increase over 50’± just above.
Relative magnitude of this pattern varies, but the overall pattern is
recognizable throughout the field.
The point may be identified from
comparison with nearby wells.
The upper part of the Wasia is a thick section of water sensitive shale and the
lower section is sand with water. Mud must be used to protect the shales
and also to keep the water from flowing to the surface.
7” Casing Point (South Qatif)
Nominal point is 300’ in the Biyadh. Probable minimum penetration is 250’
below the top of Biyadh.
The purpose of the casing is to shut off the lost circulation of the Shu’aiba. It
must be set far enough into the greenish-gray shale of Biyadh to case off the
water sensitive portion, so that the section below may be drilled with water. In
the event that circulation is maintained through the Shu’aiba, as is the case in
North Qatif, the casing may be omitted if it is acceptable to drill the remaining
hole with mud.
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The advantage is that a 7” completion results rather than a 4½”, with
consequently greater well potential. The same thing may be accomplished
by starting with one size larger casing at the top of the hold. This means
drilling longer stretches of large hole. The drill time shows a distinct increase
at the top of the Shu’aiba and just above or the top of the Biyadh.
4½” Casing Point (South Qatif)
Nominal setting point for the string is the top of the D reservoir. Actual setting
depths have ranged from 36’ above to 227’ below the top, with the more
recent wells having the deeper settings. These were set through the zone.
The deeper Fadhili zone is also productive in Qatif. The 4½” may be set
through this zone and selectively perforated.
The purpose of the casing is to produce the well and shut off the water zones
above the oil. All four Arab zone reservoirs contain oil in Qatif, and many of
the wells produce from both the C and D reservoirs, separated by down hole
packers. Present practice is to use a liner rather than a full string, and to
bring the top of the liner above the shoe of the string set in the Biyadh
formation.
The Arab and Fadhili zones have characteristic drill time curves and lithology,
so that the casing point may be easily picked by either of these means.
7” Casing Point (North Qatif)
In North Qatif circulation is usually maintained through the Shu’aiba formation
and the casing in Biyadh formation is omitted. The 7” casing is set a few feet
above the producing zone or completely through the porosity. Current
practice is to set through the producing zone and perforate selectively.
The tops and bases of Arab zones and Fadhili reservoir may be picked from
drill time or samples.
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2.19 Qirdi Field
18-5/8” or 20” Casing Point
Nominal casing point is at top of Pre Neogene unconformity which is about
30’ below the surface. Its The purpose is to prevent the Neogene from
sloughing after circulation is lost in the Umm er Radhuma. However, the
Neogene is composed of competent limestone beds which will stand by
themselves, so use of the casing depends on surface conditions.
The Alat and Khobar are missing at Qirdi, and the Eocene-Neogene
unconformity cuts into the Umm er Radhuma formation. Circulation is
commonly lost at about 100’ below the surface, and not regained until casing
is set in the Wasia sand.
13-3/8” Casing Point
Nominal casing point is the Wasia-Aruma unconformity. Casing setting
depths can vary from 100’ above to 200’ below the unconformity.
The purpose of the casing is to shut off the lost circulation of the Umm er
Rahuma formation and prevent the Wasia from charging the upper horizons.
Circulation is frequently lost below the casing shoe in the Wasia. The Wasia
is the main aquifer in the area; water quality is about 1000 ppm total solids.
Static water level is about 900’ mean sea level, surface elevations are about
1400-1500’.
The unconformity may be picked on drill time. An increase of varying
magnitude commonly occurs at, or just above, the unconformity. The lithology
above the unconformity is limestone. Below it is a short section of shale or
sandy shale and then the main Wasia sand is penetrated.
9-5/8” Casing Point
Nominal casing point is 100’ into the Buwaib formation.
The purpose of the casing is to shut off the lost circulation zones of the
Wasia, Shu’aiba and Biyadh formations. All are potential sources of trouble.
Once this string is set, the remaining hole, to the top of the D member, may
be water drilled.
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Top of the Buwaib may be easily picked either on samples or drill time. The
lithologic change is from a long continuos sand section (Biyadh formation) to
the compact limestones of the Buwaib. It is accompanied by a definite
increase in drilling time. Main concern in setting the casing is to obtain a
good cement job, so probable minimum penetration for this would be about
100’ below the top.
7” Casing Point
Nominal casing point is below the base of the D reservoir.
The purpose of the casing is to act as the production string.
Top of the D or base of the C are distinctive picks on either lithology or drill
time, and may be easily picked by comparison with other wells in the field.
2.20 Rimthan Field
26” Casing Point
Nominal setting depth is 100± below the surface. The purpose of the casings
is to case off unconsolidated sand from washing out under the rig. Use of
this casing depends on surface conditions.
13-3/8” Casing Point
Nominal casing point is 50’ below the top of the RUS formation.
The purpose of this string is to separate the incompetent sand and shale to
the pre-Neogene unconformity and to support the hole after circulation is lost
and separate the Umm er Radhuma from the Neogene and Dammam
formation.
The top of the RUS must usually be picked on drill time since samples are
not normally available, due to the lost circulation. Drill time increases just
about the RUS and then decreases when the limestone of the RUS is
penetrated. The lower part of the RUS is anhydrite which is below the
limestone.
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9-5/8” Casing Point
Nominal casing point is 1500’ into the Aruma (i.e. 100’ into the Mid-Aruma
shale).
The purpose of this casing is to shut off lost circulation of the Umm er
Radhuma formation, and to permit drilling the lower section with mud to
control the sloughing shale of the Aruma.
The Aruma is picked on drill time as a decrease in the drilling time and as
lithology changes from limestone to shale.
7” Casing Point
Nominal casing point is at total depth, which is 60’ below base of Arab-D
reservoir.
The purpose of this string is to produce from the zone of interest through
perforation. Present practice is to run a full string of 7”.
The tops and bases of Arab zones are readily picked on drill time.
2.21 Safaniyah Field
Conductor Pipe 30”
This is a conductor pile driven into the sea floor when the platform is set, prior
to moving the rig on location. It is driven to refusal but not cemented.
The purpose of the conductor is to return drilling fluids to the surface while
drilling to the first casing point.
18-5/8” Casing Point
This is set at the top of the Pre Neogene unconformity to shut off
unconsolidated sands in the Neogene. Nominal setting depth is 25’ into the
Pre Neogene unconformity. It is cemented to the surface. In instances
where cement is not circulated, a surface bridge is established.
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It is not necessary from a geological or engineering standpoint except in
North Safaniya wells, where oil and gas occur in the RUS. Wells in Central
Safaniya have been drilled successfully without setting this string of casing.
In North Safaniya, oil and gas occur in the RUS formation on top of the
structure. Here, the casing must be set so that blowout equipment can be
installed, and mud can be used to drill the oil and gas bearing zones. Heavy
oil is also known in the Alat and Khobar (SW-37).
The top of the Pre Neogene unconformity is picked on samples and drill time.
The change in lithology is from sand and marl, or sandy limestones of the
Neogene, to non-sandy limestone of the Eocene. There is usually, but not
always, a distinct increase in drill time for a short interval at the change in
lithology. This may be determined by comparison with nearby wells.
13-3/8” Casing Point
This string of casing is set in the RUS formation at one of two nominal points,
depending on location of the well. In North Safaniya, the nominal point is the
top of the UER to shut off the oil and gas zones encountered in that area.
See well records for SW-43 for a discussion of the gas and oil occurrences.
In the other areas of Safaniya, nominal casing point is 25’ into the RUS.
The section between the 18-5/8” and 13-3/8” casing point consists of the Alat
limestones and marls. Khobar dolomite, limestone and marl, the thin
limestones and marls of the Alveolina zone, and the anhydrite and thin
limestones of the RUS formation. Circulation may be lost in the Khobar.
The top of the RUS may be picked either on samples or drill time. The
lithology changes abruptly from the blue-gray marl containing Alveolina, to
calcarenitic limestone and then to anhydrite or gypsum. The top is picked at
the top of the calcarenitic limestone. This is commonly porous and contains
a showing of heavy oil.
On drill time, the bit tends to ball up through the Alveolina zone, giving an
increase in drilling time. The first few feet of the RUS usually drill faster, then
the drill time may increase again as the gypsum and anhydrite are
penetrated.
This pattern varies somewhat from well to well, and nearby wells should be
checked carefully when picking this point. Circulation is usually maintained to
this casing point so samples are available.
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The casing is usually cemented in two stages, using a DV packer collar
inside the 18-5/8” casing. If 18-5/8” is not run, the 13-3/8” is cemented in a
single stage and a surface bridge is established if cement is not circulated.
9-5/8” Casing Point
The nominal setting point is 50-100’ into the Lower Aruma shale. Actual
setting points have varied from 227’ above to 257’ below the top of the Lower
Aruma shale. Recent practice has been to set about 50’ below the Lower
Aruma shale top.
The interval between the 13-3/8” casing point and the 9-5/8” is composed of
the lower part of the RUS, the very porous limestones of the Umm er
Radhuma formation, and the somewhat porous limestones of the Aruma
formation. The section is drilled with water due to the large water flow
encountered in the Umm er Radhuma.
The purpose of the casing is to shut off this water flow and any lost circulation
zones below it, so that mud, with full circulation, may be used to drill into the
oil zones (Wasia formation). The casing point must be picked deep enough
into the Aruma so that there is no chance of a water flow or lost circulation
below the shoe.
Thickness of the Lower Aruma shale is extremely variable, due to the effect
of the underlying Wasia-Aruma unconformity.
However, a relatively
consistent increase in drilling time occurs in the lower portion of the Aruma
formation. This represents a change to a more dense limestone, and casing
may safely be set any time after penetrating about 100’ of this lithology. The
increase in drilling time is a sufficient indicator of this point. Ditch samples
are badly contaminated due to the water flow.
The casing is usually cemented in two stages, using a DV packer collar
inside 13-3/8” casing.
7” Casing Point
Setting point of this casing varies according to the type of completion desired.
It is set through the producing zone, and then perforated for production.
Normal completions are either in the Safaniya or Khafji members, with lowest
perforations about 100’ above the oil-water contact.
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The section below the 9-5/8” casing point consists mainly of the sandstones,
shales, and then limestones of the Wasia formation. The section down to the
top of the Caprock limestone may be drilled with water, but the drilling fluid
should be changed to mud before drilling the Caprock and the producing
zones below. Low water loss, fresh water mud is used to minimize formation
damage and provide proper logging environment.
2.22 Shaybah Field
18-5/8” Casing Point
Nominal setting point for this surface conductor is 150’± below the surface.
The purpose of this conductor is to keep the unconsolidated surface sand
from washing out under the rig.
13-3/8” Casing Point
Nominal casing point is 50’ into the RUS.
The purpose of this casing is to isolate the Sabkah water just beneath the
surface from the RUS and Umm Er Radhuma, which have possible water
flow or loss of circulation. The UER water in this area flows to surface and is
used for water supply.
This casing point allows water to be used to drill the remaining RUS and
UER. The kick-off point for horizontal wells is typically just below this casing
point in the RUS formation.
9-5/8” Casing Point
Nominal casing point is 180’ TVD into Aruma Carbonate.
The purpose of this casing is to shut off lost circulation zone or water flow of
the Umm er Radhuma from the underlying Wasia formation and permit drilling
with oil base mud.
The Aruma can be picked at an increase in drill time following a general
decrease over 150’ just above. This can be identified from comparison with
nearby wells. Oil base mud must be used to protect the exposed shales and
to control the Shu’aiba reservoir where this producing zone is overlain with
gas in the crestal area.
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7” Casing Point
Nominal casing point for a horizontal producer is the start of the horizontal
section in the Shu’aiba reservoir.
Total Depth
Total depth is determined by the required lateral length and/or the base of the
Shu’aiba reservoir. Horizontal wells are typically completed as open hole
producers, with a production packer located in the 7” casing.
2.23 Shedgum Field
18-5/8” Casing
In the Shedgum area, the Neogene, Alat, Khobar, RUS, Umm er Radhuma,
and Aruma have nearly the same water quality and static water levels, so do
not need to be separated by casing. In fact, some recharge of the Alat and
Khobar may be taking place by having the zones in communication.
The formations above the Umm er Radhuma are reasonably competent so
that no casing is needed to support them after circulation is lost in the Umm
er Radhuma. Some of the Umm er Radhuma is about 475’ above mean seal
level, which is below the ground level throughout most of the Shedgum area.
The only casing needed above the Lower Aruma casing point is the short
surface conductor. This is commonly 18-5/8” casing and is set only in those
wells where it is needed to support loose sand at the surface.
13-3/8” Casing Point
This casing is normally set in the Lower Aruma shale or Ahmadi limestone.
Its The purpose is to isolate the overlying lost circulation and water zones
and permit drilling the underlying Wasia formation with mud and full
circulation. It also prevents contamination of the Umm er Radhuma aquifer
which supplies Abqaiq with raw water. Nominal casing point is 50’ into the
Lower Aruma shale or Ahmadi limestone.
The object is to pick a casing point which is below any possible water flow or
lost circulation zone in the Aruma formation, so that circulation may be
maintained while drilling the Wasia formation with mud. There must also be
sufficient non-porous rock about the casing point to assure a good cement
job around the casing.
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Some wells on the South West and East flanks had lost circulation after
setting the 13-3/8” casing in the Lower Aruma shale. In such areas it is
advisable to set the 13-3/8” casing in Ahmadi. The top of Lower Aruma shale
and Ahmadi are readily picked by comparison of drill time pattern with nearby
wells. The drilling time decreases at Lower Aruma shale and Ahmadi.
9-5/8” Casing Point
The section between 13-3/8” casing point and the 9-5/8” casing point consists
of the remaining portion of the Lower Aruma shale, the hydroscopic shales
and water sands of the Wasia formation, the Shu’aiba formation (Dolomitic
limestone) and the upper portion of the Biyadh formation (greenish-gray
shale).
The Wasia shales are very water sensitive and a low water loss mud must be
used to keep sloughing to a minimum. Even when the water loss is kept at
3cc or below, some sloughing is encountered. This tends to become worse
as time goes on, so it is best to drill this section as rapidly as possible. Mud
weight must also be great enough to prevent the water in the Wasia sands
from flowing up the hole and contacting the shales. Static water level is 864’
mean sea level.
Circulation is commonly lost in the Shu’aiba formation and drilling proceeds
to the 9-5/8” casing point with water and a mud cap. The mud cap is held
against the Wasia formation, and must be low water loss mud to control
sloughing, as noted above. The Shu’aiba formation is very porous and even
cavernous, so that attempts to regain circulation are expensive and usually
futile.
The nominal casing point is 300’ into the Biyadh. The purpose of this point is
to assure that all the hydroscopic shales of the Biyadh will be behind casing,
so that the next portion of the hole may be drilled with water. The casing also
shuts off the lost circulation zone of the Shu’aiba, so that circulation may be
maintained.
Actual setting depths have varied from 137’ to 671’ below the top of the
Biyadh with most wells in the 250-350’ range. Probable absolute minimum
penetration of the greenish-gray shale which will allow water drilling is 200’.
Nominal casing point should remain at 300’ penetration.
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Key horizons for this casing point are the tops of the Shu’aiba and the
Biyadh. Either may be picked on samples or drill time. The top of the
Shu’aiba is represented by an abrupt change from sand to Dolomite. An
accompanying increase in drilling time occurs about 30-50’ above the top.
The Shu’aiba is 275-300’ thick in Shedgum. If circulation is maintained, the
top of the Biyadh may be picked on the occurrence of shale. If circulation is
lost, a general increase in drill time serves to locate the point.
7” Casing Point
The 7” casing is the production string. It may be set at the top of the
producing zone, or set through and perforated. The practice of setting on top
of the zone and then drilling out and completing barefoot has been the most
common. However, some difficulty has been experienced by setting too high
and not getting a shut off of the sub C stringer, which contains salt water.
The most foolproof completion is to drill through the producing zone, set
casing through it, and then perforate.
The section between the 9-5/8” casing point and the producing zone consists
of the major portion of the Biyadh formation, the limestones of the Thamama
group, including the Sulaiy zone, the High formation anhydrite and limestone,
and the Arab-A, B and C zones. The section is commonly drilled with water
to the top of the Arab-D zone. Minor amounts of shale sloughing from the
Biyadh interval are common, and a water flow is encountered in the Sulaiy
zone up to 5-6 MBPD.
The change to mud is made while drilling the anhydrite above the top of the
Arab-D reservoir. Reservoir pressure has been lowered due to withdrawals
from the field, so lost circulation is possible.
The key horizons for this casing point are the base of the Arab-C reservoir
and the top of the Arab-D. The base of the C may be picked on a change
from calcarenite to anhydrite, with an accompanying increase in drilling time.
Top of the D reservoir is about 100’ below this point, and occurs at the
change from anhydrite back to calcarenite with a decrease in drilling time.
Care must be taken not to confuse one of the porous water bearing stringers
immediately above the D reservoir with the top of the D reservoir itself, as
noted above.
Present completion practice is set to the 7” liner at the top of D reservoir prior
to drilling out to the base of porosity.
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2.24 Uthmaniyah Field
26” Casing Point
Nominal setting depth is 100’± below the surface. The purpose of the casing
is to prevent unconsolidated sand from washing out under the rig. Use of this
casing depends on surface conditions.
18-5/8” Casing Point
This casing has been set in the top of the Eocene to separate the Neogene
water (± 1500 ppm) and the Eogene water (± 1300 ppm) and to support the
Neogene in those areas where it may be unconsolidated. Nominal setting
depth is 50’ below the Eocene/Neogene unconformity; probable safe range is
from Eocene-Neogene unconformity to the base of RUS.
Since the waters of the Neogene, Alat, Khobar and Umm er Radhuma are
similar, about 1300-1500 ppm total solids, and the formation pressures about
the same; the casing is not needed for water separation. In fact, a slight
recharge of the upper formations by the Umm er Radhuma will result if a
separation is not accomplished. Therefore, in areas where the Neogene is
competent, the string may be left out. This will be true in most cases in
Uthmaniyah. Circulation may be lost in any of the formations down to below
the pre-Aruma Unc, so setting the casing to regain circulation is futile.
13-3/8” Casing Point
Nominal casing point for this string is 50’ into the Lower Aruma shale or
Ahmadi limestone. Many wells on the flanks of the field lost circulation below
the Pre-Aruma unconformity after drilling out of the 13-3/8” casing set in
Lower Aruma shale. It is advisable to set 13-3/8” casing in the Ahmadi on
wells located at the flanks.
The purpose of the casing is to shut off all possible lost circulation zones or
water flow, so that Wasia may be drilled with mud. The casing also serves to
separate the flow of Wasia from the upper formations.
A characteristic increase in drilling time occurs some 100-200’ above the top
of Lower Aruma shale and may represent the minimum safe casing point.
The top is usually indicated by a subsequent decrease in drill time, commonly
followed by an increase. The pattern is reasonably consistent from well to
well, so that it is not a difficult pick to make.
46 of 52
SAUDI ARAMCO
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
B
DRILLING MANUAL
JUNE 2006
DRILLING PRACTICES
CASING
__________________________________________________________________________________________________________________________
The top of Ahmadi limestone is also readily picked from drill time comparison.
9-5/8” Casing Point
Nominal setting point for this casing is 300’ into the Biyadh formation
(greenish-gray shale). Actual setting points have varied.
The purpose of the string is to shut off the lost circulation of the Shu’aiba
formation (Dolomitic Limestone). The casing also protects the hydroscopic
shales in the upper portion of the Biyadh formation and must be set through
these in order to drill with water below the casing point.
Probable minimum penetration which will allow water drilling below is about
200’. However, since some difficulty is often encountered in washing casing
to bottom, a minimum of 300’ penetration should be specified.
The top of the Shu’aiba formation may be picked either on samples or drill
time. The lithologic change is from sand to dolomite, and circulation is usually
lost below the top. The top of the Biyadh occurs about 200-250’ below, and
is less easily picked. Drill time pattern is irregular, but the pick can be made
by comparison with nearby wells.
The section down to the top of the producing zone (Arab-D) may be drilled
with water. The change to mud may be made while drilling the anhydrite unit
below the base of the C reservoir.
7” Casing Point
Nominal casing point is the top of the Arab-D reservoir. The purpose of the
casing is to case off all water zones above the producing zone and to get the
overlying sub ‘C’ stringer behind pipe.
Present practice is to run a liner rather than a full string. The casing is set
prior to drilling into the ‘D’ reservoir. The presence of salt water in the sub ’C’
stringer which is 20-40’ above the Arab-D reservoir makes the casing point
pick critical.
The tops and bases of Arab zones are readily picked on drill time by
comparison with nearby wells.
47 of 52
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
B
JUNE 2006
DRILLING PRACTICES
CASING
__________________________________________________________________________________________________________________________
2.25 Zuluf Field
30” Conductor Pipe
This is a conductor pile driven into the sea floor when the platform is set, prior
to moving the rig on location. It is driven to refusal, but not cemented. The
purpose of the conductor is to return drilling fluids to the surface while drilling
to the first casing point at the top of the Eocene.
13-3/8” Casing Point
Nominal setting depth is 25’ into the RUS formation.
This section consists of the Alat limestones and marls. Khobar dolomite,
limestone, and marl, the thin limestones and marls of the Alveolina zone, and
the anhydrite and thin limestones of the RUS formation. Circulation may be
lost in the Khobar.
The top of the RUS may be picked either on samples or drill time. The
lithology changes abruptly from the blue gray marl containing Alveolina, to
calcarenitic limestone and then to anhydrite or gypsum. The top is picked at
the top of the calcarenitic limestone.
On drill time, the bit tends to ball up through the Alveolina zone, giving an
increase in drilling time. The first few feet of the RUS usually drill faster, then
the drill time may increase again as the gypsum and anhydrite are
penetrated. This pattern varies somewhat from well to well, and nearby wells
should be checked carefully when picking this point. Circulation is usually
maintained to this casing point so samples are available.
9-5/8” Casing Point
The nominal setting point is 50-100’ into the Lower Aruma shale.
The interval between 13-3/8” casing point and the 9-5/8” is composed of the
lower part of the RUS, the very porous limestones of the Umm er Radhuma
formation, and the somewhat porous limestones of the Arum formation. The
section is drilled with water due to the large water flow encountered in the
Umm er Radhuma.
48 of 52
SAUDI ARAMCO
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
B
DRILLING MANUAL
JUNE 2006
DRILLING PRACTICES
CASING
__________________________________________________________________________________________________________________________
The purpose of the casing is to shut off this water flow and any lost circulation
zones below it, so that mud, with full circulation, may be used to drill into the
oil zones (Wasia formation). The casing point must be picked deep enough
into the Aruma so that there is no chance of a water flow or lost circulation
below the shoe.
Thickness of the Lower Aruma shale is extremely variable due to the effect of
the underlying Wasia-Aruma unconformity. However a relatively consistent
increase in drilling time occurs in the lower portion of the Aruma formation.
This represents a change to a more dense limestone, and casing may safely
be set any time after penetrating about 100’ of this lithology. The increase in
drilling time is a sufficient indicator of this point. Ditch samples are badly
contaminated due to the water flow.
This casing is cemented in two stages using a DV packer collar inside the 133/8” casing.
7” Casing Point
Setting point of this casing varies according to the type of completion desired.
It is set through the producing zone, and then perforated for production.
Normal completions are in the Khafji member, with lowest perforations about
100’ above the oil-water contact.
The section below the 9-5/8” casing point consists mainly of the sandstones,
shales, and then limestones of the Wasia formation. The section down to the
top of the Caprock limestone may be drilled with water, but the drilling fluid
should be changed to mud before drilling the Caprock and the producing
zones below. Low water loss, fresh water mud is used to minimize formation
damage and provide proper logging environment.
3.0
CASING INSPECTION
3.1
Khuff, Deep & Exploration Wells
The 36”, 30” and 24” casing will be externally coated with FBE (fusion bonded
epoxy). The 18-5/8” casing will be externally coated FBE from the shoe to the DV.
The 13-3/8” casing will be externally coated FBE from 8500’ to the upper DV.
49 of 52
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
JUNE 2006
DRILLING PRACTICES
B
CASING
__________________________________________________________________________________________________________________________
The rig crew should inspect all casing and tubing after shipment as follows:
x
Clean and visually inspect all threads. Use casing dope for thread
compound.
x Run API full length drift.
x Visually inspect for overall damage.
The contracted inspection company (PWS, Vetco or other) should inspect all
casing and tubing (13-3/8” and smaller) before shipment to the rig as follows:
x
x
x
Clean and inspect all threads.
Visually inspect for overall damage.
Electromagnetic inspection (4 functions); Longitudinal, Traverse, Wall
Thickness, Grade Verification
3.2 Development Wells
Prior to running the 13-3/8” casing and subsequent strings, insure that the
following has been conducted.
x
x
x
x
NOTE:
[1]
[2]
NOTE:
Run full-length API drift.
Clean and visually inspect threads.
Visually inspect tubes for damage.
Use casing dope for thread compound.
TABLE 4.0
SAUDI ARAMCO CASING DATA
Internal yield values (*) listed on page 51 reflect the lower value for buttress couplings.
Value provided is the minimum value, either pipe body strength or joint strength.
TABLE 5.0
KHUFF CASING & TUBING DATA
[1]
[2]
[3]
Internal yield values (*) listed on page 52 reflect the lower value for buttress couplings.
Value provided is the minimum value, either pipe body strength or joint strength.
The RL-4S connector ID is less than that of the LS connector.
[4]
The Hydril PH-6 connector ID is less than that of the pipe body.
(RL-4S = 22.250” ID, LS = 22.624” ID)
(Conn. = 2.687” ID, Body = 2.750” ID)
i
’
50 of 52
Tubulars that are being phased out.
Completion accessory items. [Flow Coupling, 'R' Landing Nipple, Seal Assembly]
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
B
JUNE 2006
DRILLING PRACTICES
CASING
__________________________________________________________________________________________________________________________
4.0
SIZE
SAUDI ARAMCO CASING DATA
WEIGHT
GRADE
CONNECTION
I.D.
DRIFT
CONN. O.D.
BURST
COLLAPSE
in.
ppf
in.
in.
in.
psi
psi
JT/ YLD
STRENGTH
1,000's lbs.
24
24
97.00
176.00
B
X-42
SJ
VETCO-LS
23.25
22.624
22.250
25.500
2170
1080
2,116
18-5/8
18-5/8
87.50
87.50
J-55
K-55
BTC
BTC
17.755
17.755
17.567
17.567
19.625
19.625
2250
2250
630
630
1,329
1,367
13-3/8
13-3/8
13-3/8
13-3/8
13-3/8
13-3/8
13-3/8
13-3/8
61.00
61.00
68.00
68.00
68.00
68.00
72.00
72.00
J-55
K-55
J-55
K-55
J-55
K-55
L-80
S-95
STC
STC
STC
STC
BTC
BTC
STC
BTC
12.515
12.515
12.415
12.415
12.415
12.415
12.347
12.347
12.359
12.359
12.259
12.259
12.259
12.259
12.191
12.250
14.375
14.375
14.375
14.375
14.375
14.375
14.375
14.375
3090
3090
3450
3450
3450
3450
4550
4930 *
1540
1540
1950
1950
1950
1950
2670
3470
595
633
675
718
1,069
1,069
1,040
1,935
9-5/8
9-5/8
9-5/8
9-5/8
9-5/8
9-5/8
9-5/8
9-5/8
9-5/8
36.00
36.00
40.00
40.00
40.00
40.00
43.50
47.00
53.50
J-55
K-55
J-55
K-55
L-80
13CR L-80
L-80
L-80
S-95
LTC
LTC
LTC
LTC
LTC
LTC
LTC
LTC
BTC
8.921
8.921
8.835
8.835
8.835
8.835
8.755
8.681
8.535
8.765
8.765
8.679
8.679
8.679
8.679
8.599
8.525
8.500
10.625
10.625
10.625
10.625
10.625
10.625
10.625
10.625
10.625
3520
3520
3950
3950
5750
5750
6330
6870
9160 *
2020
2020
2570
2570
3090
3090
3810
4760
8850
453
489
520
561
727
727
813
893
1,477
7
7
7
7
7
7
7
7
7
7
23.00
26.00
26.00
26.00
26.00
26.00
26.00
26.00
35.00
35.00
J-55
J-55
K-55
J-55
K-55
J-55
K-55
13CR L-80
L-80
L-80
STC
LTC
LTC
VAM
VAM
NVAM
NVAM
LTC
LTC
VAM
6.366
6.276
6.276
6.276
6.276
6.276
6.276
6.276
6.004
6.004
6.241
6.151
6.151
6.151
6.151
6.151
6.151
6.151
5.879
5.879
7.656
7.656
7.656
7.681
7.681
7.681
7.681
7.656
7.656
7.681
4360
4980
4980
4980
4980
4980
4980
7240
9240
9960
3270
4320
4320
4320
4320
4320
4320
5410
10180
10180
284
367
401
415
415
415
415
511
734
725
5
5
15.00
15.00
K-55
13CR L-80
Spec. Cl. BTC
Spec. Cl. BTC
4.408
4.408
4.283
4.283
5.375
5.375
5130
7460
5560
7250
241
350
4-1/2
4-1/2
4-1/2
4-1/2
4-1/2
11.60
11.60
11.60
12.60
13.50
J-55
J-55
13CR L-80
J-55
L-80
STC
LTC
LTC
VAM
VAM
4.000
4.000
4.000
3.958
3.920
3.875
3.875
3.875
3.833
3.795
5.000
5.000
5.000
4.892
4.862
5350
5350
7780
5790
8540
4960
4960
6350
5720
9020
154
162
212
198
211
51 of 52
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
JUNE 2006
DRILLING PRACTICES
B
CASING
__________________________________________________________________________________________________________________________
5.0
SIZE
KHUFF CASING & TUBING DATA
WEIGHT
GRADE
CONN
LENGTH
wt.
I.D.
DRIFT
in.
psi
psi
JT/ YLD
STRENGTH
1,000's lbs.
in.
48.000
36.000
25.500
25.250
1822
1890
2170
2170
254
768
1080
1080
2,116
2,116
17.249
20.000
3070
1511
1,850
12.347
"
"
"
"
12.250
"
"
"
"
14.375
14.375
14.398
14.398
14.375
4930 *
6390
6390
6390
6390
3470
3680
3900
3680
3890
1,935
1,935
1,935
1,935
1,973
0.625
"
"
"
12.125
"
"
"
12.000
"
"
"
14.375
14.398
14.398
14.375
7770
7770
7770
7760
6260
6560
6240
6500
2,333
2,333
2,333
2,333
R-3
R-3
R-3
R-3
R-3
0.545
"
"
"
"
8.535
"
"
"
"
8.500
"
"
"
"
10.625
10.625
10.650
10.650
10.625
9160 *
8920
9410
9410
9410
8850
9330
8960
9350
8940
1,477
1,386
1,477
1,477
1,477
NS-CC
R-3
0.595
8.435
8.375
10.625
11900
12050
1,739
NS-CC
N-VAM
N-VAM
NK-3SB
R-3
R-3
R-3
R-3
"
"
"
"
"
"
"
"
"
"
"
"
10.625
10.650
10.650
10.625
11960
11900
11900
11900
12870
11880
12800
12860
1,857
1,857
1,857
1,857
NS-CC
NVAM-MS
NVAM-MS
NK-3SB
R-3
R-3
R-3
R-3
0.453
"
"
"
6.094
"
"
"
6.000
"
"
"
7.656
7.732
7.732
7.772
10760
10760
10760
10760
11380
11160
11190
11150
885
885
885
885
L-80
NS-CC
R-3
0.498
6.004
5.879
7.656
9960
10180
814
L-80
NVAM-MS
R-3
"
"
"
7.805
9960
10180
814
35
L-80
NK-3SB
R-3
"
"
"
7.772
9960
10180
814
23
20
20
20
20
L-80
NT-95HSS
C-95VTS
SM-95TS
NKAC-95T
N-VAM
NS-CC
N-VAM
N-VAM
NK-3SB
Tbg. Hngr
R-3
R-3
R-3
R-3
0.415
0.361
"
"
"
4.670
4.778
"
"
"
4.545
4.653
"
"
"
6.075
6.050
6.075
6.075
6.050
10560
10910
10910
10910
10910
11160
11580
11410
11450
11400
478
554
554
554
554
in.
ppf
range
in.
in.
48
36
30
24
24
253
236
234
176
176
B
X-60
X-42
X-42
X-42
BE
BE
SJ
LS
RL-4S
40’
40'
55-60'
R-3
R-3
0.500
0.625
0.750
0.688
0.688
47.000
34.750
28.500
22.624
18-5/8
115
K-55
BTC
R-3
0.594
17.437
13-3/8
13-3/8
13-3/8
13-3/8
13-3/8
72
72
72
72
72
S-95
NT-95HS
C-95VT
SM-95T
NKHC-95
BTC
NS-CC
N-VAM
N-VAM
NK-3SB
R-3
R-3
R-3
R-3
R-3
0.514
"
"
"
"
13-3/8
13-3/8
13-3/8
13-3/8
86
86
86
86
NT-95HS
C-95VT
SM-95T
NKHC-95
NS-CC
N-VAM
N-VAM
NK-3SB
R-3
R-3
R-3
R-3
9-5/8
9-5/8
9-5/8
9-5/8
9-5/8
53.5
53.5
53.5
53.5
53.5
S-95
NT-90HSS
C-95VTS
SM-95TS
NKAC-95T
BTC
NS-CC
N-VAM
N-VAM
NK-3SB
9-5/8
58.4
9-5/8
9-5/8
9-5/8
9-5/8
58.4
58.4
58.4
58.4
NT105HSS
NT-110HS
P-110VT
SM-110T
NKHC-110
7
7
7
7
32
32
32
32
NT-95HSS
C-95VTS
SM-95TS
NKAC-95T
i7
i7
i7
35
35
’
5-1/2
5-1/2
5-1/2
5-1/2
5-1/2
22.250
22.25 (con) 22.125
CONN. O.D.
BURST
COLLAPSE
’
15.1
L-80
N-VAM
Tbg. Hngr
0.337
3.826
3.701
5.010
10480
11080
353
NT-95HSS
C-95VTS
SM-95TS
NKAC-95T
L-80
D-95HC
KO-105T
NS-CC
N-VAM
N-VAM
NK-3SB
N-VAM
HYDRIL TS
HYDRIL TS
R-3
R-3
R-3
R-3
R-3
R-3
R-3
0.290
"
"
"
0.290
"
"
3.920
"
"
"
3.920
"
i4-1/2
13.5
13.5
13.5
13.5
13.5
13.5
13.5
3.840(con)
3.795
"
"
"
3.795
"
"
5.000
4.961
4.961
5.000
4.961
4.719
"
10710
10710
10710
10710
9020
10720
10710
11330
11090
11120
11080
8540
12070
11280
364
364
364
364
307
300
295
3-1/2
12.95
L-80
HYDRIL PH-6
R-2
0.375
2.687(con)
2.625
4.313
15000
15310
295
4-1/2
4-1/2
4-1/2
4-1/2
4-1/2
4-1/2
4-1/2
52 of 52
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
C
June 2006
DRILLING PRACTICES
RUNNING CASING AND LINERS
___________________________________________________________________________________________________________________________
RUNNING CASING AND LINERS
1.0 CASING RUNNING GUIDELINES
1.1
1.2
1.3
1.4
1.5
1.6
1.7
1.8
1.9
1.10
1.11
1.12
1.13
1.14
1.15
Hook Load Requirement
1.1.1 Hoisting System
1.1.2 Determining Maximum Pull
Equipment Inspection
Casing Inspection
1.3.1 Electromagnetic Inspection
1.3.2 Grade Verification
1.3.3 Thread Inspection
1.3.4 Drifting
Casing Tally
Float Equipment
Centralizers
Elevators
Casing Setting Depth
1.8.1 Wiper Trip
1.8.2 Strapping Out
1.8.3 Conditioning Trip
1.8.4 Pulling Wear Bushing
1.8.5 Drifting Inner String
Changing and Testing BOP Rams
Threadlock vs. Welding
Casing Make-up
1.11.1 Thread Lubricants
1.11.2 Make-up Torque
Fill Requirements
Running Speed
Breaking Circulation
Landing Casing
1.15.1 Setting Slips
1.15.2 Landing Load
2.0 ADDITIONAL GUIDELINES FOR RUNNING LINERS
2.1
2.2
2.3
2.4
2.5
2.6
2.7
General Instructions
Float Equipment and Landing Collar
Wiper Plugs
Liner Hanger
Cement Manifold
Fill Requirements
Running Speed
SAUDI ARAMCO
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
C
DRILLING MANUAL
June 2006
DRILLING PRACTICES
RUNNING CASING AND LINERS
___________________________________________________________________________________________________________________________
2.8
2.9
Breaking Circulation
Setting Liner Hanger
3.0 FLOAT EQUIPMENT
3.1
3.2
3.3
3.4
Inner String Cementing
Float Shoe
Float Collar
Plug Set
4.0 MULTI-STAGE PACKER COLLAR
4.1
4.2
4.3
Tool Illustrations/Technical Data
Free Fall Plug Set
Displacement Type Plug Set
5.0 CENTRALIZERS
5.1
5.2
5.3
Collapsible
Rigid
SpiraGlider
6.0 LINER HANGERS
6.1
6.2
6.3
Mechanical-Set Liner Hanger
Hydraulic-Set Liner Hanger
Associated Equipment
6.3.1 Setting Collar/Tieback Sleeve
6.3.2 Liner Top Packer
6.3.3 Polished Bore Receptacle
6.3.4 Cementing Manifold
______________________________________________________________________________
1 of 46
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
DRILLING PRACTICES
SECTION
RUNNING CASING AND LINERS
C
June 2006
___________________________________________________________________________________________________________________________
RUNNING CASING AND LINERS
The purpose of this chapter is to present (1) casing running guidelines, (2) additional
liner running requirements, and (3) down-hole equipment associated with these
operations.
1.0
CASING RUNNING GUIDELINES
Casing has become one of the most expensive parts of a drilling program. Post
well evaluations have shown that the average cost of tubulars is approximately
20% of the completed well cost. More importantly, if these tubulars are not run
properly, the success of the entire well could be jeopardized. Thus, an important
responsibility of the Drilling Engineer and Drilling Foreman is to develop and
execute a casing running procedure that will result in minimal risk and ensure the
success of the operation.
The following casing running guidelines are provided to aid the Drilling Engineer
and Drilling Foreman in developing a sound work plan for running casing. It must
be noted that these guidelines are subject to specific well conditions.
1.1
Hook Load Requirement
The hoisting system capacity (mast, hook, traveling block, as well as the
number and condition of lines) should be checked and compared to the
calculated hook load for the next casing string. If additional lines are required,
the string-up shall be done at least one trip prior to running casing.
1.1.1
Hoisting System
A hoisting system is a way of lifting heavy loads with a lighter lead line
pulling force. As with a simple pulley system, the line strung through
the blocks creates a mechanical advantage. This mechanical
advantage is equal to the number of lines strung between the crown
and traveling block. Thus for a 12-line system, without friction, a given
weight can be lifted with a pulling force of 1/12 of the weight as shown
in Figure 2C-1.
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SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
C
June 2006
DRILLING PRACTICES
RUNNING CASING AND LINERS
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Dead Line
Fast Line
12 LINE HOISTING SYSTEM
Figure 2C-1
1.1.2
Determining Maximum Pull
The fast line during hoisting has a somewhat greater load than the
weight divided by the number of lines. This results from the friction of
the sheave bearings and the bending of the line around the sheave.
Since the fast line experiences the accumulation of frictional forces
from all of the rotating sheaves, its load is the greatest and should be
used when calculating design factors.
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SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
DRILLING PRACTICES
SECTION
RUNNING CASING AND LINERS
C
June 2006
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The fast line load can be calculated as follows,
where,
L
= W x Ks (K-1)
Kn -1
L
W
K
n
s
=
=
=
=
=
Load on Fast Line (lbs)
Total String Weight with *Overpull (lbs)
1.04 (coefficient of friction of roller bearing sheaves)
Number of Lines
Number of Sheaves
Note:
s = n (for most rigs; since the deadline does not rotate)
* Overpull = 50,000 -100,00lbs (margin for working stuck pipe)
Thus, the design factor can be calculated as follows,
where,
DF = B
L
DF = Design Factor for Drilling Line
B = Nominal Catalog Breaking Strength (lbs)
L = Load on Fast Line (lbs)
Note:
Minimum Design Factor = 2.0 (when setting casing)
When a drilling line is operated near its minimum design factor, care
should be taken that the line and related equipment is in good
operating condition.
The Drilling Manager‘s approval is required for casing loads resulting
in a design factor < 2.0 with maximum line capacity. Floating the
casing to bottom may be a consideration.
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SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
June 2006
DRILLING PRACTICES
C
RUNNING CASING AND LINERS
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DESIGN FACTORS FOR VARIOUS NUMBER OF LINES AND HOOKLOADS
(ALL CALCULATIONS BASED UPON NEW 6 x 19 IWC WIRE ROPE)
Design Factor
HOOK
LOAD
LINES
FAST LINE
LOAD
I.P.
200 M
EIPS
6
8
10
(LBS)
38,200
29,600
24,600
2.3
3.0
3.6
2.7
3.5
4.2
3.
3.8
4.6
3.4
4.4
5.3
3.6
4.7
5.6
4.2
5.3
6.5
4.4
5.6
6.8
5.
6.5
7.8
5.2
6.7
8
6.
7.7
9.2
250M
6
8
10
12
47,750
37,000
30,750
26,500
1.9
2.4
2.9
3.4
2.1
2.8
3.4
3.9
2.4
3.
3.7
4.2
2.8
3.5
4.2
4.9
2.9
3.7
4.5
5.2
3.3
4.3
5.2
6.
3.5
4.5
5.3
6.3
4.
5.2
6.2
7.2
4.2
5.3
6.4
7.5
4.8
6.1
7.4
8.6
300 M
6
8
10
12
57,300
44,400
36,900
31,800
2.
2.4
2.8
2.3
2.8
3.2
2.
2.5
3.
3.5
2.3
2.9
3.5
4.1
2.4
3.1
3.7
4.4
2.8
3.6
4.3
5.
2.9
3.7
4.5
5.2
3.3
4.3
5.2
6.
4.
4.5
5.3
6.2
5.1
6.2
7.1
6
8
10
12
66,850
51,800
43,050
37,100
1.7
2.1
2.4
2.
2.4
2.8
2.2
2.6
3.
2.5
3.
3.5
2.1
2.7
3.2
3.7
2.4
3.1
3.7
4.3
2.5
3.2
3.9
4.5
2.9
3.7
4.5
5.2
2.9
3.8
4.6
5.3
3.4
4.4
5.3
6.1
4.4
5.3
6.2
5.1
6.0
7.1
5.1
6.2
7.1
5.9
7.1
8.2
8
10
12
59,200
49,200
42,400
1.8
2.1
2.1
2.4
1.9
2.4
2.7
2.2
2.6
3.
2.3
2.8
3.3
2.7
3.2
3.8
2.8
3.4
3.9
3.2
3.9
4.5
3.3
4.
4.6
3.8
4.6
5.3
3.9
4.6
5.3
4.5
5.3
6.2
4.5
5.4
6.3
5.2
6.2
7.2
8
10
12
66,600
55,350
47,700
2.0
2.3
2.3
2.7
2.0
2.5
2.9
2.4
2.8
3.3
2.5
3.0
3.5
2.8
3.4
4.0
2.9
3.6
4.1
3.4
4.1
4.8
3.4
4.2
4.8
4.0
4.8
5.5
4.0
4.8
5.5
4.7
5.5
6.4
8
10
12
14
74,000
61,500
53,000
47,500
1.8
2.1
2.3
2.1
2.4
2.7
1.9
2.2
2.6
2.9
2.1
2.6
3.
3.3
2.2
2.7
3.1
3.5
2.6
3.1
3.6
4.0
2.7
3.2
3.7
4.1
3.1
3.7
4.3
4.8
3.1
3.7
4.2
4.8
3.6
4.3
5.0
5.5
3.6
4.3
5.0
5.6
4.1
5.0
5.7
6.4
8
10
12
14
88,800
73,800
63,600
57,000
1.8
2.0
2.
2.2
1.9
2.2
2.4
2.1
2.5
2.8
1.9
2.2
2.6
2.9
2.1
2.6
3.
3.3
2.2
2.7
3.1
3.4
2.5
3.1
3.6
4.0
2.6
3.1
3.6
4.0
3.0
3.6
4.1
4.6
3.0
3.6
4.2
4.6
3.4
4.1
4.8
5.3
8
10
12
14
103,600
86,100
74,200
66,500
1.8
2.0
2.1
2.4
1.9
2.2
2.5
2.2
2.6
2.8
1.9
2.3
2.7
2.9
2.2
2.6
3.1
3.4
2.2
2.7
3.1
3.4
2.5
3.0
3.5
3.9
2.5
3.1
3.6
4.0
3.0
3.5
4.1
4.6
8
10
12
14
118,400
98,400
84,800
76,000
1.7
1.97
2.2
1.95
2.28
2.53
2.0
2.3
2.6
2.3
2.7
3.0
1.9
2.3
2.7
3.0
2.2
2.6
3.1
3.4
2.2
2.7
3.1
3.5
2.6
3.1
3.6
4.0
8
10
12
14
133,200
110,700
95,400
85,400
1.75
1.96
1.74
2.01
2.25
1.79
2.08
2.32
1.70
2.05
2.39
2.67
1.87
2.41
2.7
1.9
2.3
2.7
3.1
2.0
2.3
2.8
3.1
2.3
2.7
3.2
3.58
10
12
14
16
123,000
106,000
95,000
86,000
1.81
2.02
1.86
2.08
2.3
1.85
2.15
2.4
2.6
1.89
2.17
2.42
2.6
2.14
2.5
2.78
2.8
2.16
2.51
2.80
2.8
2.49
2.89
3.22
3.5
350 M
400 M
450 M
500 M
600 M
700 M
800 M
900 M
1000 M
Note:
1”
I.P.
1-1/8”
EIPS
I.P.
1-1/4”
EIPS
I.P.
1-3/8”
EIPS
I.P.
1-1/2”
EIPS
I.P.
1-5/8”
EIPS
I.P.
1-3/4”
EIPS
1. This table is based upon Extra Improved Plow and Improved Plow drilling line (with independent wire rope cores).
2. If a well is highly deviated (with high drag forces), an overpull (50,000 to 100,000 lbs) may be desired. In this case,
the overpull margin must be added to the calculated casing weight to determine the maximum hook load.
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SAUDI ARAMCO
Drilling & Workover Engineering Department
CHAPTER 2
DRILLING PRACTICES
SECTION
RUNNING CASING AND LINERS
C
DRILLING MANUAL
June 2006
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1.2
Equipment Inspection
A complete field inspection by magnetic particle method of elevators, bails,
spiders, slips, and hook shall be performed on each rig at least annually. This
inspection should be carried out prior to the job on extremely heavy casing
loads where minimum design factors are approached.
1.3
Casing Inspection
1.3.1
Required Electromagnetic Inspection
Be aware of the required casing inspection and that it is detailed in the drilling
program. If electromagnetic inspection is required, this must be specified by
the Drilling Foreman when the casing is ordered from the Dispatcher and
performed by the inspection company prior to delivery to the rigsite.
1.3.2
Visual Casing Grade Verification
The API color codes listed below are used for all sizes/weights of casing and
tubing to identify the grade. This color code identification is located on the
casing coupling.
Casing Grade Verification:
P110 - One White Band
C95 - One Yellow Band
N80 - One Red Band
C75 - One Blue Band
K55 - One Green Band
H40 - No Marking
Weight and grade identification may also be stenciled on the pipe body.
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SAUDI ARAMCO
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CHAPTER 2
SECTION
DRILLING MANUAL
June 2006
DRILLING PRACTICES
C
RUNNING CASING AND LINERS
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1.3.3
Visual Thread Inspection
When the casing is delivered and racked by grade, remove protectors
and thoroughly clean casing threads. Visually inspect threads for
damage or manufacturing defects. Re-install thread protectors if pipe
is to be moved.
1.3.4
Drifting
Drift casing with API full-length drift. Defective joints are to be clearly
marked and removed to a separate area.
1.4
Casing Tally
The casing is tallied by layer and numbered appropriately, in order in which
the joints are to be run. The casing tally should be independently checked by
both the Toolpusher and Drilling Foreman. Thread protectors shall be
replaced to avoid damage during handling. A running list is essential and
should include the following:
♦
♦
♦
♦
♦
♦
♦
♦
1.5
Joints to be excluded.
Amount of stick-up above rotary table.
Position of casing collar in BOP stack.
Location of centralizers.
Change points for casing grade.
Location of DV’s (if required).
Location of marker joints (if required).
Location of Float Equipment.
Float Equipment
The float equipment should be made-up and threadlocked (along with the
entire shoe track) in the rotary table with power tongs to ensure the proper
torque is applied. This procedure involves only threadlocking the field-end of
the casing coupling (as the mill-end of the coupling is not threadlocked).
Historically, this procedure has proven effective. If casing back-off is a
concern, casing couplings on the shoe track should be removed,
threadlocked, and retorqued at float equipment vendor’s facility. As an
alternative, multi-stage packer collars (DV’s) could also be made-up with (2)
short joints at vendor’s facility to reduce rig time while handling and making
up.
All float equipment, multi-stage packer collar(s), opening bombs, and
associated plugs shall be visually checked once on location.
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SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
DRILLING PRACTICES
SECTION
RUNNING CASING AND LINERS
C
June 2006
___________________________________________________________________________________________________________________________
1.6
Centralizers
Install centralizers on the rack in the middle of the appropriate joints as per
running list.
1.7
Elevators
All casing lifting/setting equipment shall be visually inspected prior to the job.
If ‘side door’ elevators are to be used, check for uneven wear and verify
that the casing load will be uniformly distributed over the face of the casing
coupling. When ‘side-door’ elevators are in use, avoid impact loading which
can open this type of elevator. Care must be taken when running centralizers
through the BOP stack and wellhead. If ‘side door ‘ elevators are used to start
a heavy casing string, always switch to ‘slip type’ elevators before entering
the open hole.
The ‘slip type’ elevator is recommended for long heavy casing strings. If
‘slip type’ elevators are to be used, the spider and elevator slips should be
examined and verified for even distribution. The spider must be level for
proper operation and load distribution. If the slips contact unevenly, there is a
possibility of denting or slip-cutting the pipe. Also, the spider and elevator
slips should be clean and sharp.
1.8
Casing Setting Depth
Casing setting depth is generally referenced to a formation top. Occasionally
the drill bit will quit or experience extremely low ROP just prior to reaching the
projected depth. In these situations, the Drilling Engineer should consult with
Geology or Reservoir Engineering regarding the following options:
♦ Obtaining approval for a revised casing point.
♦ Logging at this depth and drilling additional rat hole, if required.
♦ Continuing drilling to original casing point.
1.8.1
Wiper Trip
The mud shall be conditioned to the desired properties. Controlled fluid loss
and Torq-Trim additions are required on deviated/horizontal wells where
differential sticking is a concern. A flow check should performed prior to
pulling out of the hole. The wiper trip shall be made to the previous casing
shoe and the trip tank monitored to ensure the hole is stable. After running
back to bottom, circulate bottoms-up and pull out of the hole. A flow check
should also be conducted at the casing shoe and again at the drill collars.
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CHAPTER 2
SECTION
C
DRILLING MANUAL
June 2006
DRILLING PRACTICES
RUNNING CASING AND LINERS
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1.8.2
Strapping Out
The casing setting depth must be checked by strapping-out of the
hole at least once prior to logging or running casing. If this
measurement does not agree with hole depth, the pipe should be restrapped.
1.8.3
Conditioning Trip
A conditioning trip should be planned prior to running casing if hole
problems were encountered during logging or if the logging program
required additional time (>10 hours). This decision is made on
location by the Drilling Foreman.
1.8.4
Pulling Wear Bushing
The wear bushing must be retrieved after the last trip out of hole with
the drill string prior to running casing.
1.8.5
Drifting Inner String
On inner string cementing operations, all drill pipe being used as the
inner string should be drifted with the correct size ‘rabbit’ to ensure
adequate clearance for the drill pipe latch down plug.
1.9
Changing and Testing BOP Rams
Casing rams shall be installed on all Class ‘A’ BOP stacks prior to running
casing. The pressure test will consist of testing the casing rams with a joint of
casing connected to the test plug with appropriate crossover.
The annular will be used as casing rams on all Class ‘B’ BOP stacks, since
the blind rams are on top of the master pipe rams.
1.10 Threadlock vs. Welding
All heat treated casing (C75 and above) shall not be welded, as mechanical
properties can be altered through welding operations. The shoe track should
be welded (for H40, X42, J55, K55, material) and threadlocked (for C75, L80,
N80, C95, S95, etc.). Apply ‘threadlock’ to the pin-end only and wipe off
excess to prevent threadlock from falling inside the float equipment.
Threadlock has a greater friction factor than thread compound; consequently,
a higher make-up torque is required (see Section 1.11.1 of this chapter).
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SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
June 2006
CHAPTER 2
DRILLING PRACTICES
SECTION
RUNNING CASING AND LINERS
C
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1.11 Casing Make-Up
The actual casing make-up is a function of the applied make-up torque and
the thread lubricant used. This assumes the torque gauge is properly
calibrated.
1.11.1 Thread Lubricants
An API Modified thread compound with a friction coefficient of 1 shall
always be used. All published make-up torque values assume a
friction factor of 1. Thread protectors should be removed on the rig
floor and thread lubricant applied to pin-end only prior to stabbing
each joint.
The table below shows the associated friction factors for thread
compounds and threadlock used by Saudi Aramco.
Thread Compound
Wfd Lube Seal
Bestolife 270
Wfd Tube Lok
Friction Factor
1.0
1.0
1.5
Note: Actual Torque = Torque Reading x Friction Factor
1.11.2 Make-Up Torque
Use only the recommended make-up torque and ensure that each
joint of casing is correctly made up. The optimum make-up torque
value is recommended at all times. Although if several threads are
exposed when the optimum torque is reached, apply additional torque
to the maximum torque value. In addition, if the make-up is such that
the thread vanish point is buried two thread turns and the minimum
torque value is not reached, the joint should be treated as a bad joint
and moved to a separate area.
Make-up for Buttress Thread Connections (BTC) should be
determined by carefully noting the torque required to make-up several
connections to the base of the triangle. Having established this torque
value, the remainder of that weight and grade of pipe in the string can
be made up accordingly. The make-up tolerance is + 3/8” measured
from the base of the triangle, providing that the make-up torque is
reached.
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SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
June 2006
DRILLING PRACTICES
C
RUNNING CASING AND LINERS
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The following table below shows the recommended make-up for the casing and tubing
commonly used by Saudi Aramco.
RECOMMENDED MAKE-UP TABLE
SAUDI ARAMCO
NON-PREMIUM CASING/TUBING
CONDUCTOR CASING
Minimum
(ft-lbs.)
Optimum
(ft-lbs.)
Maximum
(ft-lbs.)
-
WELD
WELD
-
26,000
WELD
WELD
29,000
32,000
24,000
24,000
WELD
26,000
26,000
28,000
28,000
18-5/8” 87.50# K-55, R-3, BTC
18-5/8” 115.00# K-55, R-3, BTC
Base of Triangle
Base of Triangle
Base of Triangle
Base of Triangle
Base of Triangle
Base of Triangle
13-3/8”
13-3/8”
13-3/8”
13-3/8”
13-3/8”
61.00#
61.00#
68.00#
72.00#
72.00#
J-55,
K-55,
K-55,
L-80,
S-95,
R-3,
R-3,
R-3,
R-3,
R-3,
STC
STC
BTC
STC
BTC
4,460
4,750
Base of Triangle
7,720
Base of Triangle
5,950
6,330
Base of Triangle
10,290
Base of Triangle
7,440
7,910
Base of Triangle
12,860
Base of Triangle
9-5/8”
9-5/8”
9-5/8”
9-5/8”
9-5/8”
9-5/8”
9-5/8”
9-5/8”
36.00#
36.00#
40.00#
40.00#
40.00#
43.50#
47.00#
53.50#
J-55,
K-55,
J-55,
K-55,
L-80,
L-80,
L-80,
S-95,
R-3,
R-3,
R-3,
R-3,
R-3,
R-3,
R-3,
R-3,
LTC
LTC
LTC
LTC
LTC
LTC
LTC
BTC
3,400
3,670
3,900
4,210
5,450
6,100
6,700
Base of Triangle
4,530
4,890
5,200
5,610
7,270
8,130
8,930
Base of Triangle
5,660
6,110
6,500
7,010
9,090
10,160
11,160
Base of Triangle
7”
7”
7”
7”
♦7”
23.00#
26.00#
26.00#
26.00#
26.00#
J-55, R-3, LTC
J-55, R-3, LTC
K-55, R-3, LTC
K-55, R-3, NVAM
K-55, R-3, OLD VAM
2,350
2,750
3,010
6,510
8,000
3,130
3,670
4,010
7,230
8,700
5”
15.00#
K-55/L-80, R-3, BTC
Base of Triangle
Base of Triangle
Base of Triangle
4-1/2”
4-1/2”
4-1/2”
♦4-1/2”
♦4-1/2”
4-1/2”
11.60#
11.60#
11.60#
12.60#
12.60#
12.60#
J-55, R-3,
L-80, R-3,
J-55, R-3,
J-55, R-2,
J-55, R-3,
L-80-13CR,
1,160
1,670
4,300
3,190
4,300
-
1,540
2,230
4,700
3,540
4,700
4,120
1,930
2,790
5,100
3,890
5,100
-
48”
36”
0.500" wt. 253.65# GR-B, R-3, BE
0.625" wt. 236.15# GR-B, R-3, BE
30”
30”
30”
0.500" wt. 157.50# X-42, 55/60', SJ
0.750" wt. 234.30# X-42, 55/50', SJ
0.750" wt. 239.00# X-42, 55/60', JV-LW
24”
97.00# GR-B, R-3, SJ
♦24” 0.688” wt. 176.00# X-42, R-3, V-LS
24” 0.688” wt. 176.00# X-42, R-3, V-RL4S
CASING and TUBING
STC
LTC
OLD VAM
NVAM
OLD VAM
R-3, FOX
3,910
4,590
5,010
7,950
10,100
3-1/2”
9.30# J-55,
R-2, EUE
1,710
2,280
2,850
2-7/8”
6.50# J-55,
R-2, EUE
1,240
1,650
2,060
2-3/8”
4.70# J-55,
R-2, EUE
970
1,290
1,610
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SAUDI ARAMCO
PREMIUM CASING and TUBING
Minimum
(ft-lbs.)
Optimum
(ft-lbs.)
Maximum
(ft-lbs.)
♦13-3/8” 72.00# C-95VT/ SM-95T, R-3, NVAM
13-3/8” 72.00# NKHC-95, R-3, NK-3SB
13-3/8” 72.00# NT-95HS, R-3, NS-CC
14,400
16,000
13,100
15,900
20,000
14,800
17,400
24,000
16,600
♦13-3/8” 86.00# C-95VT/ SM-95T, R-3, NVAM
13-3/8” 86.00# NKHC-95, R-3, NK-3SB
13-3/8” 86.00# NT-95HS, R-3, NS-CC
14,400
16,000
13,100
15,900
20,000
14,800
17,400
24,000
16,600
♦9-5/8” 53.50# C-95VTS/SM-95TS, R-3, NVAM
9-5/8” 53.50# NKAC-95T, R-3, NK-3SB
9-5/8” 53.50# NT-90HSS, R-3, NS-CC
14,400
13,200
9,500
15,900
16,500
10,800
17,400
19,800
12,300
♦9-5/8” 58.40# P-110VT/ SM-110T, R-3, NVAM
9-5/8” 58.40# NKHC-110, R-3, NK-3SB
9-5/8” 58.40# NT-105HS/-110HS, R-3, NS-CC
14,400
14,400
10,200
15,900
18,000
11,700
17,400
21,600
13,300
6,510
9,850
8,800
6,600
6,900
9,600
9,500
8,500
-
7,230
10,850
11,000
7,600
8,000
12,000
10,500
9,560
10,000
7,950
11,850
13,200
8,600
9,000
14,400
11,500
10,625
-
♦5-1/2” 20.00# C-95VTS/SM-95TS, R-3, NVAM
5-1/2” 20.00# NKAC-95T, R-3, NK-3SB
5-1/2” 20.00# NT-95HSS, R-3, NS-CC
♦∇ 5-1/2” 23.00# L-80,
R-3, NVAM
6,120
5,760
5,100
7,170
6,800
7,200
5,900
7,960
7,480
8,640
6,800
8,750
♦4-1/2” 12.60# J-55,
R-2, NVAM
♦4-1/2” 13.50# L-80,
R-3, NVAM
♦4-1/2” 13.50# C-95VTS/ SM-95TS, R-3, NVAM
4-1/2” 13.50# NKAC-95T, R-3, NK-3SB
4-1/2” 13.50# NT-95HSS, R-3, NSCT
♦ 4-1/2” 13.50# KO-105T, R-3, HTS
♦∇ 4-1/2”15.10# L-80,
R-3, NVAM
3,190
4,430
5,080
3,520
2,900
4,200
5,210
3,540
4,920
5,640
4,400
3,600
4,725
5,790
3,890
5,410
6,200
5,280
4,300
5,250
6,370
3-1/2” 12.95# L-80, R-2,
HYDRIL PH-6
5,500
6,185
6,875
2-7/8” 6.40# J-55, R-2,
2-7/8” 8.70# L-80, R-2,
NSCT-SC
HYDRIL PH-6
1,160
3,000
1,340
3,375
1,520
3,750
♦7”
♦7”
7”
7”
♦7”
♦7”
♦7”
♦7”
♦7”
26.00#
32.00#
32.00#
32.00#
35.00#
35.00#
35.00#
35.00#
35.00#
K-55,
R-2, NVAM
C-95VTS/ SM-95TS, R-3, NVAM
NKAC-95T, R-3, NK-3SB
NT-95HSS, R-3, NS-CC
L-80,
R-3, NS-CC
L-80,
R-3, NK-3SB
L-80,
R-3, NVAM MS
L-80, R-3, HYDRIL SUPER-EU
L-80,
R-3, AB IJ-4S
500
♦2-3/8” 4.70# L-80, R-2, AB FL-4S
2-3/8” 4.70# L-80, R-2, HYDRIL CS
1,500
1,685
2-3/8” 5.80# L-80, R-2, NVAM
1,500
1,660
2-3/8” 5.90# L-80, R-2, HYDRIL PH-6
2,200
2,475
Note: ♦ Tubulars that are being phased out.
∇ Completion accessory items. [Flow Coupling, 'R' Landing Nipple, Seal Assembly].
1,875
1,820
2,750
The use of a make-up monitoring system (Jam, Torque/Turn, etc.) should be used on all production
tubing strings with specialty connections to ensure a more accurate make-up.
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1.12 Fill Requirements
The casing string should be filled every joint while running and topped off
every 10 joints, or otherwise dictated by casing collapse calculations (based
on evacuated casing and a full column of mud in the annulus). In no case
shall the hydrostatic pressure inside the casing be less than reservoir
pressure due to infrequent filling (this could result in a kick if the float
equipment fails while running the casing).
Note: The Khuff/Pre-Khuff rigs with top drives have installed a short joint on
the top drive to fill the casing faster and reduce mud spillage on the rig
floor.
1.13 Running Speed
Casing should be run smoothly. Avoid high acceleration and deceleration,
which can cause high surge/swab pressures. The casing running speed
should be regulated to approximately 30 seconds per joint or otherwise
dictated by surge pressure calculations.
The Driller should be aware of tight spots on the previous trip out of the hole
and any problem zones, which could result in stuck pipe or loss circulation
while running casing. If tight hole is encountered while running with the
casing, a circulating sub should be installed to wash the casing down.
•
If the casing can not be run deeper due to hole conditions, the Drilling
Foreman should inform the Drilling Superintendent and Drilling Engineer.
Drilling Engineering and the Superintendent will determine if (1) the
casing can be set at this depth or (2) the casing should be laid down and
a clean out trip made.
•
If the casing is stuck, the grease pills should be spotted in an attempt to
free the pipe. If unsuccessful, the casing must be cemented in place at
the stuck point. Cementing the pipe high is not desirable, as it increases
the risk of successfully drilling the next hole section with more zones
exposed. This has led to abandoning the well and skidding the rig on
some situations where the entire RUS and UER had to be drilled
together.
Sticking problems have occurred in the following formations:
RUS
Wasia Shale
Wara Shale
Khafji Stringer
(Arab-D and Khuff/Pre-Khuff wells)
(Arab-D and Khuff/Pre-Khuff wells)
(Shaybah wells)
(Offshore Horizontal wells)
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C
June 2006
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1.14 Breaking Circulation
Circulation should be established while running casing as follows,
♦
♦
♦
♦
After running in with the shoe track.
Upon reaching casing shoe depth.
Upon encountering tight hole (if any).
Upon reaching 1-2 joints before TD (for circulating down).
Note: Break circulation slowly.
Once total depth is tagged, the casing should be picked up 1-2 feet and free
hanging weight recorded. Circulate hole at least one full circulation while
recording circulating pressures and rates. Reciprocate casing as specified in
the drilling program.
1.15 Landing Casing
Once the casing has been cemented, the BOP stack will be nippled down
and raised to set the casing slips. On multi-stage cement jobs, the slips will
be set prior to cementing the last stage.
1.15.1 Setting Slips
Do not drop casing slips through the BOP stack. The following
problems can occur with this practice,
♦ Slips hanging up in the BOP stack.
♦ Slips stopping on a casing collar (if collar is positioned in stack).
♦ Slips misaligned preventing improper setting.
On single stage cementing, set casing slips as follows,
A)
B)
C)
D)
Displace cement and bump plug.
Check for flow-back and verify well is stable.
Pick-up BOP stack.
Set casing slips.
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On multi-stage cementing, set casing slips as follows,
A)
B)
C)
D)
E)
F)
Displace 1st stage (and 2nd, if 3 stage job) cement with mud.
Open upper most DV.
Circulate hole clean with mud.
WOC. Verify well is static.
Pick-up BOP stack.
Set casing slips prior to cementing final stage.
1.15.2 Landing Load
A proper casing landing load is required to avoid excessive or unsafe
tensile stresses during the life of the well. The casing should be
landed in the casing spool in approximately the same “as cemented”
position (no pick-up or slack-off) unless otherwise dictated by landing
calculations. A casing string pick-up of less than 6” to set the casing
slips is recommended. This pick-up will allow setting the casing slips
in the “as cemented” position and will not damage or release the
multi-stage packer collar. Cementing the production casing to surface
and setting the casing slips in the “as cemented” position will avoid
buckling problems (associated with excessive slack-off and changes
in well temperature during production).
Khuff and Pre-Khuff wells utilize a reinforced support unit which is
attached to the casing head to distribute excessive casing loads
directly to the cellar floor.
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C
DRILLING MANUAL
June 2006
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2.0
ADDITIONAL GUIDELINES FOR RUNNING LINERS
Liners are casing strings that do not extend to the surface but are suspended from
the bottom of the previous casing string. A drilling liner is similar to intermediate
casing in that it serves to isolate troublesome zones (abnormally pressured zones,
weak formations, borehole instability, etc.) during the drilling operation. A
production liner is set through the productive interval of the well. Production liners
may be tied back to the surface, if required. Advantages of liners as compared to
casing are as follows,
♦
♦
♦
♦
Lowers tangible cost.
Reduces tensile running load (may overcome rig limitation).
Eliminates a casing spool requirement on the wellhead.
Allows use of larger production tubing above liner top (if no tie-back).
The following discusses the additional guidelines associated with running drilling or
production liners. These guidelines are subject to well conditions and the specific
liner hanger equipment utilized.
2.1
General Instructions
A)
When running short liners, be aware of the buoyant conditions. If
floating is anticipated, consider using hold-down slips on the liner
hanger or loading the liner with weighted mud to offset the buoyant
force.
B)
Drift all drill pipe, crossovers, liner hanger, and setting tools required in
running the liner with the correct size drift to ensure the passage of the
drill pipe wiper plug. Rabbit the drill pipe on the conditioning trip prior to
running the liner. If the rabbit hangs up in any joint, leave that joint out
of the string. Ensure the exact quantity of drill pipe in the derrick is
known.
C)
The Drilling Foreman, Toolpusher, and Liner Company serviceman
should compare all pipe figures and displacement calculations.
D)
Check the length of the liner versus the drill pipe and collars to be left
out of the hole. As soon as the liner is landed, the number of remaining
joints of drill pipe in the derrick should be counted to verify that the liner
is on bottom.
E)
Install a drill pipe wiper rubber on the drill pipe string while running in
the hole to prevent foreign objects from falling into the wellbore.
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F)
2.2
The liner cement shall be batch-mixed and displaced using the cement
company pump truck. Further details on cementing operations are
covered in Chapter 2D of this manual.
Float Equipment and Landing Collar
Visually inspect all liner float equipment and ensure that they are compatible
with the liner hanger equipment and running procedures. The liner company
service representative on location should verify the proper ‘shear pressure’ of
the ballseat in the landing collar and that the ball is compatible with the seat.
2.3
Wiper Plugs
Visually inspect wiper plugs and ensure the drill pipe wiper plug is compatible
with the liner wiper plug.
2.4
Liner Hanger
The liner hanger will be inspected, measured, and pre-assembled on the
setting tool (complete with liner wiper plug) at the liner shop prior to shipping
to the rig. Once the complete liner assembly is on location, a visual inspection
should be made and no damage has occurred during transportation. The liner
company service representative on location should ensure the proper ‘liner
setting’ shear pins are installed.
In addition, be aware of the liner hanger operation, method of make-up,
running procedure, and procedures to follow in the event of an equipment
failure, as directed by the Liner Company serviceman on location.
2.5
Cement manifold
Visually inspect the cement manifold along with the liner assembly when it
arrives on location. Load the drill pipe wiper plug in the manifold after
performing the torque/drag test at the casing shoe (before going into open
hole with the liner). Pick up the cement manifold approximately + 30’ from
TD. Install the manifold and circulate down to TD. Ensure that lines are
hooked-up and ready for immediate reversing (once the cement job is
complete).
2.6
Fill Requirements
The liner should be filled every 10 joints or otherwise dictated by liner
collapse calculations (based on evacuated casing and a full column of mud in
the annulus). Fill the drill pipe at least every 5 stands and check to ensure
that the correct amount of fluid required is pumped.
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In no case shall the hydrostatic pressure inside the liner be less than
reservoir pressure due to infrequent filling (this could result in a kick if the
float equipment fails while running the liner).
2.7
Running Speed
Control the running speed to reduce high surge pressure created by the small
annular clearances associated with liners. The running speed should be
regulated to approximately 30 seconds per joint for the liner and 60 seconds
per stand for the drill pipe, or otherwise dictated by surge pressure
calculations.
The Driller should be aware of tight spots on the previous trip out of the hole
and any potential loss circulation zones that could be affected by high running
speed.
2.8
Breaking Circulation
Circulation should be established while running the liner as follows,
♦
♦
After running in with the shoe track.
After installing the liner hanger, pick up one stand of drill pipe and slack
off until the liner hanger assembly is below the BOP stack. Circulate
one complete liner capacity plus 25%. Ensure that the circulating
pressure does not exceed 75% of the pressure required to set the liner
hanger.
Record the weight on the liner on the weight indicator.
♦
Upon reaching casing shoe depth, break circulation and ensure that the
circulating pressure does not exceed 75% of the pressure required to
set the hanger.
Perform torque/drag test and record data.
Load the drill pipe wiper plug.
♦
♦
Upon encountering tight hole (if any).
Upon reaching approx. 30’ from TD (for circulating down).
Note: Break circulation slowly as high pump rates can break down weak
formations due to small annular clearances.
Once total depth is tagged, the liner should be picked up 1 to 2 feet. Record
the free hanging weight of liner and drill pipe. Circulate hole at least two full
circulation volumes while ensuring that the pump pressure does not exceed
75% of the pressure required to set the hanger. Pump at reduced rate until
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bottoms-up is past the liner top. Rotate and/or reciprocate liner as specified in
the drilling program.
2.9
Setting Liner Hanger
The liner hanger should always be set higher than the deepest depth
achieved while circulating or reciprocating. This will ensure the liner is hung
and not merely standing on bottom.
The specific liner hanger setting procedure will vary with the type of well,
cementing program, and type of hanger used. These setting instructions will
be provided by the liner hanger serviceman on location or will be detailed in
the drilling program.
Mechanical-set and hydraulic-set liner hangers are utilized within Saudi
Aramco’s drilling operation. The following summarizes four different well
types and liner hanger applications,
♦ Arab-D Vertical Well
7” Mechanical-Set Liner Hanger with Pack-Off (Lindsey, BOT)
Hanger Set Prior to Cementing
Set after Cement Job
♦ Offshore/Shaybah Horizontal Well (BOT, and TIW)
4-1/2” Hydraulic-Set Liner Hanger
Set After Cementing
♦ Khuff Vertical Well (BOT and 1st Generation TIW)
7” and 4-1/2” Hydraulic-Set Liner Hangers
Set Prior to Cementing
♦ Khuff Horizontal Well (2nd Generation TIW)
7” and 4-1/2” Hydraulic-Set Liner Hanger
Hanger Set After Cementing
Further information regarding details on mechanical-set, hydraulic-set, and
associated liner hanger equipment is listed in Section 6 of this chapter.
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3.0
FLOAT EQUIPMENT
3.1
Inner String Cementing
Inner string cementing (ISC) is utilized to
reduce rig time and cementing cost. The
method provides for the cementing of large
diameter casing through an inner drill pipe
string,
virtually
eliminating
cement
contamination and the drill out of large
quantities of cement. This system is primarily
used on Khuff wells where the 30” casing is
cemented at approximately 600’ (with ISC
and stab-in float shoe) and 24” casing is
cemented at approximately 2200’ (with ISC
and stab-in float collar).
Casing collapse must be considered on
the deep casing strings cemented with
ISC. *The maximum surface pressure
should be calculated to avoid casing
collapse in the event of the hole
bridging-off near the casing shoe. On
critical depth strings, the surface pump
pressure plus the cement hydrostatic
pressure (ISC) can exceed the casing
collapse rating, even though the casing
is supported by mud hydrostatic
pressure
inside.
The
following
alternatives
can
prevent
casing
collapse while ISC at a critical
cementing depth:
♦
♦
*
Increasing mud weight inside the
casing prior to cementing.
Utilizing a pack-off cementing
head (which enables holding additional pressure on the casing).
Max. Surf. Press. = Collapse Rating – [Cmt Hydrostatic Inside ISC – Mud Hydrostatic Inside Csg]
1.125
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3.2
Float Shoes
The float shoe reinforces the lower
end of the casing string and guides
the string away from ledges to
cementing depth. It includes a springloaded backpressure valve that
prevents reverse flow of cement back
into the casing following the
cementing operation. The outside
body of the float shoe is made of steel
of the same strength as the casing.
The backpressure valve is made of
plastic and is enclosed in concrete for
easy drill-out.
3.3
Float Collars
The float collar serves as a back up
to the float shoe in the event the
backpressure valve in the float shoe
fails to provide a seal. The float collar
is normally located 2 to 3 joints above
the float shoe. The construction of
float collar is similar to the float shoe
and also enables easy drill-out.
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June 2006
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3.4
Plug Set
The standard plug set consists of a bottom wiper (rupture) plug and top
wiper (solid) plug. The primary purpose of bottom wiper plug is to wipe the
mud from the casing wall ahead of the cement to minimize contamination.
The purpose of the top wiper plug is to isolate the cement slurry from the
displacement fluid.
In most cases, the bottom wiper plug is not used to avoid confusion or a
potential problem with the bottom plug not rupturing. If the top wiper plug is
dropped first, the plug will bump with the cement still inside the casing. A
similar result would be experienced if the bottom plug did not rupture.
This procedure of ‘not using the bottom wiper plug’ is a Drilling & Workover
policy. The only exception would be a possible situation where the top wiper
plug might wipe enough mud from a long, small diameter casing string and
exceed the capacity of the shoe track (resulting in a wet shoe).
TOP WIPER PLUG
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4.0
MULTI-STAGE PACKER COLLAR
The multi-stage packer collars are hydraulically operated and provide for 2-stage
and 3-stage cementing operations. Applications for multi-stage packer collars
include the following:
♦
♦
♦
Cementing a high-pressure gas zone and loss circulation zone.
(Example: Isolating abnormal Lower Jilh pressure from the Hanifa and ArabD reservoirs.)
Cementing above a loss circulation zone.
(Example: Cementing to surface above UER.)
Cementing a deep casing string back to surface.
(Example: Cementing to surface from the Jilh Dolomite casing point.)
The multi-stage packer collar (DV) is typically located inside the previous casing
string to ensure a good packer seat for the 2nd stage cementing. On a 3-stage
cement job, the lower DV is run in the open hole section where the hole size is
close to gauge. The actual packer depth can be picked from the caliper log, when
available, or by rate of penetration.
A 3-stage cement job requires two multi-stage packer collars and two different size
plug sets. A conversion kit is installed in the lower DV to accommodate the smaller
plug set. The actual DV tool is the same for both 2-stage and 3-stage applications
except for the conversion kit installation.
4.1
Tool Illustrations/Technical Data
The following provides tool illustrations and technical data for the multi-stage
packer collars commonly used within Saudi Aramco drilling operation. The
actual tool application will be specified in the drilling program based upon
casing size, connection, rated service, and other factors.
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C
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C losing
S eat
O pening
S eat
18-5/8” T yp e P
E S In flatab le
P acker C o llar
w /M etal B lad d er
P acker
(E S IP C )
E xternal P orts
w /R upture D isk
Internal P orts
P acker
E lem ent
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HALLIBURTON DV PACKER COLLARS
SAMS No.
SA Set No.
Size (in)
Tool Type
HES Set No.
Description
Pkr (HES P/N)
Pkr Description
Plug Set (HES P/N)
Plug Set Description
Open Press (psi)
Open Force (lbs)
Inflation (psi)
Closing Press (psi)
Closing Force (lbs)
Pkr Differential (psi)
Hole Size (in)
Pkr OD (in)
Pkr Length (in)
Min ID after Drillout (in)
Opening Seat ID (in)
Closing Seat ID (in)
No. of Circl. Ports
Size of Ports (in)
Recom. Max Hole Size (in)
Recom. Min Hole Size (in)
Actual Max. Expansion (in)
45-664-789-00
813.30226
18.625
ESIPC-P
813.30226
CEMENTER SET - SAMS #45-664-789-00 - 18-5/8" BUTTRESS
115# - ESIPC W/METAL BLADDER PKR W/2-STG, W/RD
FREE FALL PLUG SET
813.78965
COLLAR - TYPE P ES INFL PKR - 18-5/8 BUTTRESS 115# METAL BLADDER PKR
813.16870
PLUG SET - FREE FALL - 18-5/8 8RD & BUTTRESS
87.5-115# 2-STAGE CMTR - W/9.81 ID BAFFLE
320
76000
1450
475
114000
3000
2000
22.750
23.200
20.800
75.750
17.467
14.250
16.000
4
1.125
23.800
N/A
24.250
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Drilling & Workover Engineering Department
June 2006
CHAPTER 2
DRILLING PRACTICES
SECTION
RUNNING CASING AND LINERS
C
___________________________________________________________________________________________________________________________
Multiple Stage
Inflatable
Packer Collar
(MSIPC)
External
Ports
Internal
Ports
Closing
Seat
Opening
Seat
Packer
Element
______________________________________________________________________________
26 of 46
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
C
June 2006
DRILLING PRACTICES
RUNNING CASING AND LINERS
___________________________________________________________________________________________________________________________
HALLIBURTON DV PACKER COLLARS
SAMS No.
SA Set No.
Size (in)
Tool Type
HES Set No.
Description
Pkr (HES P/N)
Pkr Description
Plug Set (HES P/N)
Plug Set Description
Open Press (psi)
Open Force (lbs)
Inflation (psi)
Closing Press (psi)
Closing Force (lbs)
Pkr Differential (psi)
Hole Size (in)
Pkr OD (in)
Pkr Length (in)
Min ID after Drillout (in)
Opening Seat ID (in)
Closing Seat ID (in)
No. of Circl. Ports
Size of Ports (in)
Recom. Max Hole Size (in)
Recom. Min Hole Size (in)
Actual Max. Expansion (in)
45-734-380-00
N/A
13.375
MSIPC
N/A
SEE BELOW
813.31060
COLLAR - MULT STAGE INFL PKR - 13-3/8 NEW-VAM 6172# -16.75 OD SUITABLE F/ USE W/ C-95
SEE NOTES AT BOTTOM
SEE NOTES AT BOTTOM
675
81000
1450
675
81000
3500
17.500
16.750
56.800
12.359
10.400
11.250
4
1.250
18.500
N/A
19.540
Description
PLUG SET - FREE FALL - 13-3/8 NEW VAM, 54.5-72#, 2-STAGE
CMTR - W/7.40 ID INSERT BAFFLE ADAPTER SUITABLE F/USE
W/C-95
PLUG SET - FREE FALL - 13-3/8 NEW VAM 54.5-72#
3-STAGE CMTR - W/7.40 ID SHUTOFF BAFFLE F/813 & 854 SERIES TOOLS-SUITABLE F/USE W/C-95
PLUG SET - DISPLACEMENT TYPE - 13-3/8 PREMIUM THD 48-85#
3-STAGE CMTR W/3.25 ID BYPASS BAFFLE -
______________________________________________________________________________
27 of 46
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
DRILLING PRACTICES
SECTION
RUNNING CASING AND LINERS
C
June 2006
___________________________________________________________________________________________________________________________
HALLIBURTON DV PACKER COLLARS
SAMS No.
SA Set No.
Size (in)
Tool Type
HES Set No.
Description
Pkr (HES P/N)
Pkr Description
Plug Set (HES P/N)
Plug Set Description
Open Press (psi)
Open Force (lbs)
Inflation (psi)
Closing Press (psi)
Closing Force (lbs)
Pkr Differential (psi)
Hole Size (in)
Pkr OD (in)
Pkr Length (in)
Min ID after Drillout (in)
Opening Seat ID (in)
Closing Seat ID (in)
No. of Circl. Ports
Size of Ports (in)
Recom. Max Hole Size (in)
Recom. Min Hole Size (in)
Actual Max. Expansion (in)
45-734-777-00
813.30215
13.375
MSIPC
813.30215
CEMENTER SET - SAMS #45-664-777-00 - 13-3/8
BUTTRESS61-72# SUITABLE F/USE W/L-80 - MSIPC
& 2-STAGE
FREE FALL PLUG SET W/7.4 ID SHUTOFF BAFFLE
813.31058
COLLAR - MULT STAGE INFL PKR - 13-3/8 BUTRESS 61-72#
-16.75 OD - SUITABLE F/USE W/L-80
813.16821
PLUG SET - FREE FALL - 13-3/8 8RD & BUTTRESS 48-85#
2-STAGE CMTR W/11.25 ID CLSG SEAT - W/7.40 ID BAFFLE
675
81000
1450
675
81000
3500
17.500
16.750
56.800
12.359
10.400
11.250
4
1.125
18.500
N/A
19.540
______________________________________________________________________________
28 of 46
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
C
June 2006
DRILLING PRACTICES
RUNNING CASING AND LINERS
___________________________________________________________________________________________________________________________
External
Ports
w/Rupture
Disk
Internal
Ports
Closing
Seat
Multiple Stage
Inflatable
Packer Collar
w/Rupture Disk
(MSIPC)
Opening
Seat
Packer
Element
______________________________________________________________________________
29 of 46
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
DRILLING PRACTICES
SECTION
RUNNING CASING AND LINERS
C
June 2006
___________________________________________________________________________________________________________________________
HALLIBURTON DV PACKER COLLARS
SAMS No.
SA Set No.
Size (in)
Tool Type
HES Set No.
Description
Pkr (HES P/N)
Pkr Description
Plug Set (HES P/N)
Plug Set Description
Open Press (psi)
Open Force (lbs)
Inflation (psi)
Closing Press (psi)
Closing Force (lbs)
Pkr Differential (psi)
Hole Size (in)
Pkr OD (in)
Pkr Length (in)
Min ID after Drillout (in)
Opening Seat ID (in)
Closing Seat ID (in)
No. of Circl. Ports
Size of Ports (in)
Recom. Max Hole Size (in)
Recom. Min Hole Size (in)
Actual Max. Expansion (in)
45-733-942
N/A
9.625
MSIPC
N/A
SEE BELOW
813.30937
COLLAR - MULT STAGE INFL PKR - 9-5/8, NEW-VAM
43.5-53.5# - 11.75 OD - W/ RD - SUITABLE F/USE W/C-95
SEE NOTES AT BOTTOM
SEE NOTES AT BOTTOM
925
54000
1800
650
38000
4000
12.250
11.750
64.100
8.619
6.926
7.750
2
1.125
14.000
N/A
15.000
Description
PLUG SET - FREE FALL - 9-5/8 NEW VAM 45.5-53.5#
2-STAGE CMTR - W/5.00 ID INSERT BAFFLE
ADAPTER - SUITABLE F/USE W/C-95
PLUG SET - DISPLACEMENT TYPE - 2-STAGE - 9-5/8
PREMIUM THD 40-53.5# MULT STAGE CMTR
PLUG SET - FREE FALL - 9-5/8 PREMIUM THREAD
43.5-53.5# MULTI STAGE CMTR
PLUG SET - DISPLACEMENT TYPE - 9-5/8
PREMIUM THD 36-53.5# & 9-7/8 62.8#
3-STAGE CMTR - W/3.25 ID BYPASS BAFFLE
HALLIBURTON DV PACKER COLLARS
______________________________________________________________________________
30 of 46
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
C
June 2006
DRILLING PRACTICES
RUNNING CASING AND LINERS
___________________________________________________________________________________________________________________________
SAMS No.
SA Set No.
Size (in)
Tool Type
HES Set No.
Description
Pkr (HES P/N)
Pkr Description
Plug Set (HES P/N)
Plug Set Description
Open Press (psi)
Open Force (lbs)
Inflation (psi)
Closing Press (psi)
Closing Force (lbs)
Pkr Differential (psi)
Hole Size (in)
Pkr OD (in)
Pkr Length (in)
Min ID after Drillout (in)
Opening Seat ID (in)
Closing Seat ID (in)
No. of Circl. Ports
Size of Ports (in)
Recom. Max Hole Size (in)
Recom. Min Hole Size (in)
Actual Max. Expansion (in)
45-733-932-00
813.30290
9.625
MSIPC
813.30290
CEMENTER SET - SAMS #45-733-932-00 - 9-5/8,
8RD, 29.3-40# SUITABLE F/USE W/P-110
W/ RD - MSIPC W/ 2-STG FREE FALL PLUG
SET
813.30854
COLLAR - MULT STAGE INFL PKR - 9-5/8,
8RD29.3-40# - 11.75 OD - W/RUPTURE
DISK, SUITABLE F/USE W/P-110
813.16710
PLUG SET - FREE FALL - 9-5/8, 8RD, 32.3-53.5#2STAGE TYPE P CMTR - W/5.90 ID BAFFLE - REF:
813.16720
860
54000
1800
610
38000
4000
12.250
11.750
64.150
8.927
6.926
7.750
2
1.125
14.000
N/A
15.000
______________________________________________________________________________
Multiple Stage 31 of 46
Packer Cementing
SAUDI ARAMCO
Drilling & Workover Engineering Department
CHAPTER 2
DRILLING PRACTICES
SECTION
RUNNING CASING AND LINERS
C
DRILLING MANUAL
June 2006
___________________________________________________________________________________________________________________________
______________________________________________________________________________
32 of 46
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
June 2006
DRILLING PRACTICES
C
RUNNING CASING AND LINERS
___________________________________________________________________________________________________________________________
HALLIBURTON DV PACKER COLLARS
SAMS No.
SA Set No.
Size (in)
Tool Type
HES Set No.
Description
Pkr (HES P/N)
Pkr Description
Plug Set (HES P/N)
Plug Set Description
Open Press (psi)
Open Force (lbs)
Inflation (psi)
Closing Press (psi)
Closing Force (lbs)
Pkr Differential (psi)
Hole Size (in)
Pkr OD (in)
Pkr Length (in)
Min ID after Drillout (in)
Opening Seat ID (in)
Closing Seat ID (in)
No. of Circl. Ports
Size of Ports (in)
Recom. Max Hole Size (in)
Recom. Min Hole Size (in)
Actual Max. Expansion (in)
45-664-786-00
813.30214
13.375
MSPCC
813.30214
CEMENTER SET - SAMS #45-664-786-00 - 13-3/8, 8RD
48-72# SUITABLE F/USE W/P-110 - MSPCC & 2-STG
FREE FALL PLUG SET W/7.40 ID SHUTOFF BAFFLE
854.08441
COLLAR - MULT STAGE PKR CMTG - 13-3/8, 8RD, 48-72#,
16-3/4 OD PKR - 11.25 ID CLSG SEAT - SUITABLE F/USE
W/P-110
813.16821
PLUG SET - FREE FALL - 13-3/8 8RD & BUTTRESS 48-85#, 2STAGE CMTR W/11.25 ID CLSG SEAT - W/7.40 ID
BAFFLE
560
81000
N/A
560
81000
1000
17.500
16.750
49.400
12.579
10.400
11.250
6
1.310
17.750
17.500
21.560
______________________________________________________________________________
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SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
DRILLING PRACTICES
SECTION
RUNNING CASING AND LINERS
C
June 2006
___________________________________________________________________________________________________________________________
HALLIBURTON DV PACKER COLLARS
SAMS No.
SA Set No.
Size (in)
Tool Type
HES Set No.
Description
Pkr (HES P/N)
Pkr Description
Plug Set (HES P/N)
Plug Set Description
Open Press (psi)
Open Force (lbs)
Inflation (psi)
Closing Press (psi)
Closing Force (lbs)
Pkr Differential (psi)
Hole Size (in)
Pkr OD (in)
Pkr Length (in)
Min ID after Drillout (in)
Opening Seat ID (in)
Closing Seat ID (in)
No. of Circl. Ports
Size of Ports (in)
Recom. Max Hole Size (in)
Recom. Min Hole Size (in)
Actual Max. Expansion (in)
45-664-776-00
813.30272
7.000
MSPCC
813.30272
CEMENTER SET - SAMS #45-664-776-00 - 7-INCH 8RD
17-23# SUITABLE F/USE W/P-110 - MSPCC W/2-STAGE
FREE FALL PLUG SET
854.0519
COLLAR - MULT STAGE PKR CMTG - 7 IN., 8RD, 17-23# 81/2 OD PKR SUITABLE F/USE W/P-110813.16571
PLUG SET - FREE FALL - 7 IN. 8RD & BUTTRESS
20-38# 2-STAGE CMTR - W/3.80 ID BAFFLE
930
35400
N/A
620
25600
1000
8.750
8.500
45.830
6.433
4.370
5.120
3
1.310
9.000
8.750
10.120
______________________________________________________________________________
34 of 46
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
C
June 2006
DRILLING PRACTICES
RUNNING CASING AND LINERS
___________________________________________________________________________________________________________________________
Type H
ES Inflatable
Packer Collar
(ESIPC)
Closing
Seat
Opening
Seat
External Ports
w/Rupture Disk
Internal Ports
Packer
Element
______________________________________________________________________________
35 of 46
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
DRILLING PRACTICES
SECTION
RUNNING CASING AND LINERS
C
June 2006
___________________________________________________________________________________________________________________________
HALLIBURTON DV PACKER COLLARS
SAMS No.
SA Set No.
Size (in)
Tool Type
HES Set No.
Description
Pkr (HES P/N)
Pkr Description
Plug Set (HES P/N)
Plug Set Description
Open Press (psi)
Open Force (lbs)
Inflation (psi)
Closing Press (psi)
Closing Force (lbs)
Pkr Differential (psi)
Hole Size (in)
Pkr OD (in)
Pkr Length (in)
Min ID after Drillout (in)
Opening Seat ID (in)
Closing Seat ID (in)
No. of Circl. Ports
Size of Ports (in)
Recom. Max Hole Size (in)
Recom. Min Hole Size (in)
Actual Max. Expansion (in)
N/A
Trial Test
7.000
ESIPC-H
N/A
SEE BELOW
813.78101
COLLAR - TYPE H ES INFL PKR - 7 IN., LG, 8RD, 26# -3
FT PKR - SUITABLE F/USE W/K-55
813.16571
PLUG SET - FREE FALL - 7 IN. 8RD & BUTTRESS
20-38# 2-STAGE CMTR - W/3.80 ID BAFFLE
1650
12300
2200
1280
38400
4000
9.000
8.250
192.000
6.079
4.375
5.120
2
1.125
11.900
N/A
12.875
______________________________________________________________________________
36 of 46
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
June 2006
DRILLING PRACTICES
C
RUNNING CASING AND LINERS
___________________________________________________________________________________________________________________________
HALLIBURTON DV PACKER COLLARS
SAMS No.
SA Set No.
Size (in)
Tool Type
HES Set No.
Description
Pkr (HES P/N)
Pkr Description
Plug Set (HES P/N)
Plug Set Description
Open Press (psi)
Open Force (lbs)
Inflation (psi)
Closing Press (psi)
Closing Force (lbs)
Pkr Differential (psi)
Hole Size (in)
Pkr OD (in)
Pkr Length (in)
Min ID after Drillout (in)
Opening Seat ID (in)
Closing Seat ID (in)
No. of Circl. Ports
Size of Ports (in)
Recom. Max Hole Size (in)
Recom. Min Hole Size (in)
Actual Max. Expansion (in)
45-733-930-00
N/A
4.500
ESIPC-H
N/A
SEE BELOW
813.78010
COLLAR - TYPE H ES INFL PKR - 4-1/2, 8RD, 9.5-11.6#
10 FT PKR - 5.62 OD - SUITABLE F/USE W/K-55
809.50100 & 809.52100
PLUG SET - SR TYPE H - 4-1/2 9.5-13.5# CSG W/3-1/2
(2.00 TO 2.75 ID) DP RELEASING DARTS - W/2-7/8
EUE 8RD SUITABLE F/USE W/K-55TBG BOX THD - F/2.00
MIN ID HANGER SYSTEM
ADAPTER - BAFFLE - 4-1/2 8RD 9.5-11.6# - 2.375 ID LATCHDOWN INSERT - 2-STAGE CMTR
1650
6000
2200
1080
13500
4000
1000
5.875
9.000
5.750
276.000
3.985
2.750
3.370
2
0.685
9.000
N/A
10.000
______________________________________________________________________________
37 of 46
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
DRILLING PRACTICES
SECTION
RUNNING CASING AND LINERS
C
June 2006
___________________________________________________________________________________________________________________________
4.2
Free Fall Plug Set
A free-fall plug set is used on most of multi-stage cement jobs. This plug set
consists of the following:
♦
♦
♦
♦
Closing Plug (closes the DV ports)
Free Fall Opening (opens the DV ports)
Shut-Off Plug (acts as top wiper plug on 1st stage cement)
Shut-Off Baffle (provides seat for Shut-Off Plug)
T w o -S ta g e
F r e e F a ll P lu g S e t
w ith B a ffle A d a p te r
Shut-Off Baffle
______________________________________________________________________________
38 of 46
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
C
June 2006
DRILLING PRACTICES
RUNNING CASING AND LINERS
___________________________________________________________________________________________________________________________
4.3
Displacement Type Plug Set
A displacement type plug set is used in situations where high mud weight
limits the use of free-fall plugs (where fall time may exceed the remaining
thickening time of the cement). This plug set consists of the following:
♦
♦
♦
♦
Closing Plug (closes the DV ports)
Opening Plug (opens the DV ports)
By-Pass Plug (acts as top wiper plug on 1st stage cement)
By-Pass Baffle (provides seat for By-Pass Plug and allows for continued
circulation until the Opening Plug bumps)
Displacement Type
Plug Set
______________________________________________________________________________
39 of 46
SAUDI ARAMCO
Drilling & Workover Engineering Department
CHAPTER 2
DRILLING PRACTICES
SECTION
RUNNING CASING AND LINERS
C
DRILLING MANUAL
June 2006
___________________________________________________________________________________________________________________________
5.0
CENTRALIZERS
The following centralizers are utilized in Saudi Aramco’s drilling operation.
These centralizer designs exceed the requirements of API specification 10D
for starting and restoring force. Centralizer placement for deviated and
horizontal well applications should be calculated using a software program.
5.1
Collapsible
The collapsible centralizer is a non-welded,
hinge type, bow centralizer. This centralizer is
used in all vertical well applications. The
centralizer should be positioned around a
stop collar in the middle of the desired joint
(as opposed to locating the centralizer around
the casing coupling).
5.2
Rigid
The rigid centralizer is a non-welded, hinge
type, rigid bow centralizer. This centralizer is
run primarily in the liner lap interval. This
centralizer design can provide approximately
100 percent standoff when run inside a cased
hole, as in the liner lap application. A stop
collar is also recommended for centralizer
placement.
5.3
SpiraGlider
The spiraglider centralizer is a steel spiralbladed centralizer. This centralizer is required
on highly deviated or horizontal wells to
improve cement flow and provide maximum
standoff from the borehole. The spiraglider
system consists of a steel centralizer and two
beveled stop collars designed to minimize the
running resistance.
______________________________________________________________________________
40 of 46
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
C
June 2006
DRILLING PRACTICES
RUNNING CASING AND LINERS
___________________________________________________________________________________________________________________________
6.0
LINER HANGERS
6.1
Mechanical-Set Liner Hanger
The mechanical-set liner hanger is mainly used in vertical or low-angle
wellbores. This liner hanger is designed for heavy-duty service and is capable
of suspending short as well as long, heavy liners.
The tandem cone version (as shown) with staggered
slips, provides maximum bypass and heavy load hanging
capacity. The increased bypass lessens pressure build-up
during the running and cementing operations, which
reduces the chance of loss circulation in pressure sensitive
formations.
The mechanical hanger is set by picking up on the liner
and rotating to disengage the J-slot. As the liner is
lowered, the springs hold the cage stationary. This allows
the barrel to move downward engaging the cones against
the slips, which move outward against the casing wall. This
liner hanger does not have hold-down slips; consequently,
buoyancy must be calculated for short liner applications to
avoid the possibility of floating.
______________________________________________________________________________
41 of 46
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
DRILLING PRACTICES
SECTION
RUNNING CASING AND LINERS
C
June 2006
___________________________________________________________________________________________________________________________
6.2
Hydraulic-Set Liner Hanger
The hydraulic-set liner hanger is primarily used in deep, highly deviated, and
horizontal well applications.
The setting mechanism of the hydro-hanger (as
shown) is pressure activated, after a ball is seated
in the landing collar. The pressure shears the pins
in the setting piston, which pushes the slips up and
around the cones. Additional pressure shears the
ball-seat in the landing collar, releasing the ball and
restoring circulation.
The typical shear pin and ball-seat strengths are
listed below:
Arab-D Deviated
Shear Pin
Ball-Seat
Shear Pressure
1200 psi
2500 psi
Khuff/Pre-Khuff
Shear Pin
Ball-Seat
Shear Pressure
2250 psi
3500 psi
This liner hanger also does not have hold-down
slips; consequently, buoyancy must be calculated
for short liner applications to avoid the possibility of
floating.
______________________________________________________________________________
42 of 46
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
C
June 2006
DRILLING PRACTICES
RUNNING CASING AND LINERS
___________________________________________________________________________________________________________________________
6.3
Associated Equipment
6.3.1
Setting Collar/Tieback Sleeve
The setting collar/tieback sleeve is a basic releasing collar used to
carry the liner into the well. It also provides a receptacle which permits
the liner to be extended to a point farther up-hole or to surface.
The setting collar (as shown) is made up on
top of the liner hanger. A right-hand releasing
thread ensures easy release of the liner
setting tool from the setting collar.
The tieback sleeve (as shown) is attached to
the setting collar. The receptacle’s polished
bore facilitates the entry and seating of the
seal nipple, when a tieback is required. The
tieback sleeve is provided in optional lengths
depending on the well type. The standard
lengths for development wells and Khuff/PreKhuff wells are 6 feet and 12 feet
respectively.
Tie-Back Sleeve
Setting Collar
______________________________________________________________________________
43 of 46
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
DRILLING PRACTICES
SECTION
RUNNING CASING AND LINERS
C
June 2006
___________________________________________________________________________________________________________________________
6.3.2
Liner Top Packer
The liner top packer combines the basic features of the setting collar
with the addition of a pack-off at the top of the liner. The packer
provides a secondary mechanical seal against gas migration and
prevents well fluids from entering the wellbore in uncemented or
poorly cemented liners; thus, creating an effective liner lap seal. The
liner top packer is optional in most liner applications but is
recommended on liners cemented across an abnormally pressured
formation, as the Lower Jilh.
The liner top packer (as shown) is mechanically
set by applying weight to the top of the packer after
releasing the liner setting tool and opening the
packer setting dogs.
The liner top packer also includes a sleeve (as
shown) for future tiebacks.
Tie-Back Sleeve
Packer Element
______________________________________________________________________________
44 of 46
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
C
June 2006
DRILLING PRACTICES
RUNNING CASING AND LINERS
___________________________________________________________________________________________________________________________
6.3.3 Polished Bore Receptacle
The polished bore receptacle (PBR) is a seal bore with a honed and
coated ID to receive production seals for a packer-less completion.
The PBR is made up on top of the liner hanger and below the setting
collar/tieback sleeve.
The polished bore receptacle (as shown)
provides for free tubing movement during
production. The use of Teflon coating prevents
the cement from sticking to the ID during
cementing operations and minimizes seizing of
the seals during production.
The PBR is primarily used on Khuff/Pre-Khuff
wells and is a standard length of 24’.
______________________________________________________________________________
45 of 46
SAUDI ARAMCO
Drilling & Workover Engineering Department
CHAPTER 2
DRILLING PRACTICES
SECTION
RUNNING CASING AND LINERS
C
DRILLING MANUAL
June 2006
___________________________________________________________________________________________________________________________
6.3.4
Cementing Manifold
The cementing manifold provides a means of circulating and
cementing the liner. The manifold consists of a swivel and plugdropping head with elevator handling sub. The plug-dropping head
facilitates the dropping the drill pipe wiper plug and liner hanger
setting ball (if a hydraulic-set liner hanger is utilized). The cementing
manifold is provided by the liner hanger company as part of the liner
hanger equipment
______________________________________________________________________________
46 of 46
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
D
June 2006
DRILLING PRACTICES
CEMENTING
___________________________________________________________________________________________________________________________
CEMENTING
1.0
CEMENT TYPES, SPECIFICATIONS & ADDITIVES
1.1 Cement Types
1.2 Specifications
1.3 Performance of Cement Slurry
1.4 Additive Functions
1.5 Cement Additives
2.0
SLURRY DESIGN
2.1 Factors That Influence Cement Slurry Design
2.2 Limitations of Thickening Time
2.3 Fluid Loss Test
2.3.1 HT/HP Fluid Loss Tests (BHCT<190 0F)
2.3.2 Stirred HT/HP Fluid Loss Tests (BHCT>190 0F)
2.4 WOC (Waiting on Cement) Time
2.4.1 Ultrasonic Cement Analyzer (UCA Test)
2.4.2 Static Gel Strength Analyzer (SGSA Test)
2.5 Pressurized Mud Balance & Densitometers
2.6 Free Fluid Test
2.7 Rheology Test
2.8 Mud-Spacer-Cement Compatibility Test
2.9 Gas Migration Additives
2.10 Cementing: Pre-Job Considerations for Slurry Design
2.11 Pre-Job Meeting
2.12 Cementing Information Form
3.0
LAB TESTING OF CEMENT
3.1 Types of Tests
3.2 When To Send Samples For Testing
3.3 Initial Pilot Testing
3.4 Pilot Testing prior To Mixing
3.5 Field Sample Confirmation Testing
4.0
MIXING CEMENT
4.1 Mix Water Quality
4.2 Type Of Chemicals And Quantity To Be Blended
4.3 Mix Water Blending And Storage System
4.4 Cement Job Quality
4.5 Pre-Mixing Additives
4.6 Sampling and Sample Sizes
4.6.1 Sample Containers
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4.6.2
4.6.3
4.6.4
4.6.5
Dry Cement Sampling
Sampling of Mix Fluid
Sample Size for Lab Testing
Sample Labeling
5.0
BALANCED PLUGS
5.1 Loss Circulation Plugs
5.2 Kick-Off / Sidetrack Plugs
5.2.1 Kick-Off Plugs
5.2.2 Sidetracking
5.3 Isolation/Abandonment Plugs
6.0
DISPLACEMENT PROCEDURES
6.1 Casing
6.2 Liners
6.3 Turbulent Flow
7.0
REMEDIAL CEMENTING
7.1
7.2
8.0
Bradenhead Squeeze
Packer Squeeze
CEMENTING EQUIPMENT (PICTURES)
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CEMENTING
The Saudi Aramco Oilwell Cement Lab monitors quality of Class G cement sold to the
Company. Cement consignments that fall out of specification are not approved for
purchase to Saudi Aramco. The Company cement lab technicians sample and test all
cement consignments prior to approving the purchase of any consignment of oilwell
cement. It is not the intention of this manual to provide cementing recipes. Cement
deteriorates with age. As dry cement ages, moisture collects on the particles and
partially hydrates the outside covering of the particle. The physical properties of the
cement slurry change when this occurs. Generally the thickening time increases, the free
fluid increases and the final compressive strength decreases.
Any concerns about Cement or Cement formulations contact Drilling Engineering or the
Saudi Aramco Oilwell Cement Lab.
1.0
CEMENT TYPES, SPECIFICATIONS & ADDITIVES
1.1
Cement Types
Class G (HSR)* cement is used exclusively in Saudi Aramco
operations as the basic oilwell cement. This cement can be
blended with many additives to cover a wide range of well
conditions. The five normal slurry compositions are as follows:
*High Sulfate Resistant
CEMENT
Class G Neat
Class G +35% Silica Flour
Class G + 1.5% Bentonite
(Prehydrated), 6.6 Lbs. Gel/bbl
Of Mix Water
Class G +35% Silica Sand
Class G +35% Silica Sand +
5% Expanding Additive
A)
B)
C)
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SLURRY
WEIGHT
(PCF)
118
118
101
SLURRY
YIELD
(FT3/SK)
1.15
1.52
1.69
WATER
REQUIREMENT
GAL/SK
5.03
6.28
8.96
125
125
1.35
1.40
5.01
5.25
All the above figures refer to a 94 lb sack.
Slurry weights listed above are absolute weights. Weight of cement
measured from the cement tub in a non-pressurized mud balance
may be as much as 15 pcf lighter due to entrapped air.
Modifications of the basic slurries will be specified by Drilling
Engineering.
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1.2
Specifications
API Specification 10A “Specification for Cement and Materials for Well
Cementing” is used for the approval of the purchasing of class G (HSR)
cement.
API Recommended Practice 10B is used for the basic test procedures for the
physical testing of cement slurries. Many instruments in the cement lab are
not listed in API RP 10B. Procedures for testing cements are located in the
labs procedures manual.
1.3
Performance of Cement Slurry
Data given for the effectiveness of any additives is only valid for the cement,
water and additives used for the test. Different cement brands, and even
different production runs of the same brand of cement, react differently to the
various additives. When there is any doubt, have the actual job cement, water
and cement additives tested. Most cement additives from the various service
companies are completely compatible with each other. Testing is always
recommended if additives from different service companies are being used.
Almost all of Schlumberger/Dowell's products are completely compatible with
Halliburton’s and BJ’s products and vice versa. Before making any
substitutions, consult with the Cement Lab, Drilling Engineering or the
Service Company. Many additives have more than one function. For
example, a dispersant (friction reducer) can be added to a slurry design to
help make the mixing easier for a class G cement slurry that is mixed at a
density greater than 118 pcf. The physical effects of adding the dispersant
will be reduced the rheology, and lengthen the thickening times. Lists of the
more common cement functions and additives used by Saudi Aramco are
included in the following pages:
1.4
Additive Functions:
1.4.1
Retarders
The function of retarders is to increase the thickening time (pumping
time) of the cement slurry being pumped. Lignosulfonates and their
derivatives make up the majority of the cement retarders for use in
low and medium temperatures. (80 0F – 220 0F) Higher temperature
retarders are composed of Polyhydroxy Organic Acids and sugar
derivatives. It has been observed that combinations of low and high
temperature retarders are effective in extending thickening times for
high temperature applications. High temperature retarders should
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never be used in cements with BHCT lower than 180 0F, unless
confirmed by lab tests.
1.4.2
Fluid Loss Additives
The function of fluid loss additives is to reduce the water loss from the
cement slurry. This class of cement chemicals and gas migration
additives are generally the most expensive part of the cementing
invoice. If high fluid loss occurs the following can happen:
•
•
•
Premature dehydration of slurry, which can cause
annulus plugging and incomplete placement of slurry.
Changes in slurry flow properties (rheology) and
increased slurry density.
Damage to production zones by cement filtrate
Most fluid loss additives also retard the thickening time. On the 4 ½”
and 7” liner jobs for vertical Arab D wells, no retarder is used.
Adequate retardation is produced from the synergetic effects
combining the fluid loss additive with the dispersants.
1.4.3
Dispersants (Friction Reducers)
The functions of dispersants are: A) to thin the slurry in order to
reduce the turbulent flow rate or enable easy mixing of slurry B) to
densify cement slurry (increase the solid-to-liquid ratio). C) to aid in
fluid loss control.
Over dispersing the cement slurry can cause high free fluid and
density settling in the cement column. This must be avoided at all
times and especially when cementing deviated or horizontal section of
the well. Pumping slurry that is not up to the designed weight (density)
can easily settle after placement. Pressurized mud balances must be
used to confirm correct cement density. Pumping cements that are
heavier than the planned density doesn’t cause settling problems.
However, the thickening times are generally shorter.
1.4.4
Accelerators
The function of accelerators is to reduce the thickening time and
decrease the (WOC) time. Calcium Chloride is the most common
accelerator used. Calcium Chloride does not increase the final
strength of cement and may perhaps lower the final compressive
strength a little. Most fluid loss additives do not work well with Calcium
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Chloride in the cement slurry. Sodium Silicate is recommended if low
fluid loss is required with fluid loss control in most cases. Special
mixing is required for sodium silicate slurries 1) if accelerator is used
then the accelerator must be added first. 2) if a retarder is to be used
then the Sodium Silicate should be added first and the retarder must
be added last.
1.4.5
Non-Foamers
The function of non-foamer (defoamers) in cement slurry is to release
trapped air in the slurry as it is being mixed. Entrapped air cause
viscosity increases, which make the cement slurry more difficult to
mix. Entrapped air also makes the density of the slurry more difficult
to measure. Special non-foamer are used for Latex cement slurries.
The addition of excess non-foamer may stabilize foam. Bentonite
cement slurries usually require twice as much non-foamer than
conventional cements. Latex cements may require as much as five
times more non-foamer than conventional cement slurries.
1.4.6
Strength Retrogression Preventers
The function of silica flour and silica sand in cement is to prevent
strength retrogression of the set cement. Exposure temperatures of
250 0F to 300 0F require 25% silica flour or silica sand by weight of
cement. When cement is exposed to temperatures from 300 0F to 450
0
F, 35% silica flour or silica sand is required. At temperatures above
450 0F only silica flour should used. Service companies recommend
35% silica at temperatures over 235 0F. This recommendation is
conservative with built in safety factors for improper blending ratios of
cement-silica flour and inaccurate temperature data.
1.4.7
Heavy Weight Additives
The function of Heavy weight additives is to increase the slurry
density above the level that can be achieved with dispersants. The
maximum density achievable with Saudi Class G cement + dispersant
is 130-135 pcf. Hematite (a form of Iron Oxide) is normally used to
densify cement. The highest density cement pumped in Saudi Aramco
is 170 pcf using 185% Hematite. MicroMax, (Manganese tetraoxide),
a relatively new product, is available for increasing the density of
cement slurries. This product has a lower specific gravity than
Hematite but is spherical and small in size. It has two primary
advantages 1) it is ground small (less than 1 micron) which allows it to
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be blended in the mix water, and 2) it is spherical which makes the gel
strengths much lower, thus reducing the viscosity.
1.4.8
Gas Migration Additives
The function of Gas migration additives is to help prevent fluids
(gasses & Liquids) from migrating to the surface during the loss of
hydrostatic pressure that occurs prior to the setting of cement. The
most popular additive is Liquid Latex. Latex provides low fluid loss to
the slurry and lower initial permeability to the set cement. Expanding
additives are often included in the slurry design to reverse any
shrinkage that occurs during the setting of cement.
Special mixing instruction for latex systems: add the stabilizer to the
water after the bactericide but prior to any other cement additives.
1.4.9
Extenders
The function of the extenders is 1) to decrease the slurry density or 2)
to increase the slurry yield decreasing the total cost. Pre-hydrated
Bentonite is the best example of cost saving of a neat cement slurry.
However, if low fluid loss is required, the cement can become more
expensive as the increased water in the system requires more
chemicals to prevent it from escaping from the slurry. Sodium
Silicates have also been used to lower the density of cement but are
more expensive than pre-hydrated Bentonite. Foam cement and Micro
spheres have been utilized with limited success.
1.4.10 Expanding Additives
The function of expanding additives is to increase the bonding
strength of the set cement. After cement goes through hydration
reaction, the cement shrinks. Expanding additives primarily MgO and
CaO or combinations of the two are dry blended in cement to take the
set cement out of shrinkage and provide up to 2.5% expansion. This
expansion may take up to two weeks to reach completion. Salt (NaCl)
is not recommended as an expansion additive in cement due to the
higher permeability that high concentrations of salt in cement produce.
On the other hand MgO and CaO are not as water soluble as NaCl
and provide a lower permeability once the cement has set.
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1.4.11 Bactericide
The function of the Bactericide (biocide) is to kill significant quantities of
bacteria in the cement mixing fluid to prevent chemical degradation of
cement additives. Bacteria reproduce exponentially and if not controlled
will reduce the cement additives to an ineffective level.
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1.5
Cement Additives:
HALLIBURTON CEMENT ADDITIVES
RETARDERS
Name
Temp.
range
172 0F,
BHCT
Normal
concentration
Up to 1.0%,
BWOC
Mixing
procedure
Added to
mix water or
dry blended
Packing
Comments
50 lb.
sack
HR-5
220 0F,
BHCT
Up to 1.0%,
BWOC
Added to
mix water or
dry blended
50 lb.
sack
Can be added to cement
containing high temp.
retarder to extend
thickening time.
Can be added to cement
containing high temp.
retarder to extend
thickening time
HR-12
320 0F,
BHCT
Up to 2.0%,
BWOC
50 lb.
sack
HR-15
380 0F,
BHCT
Up to 2.5%,
BWOC
TB-41
250 - 450 0F,
BHCT
Up to 3.0%,
BWOC
Compon
ent R
250 - 450 0F,
BHCT
Up to 3.0%,
BWOC
Added to
mix water or
dry blended
Added to
mix water or
dry blended
Added to
mix water or
dry blended
Added to
mix water or
dry blended
HR-4
50 lb.
sack
50 lb.
sack
50 lb.
sack
Added with high temp.
retarders to extend
thickening time.
Added with high temp.
retarders to extend
thickening time.
FLUID LOSS ADDITIVES
Name
Temp.
range
125 0F 0
360 F
Normal
concentration
Up to 1.5%,
BWOC
Halad-322
Up to
180 0F
Up to 1.5%,
BWOC
Halad-344
Up to
330 0F
Up to 1.0%,
BWOC
Halad-413
80 0F 400 0F
Up to 3.0%,
BWOC
Halad-22A
Mixing
procedure
Added to mix
water or dry
blended
Added to mix
water or dry
blended
Added to mix
water or dry
blended
Added to mix
water or dry
blended
Packing
Comments
50 lb.
sack
50 lb.
sack
50 lb.
sack
50 lb.
sack
DISPERSANTS (Friction Reducers)
Name
CFR-3
8 of 48
Temp.
range
Up to 350
0
F
Normal
concentration
Up to 1.0%,
BWOC
Mixing
procedure
Added to
mix water or
dry blended
Packing
Comments
50 lb.
sack
Can be used to help
increase the density of
cement.
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HALLIBURTON CEMENT ADDITIVES (continued)
ACCELERATORS
Name
CaCl2
CAL-SEAL
LIQUID
ECONOLITE
NaCl
Temp.
range
Up to
120 0F
Normal
concentration
Up to 2.0%,
BWOC
Up to
170 0F
Up to
200 0F
Up to
0
360 F
Up to 90.0%,
BWOC
Up to 1.0 GPS
Mixing
procedure
Added to
mix water or
dry blended
dry blended
Added to
mix water
Added to
mix water or
dry blended
Up to 5.0%,
BWOC
Packing
Comments
100 lb.
sack
100 lb.
sack
52 gallon
drum
80 lb.
sack
Sodium Chloride
NON-FOAMERS
Name
NF-1
D-AIR-3
Temp.
range
Up to
0
500 F
Up to
500 0F
Normal
concentration
1 PT/10 BBLS
0.02 GPS - 0.20
GPS
Mixing
procedure
Added to mix
water
Added to mix
water
Packing
Comments
5 gallon
can
54 gallon
drum
2 PT/10 BBLS IN
BENTONITE SLURRIES
5 PT/10 BBLS IN LATEX
SLURRIES
STRENGTH RETROGRESSION PREVENTERS
Name
Temp. range
SSA-1
250 0F – 700 0F
SSA-2
250 0F – 700 0F
Normal
concentration
25%-100%,
BWOC
25%-100%,
BWOC
Mixing
procedure
dry blended
dry blended
Packing
Comments
100 lb.
sack
100 lb.
sack
Silica Flour
Silica Sand
HEAVY WEIGHT ADDITIVES
Name
Hi-Dense
No.4
Temp.
range
Up to 500
0
F
Micro-Max
Up to 500
0
F
Hi-Dense
No.3
Up to 500
0
F
Normal
concentration
Depends on
required slurry
density
Depends on
required slurry
density
Depends on
required slurry
density
Mixing
procedure
dry blended
Packing
Comments
100 lb.
sack
Hematite
Added to mix
water or dry
blended
dry blended
1,500 lb.
Big Bag
Soluble in HCl
100 lb.
sack
Hematite
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HALLIBURTON CEMENT ADDITIVES (continued)
GAS MIGRATION ADDITIVES
Name
Latex 2000
Stabilizer 434B
Versa-SET
Temp.
range
Up to 400
0
F
Up to 320
0
F
Normal
concentration
0.5 – 3.0 GPS
Up to 140
F
Up to 2.0%,
BWOC
0
0.05 – 0.5 GPS
Mixing
procedure
Added to mix
water
Added to mix
water
Packing
Comments
54 gal
drum
5 gal can
Order of mixing
critical
Order of mixing
critical, Does not
tolerate Salt
Added to mix
water or dry
blended
50 lb. bags
Mixing
procedure
Added to mix
water
Packing
Comments
1.5 ton
super
sacks
52 gallon
drum
Wyoming
Bentonite, Nonbenificiated
Order of mixing
critical
EXTENDERS (LIGHT WEIGHT ADDITIVES)
Name
Bentonite (PH)
Liquid
Econolite
Temp.
range
Up to 400
0
F
Up to 200
0
F
Normal
concentration
Up to 6.0%,
BWOC, when
prehydrated
Up to 1.0 GPS
Added to mix
water
EXPANDING ADDITIVES
Name
MICROBO
ND-HT
Temp.
range
Up to
350 0F
Normal
concentration
Up to 10.0%,
BWOC
Mixing
procedure
dry blended
Packing
Comments
50 lb.
sack
Normal concentration
5.0%
Mixing
procedure
Added to mix
water
Added to mix
water
Packing
Comments
5 gal can
Add to tank prior to
filling with water
BACTERIACIDES
Name
BE-3
BE-6
10 of 48
Temp.
range
Up to
0
120 F
Up to
120 0F
Normal
concentration
0.5 gal/1000 gals
1 lb/500 bbls
1 lb bag
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SCHLUMBERGER / DOWELL CEMENT ADDITIVES
RETARDERS
Name
Normal
concentration
Up to 0.25GPS
Mixing
procedure
Added to
mix water
Packing
Comments
D-81
Temp.
range
Up to
0
180 F,
BHCT
5 gal. can
Liquid version of D-13.
Can be added to cement
containing high temp.
retarder to extend
thickening time.
D-800
250 0F,
BHCT
Up to 2.0%,
BWOC
50 lb.
sack
D-801
250 0F,
BHCT
Up to 0.5 gps
Added to
mix water or
dry blended
Added to
mix water
D-109
175 - 300 0F,
BHCT
200 - 400 0F,
BHCT
Up to 0.5 gps
5 gal. can
250 - 450 0F,
BHCT
Up to 3.0%,
BWOC
Added to
mix water
Added to
mix water or
dry blended
Added to
mix water or
dry blended
D-28
D-93
Up to 2.5%,
BWOC
5 gal. can
Liquid version of D-800.
Can be added to cement
containing high temp.
retarder to extend
thickening time.
50 lb.
sack
50 lb.
sack
Added with high temp.
retarders to extend
thickening time.
FLUID LOSS ADDITIVES
Name
D-60
D-112
D-604 AM
D-900
Temp.
range
Up to
200 0F,
BHCT
Up to
0
200 F,
BHCT
120 0F –
0
250 F
Up to
400 0F,
BHCT
Normal
concentration
Up to 1.5%,
BWOC
Up to 1.5%,
BWOC
Up to 1.0 gps
Up to 0.8%,
BWOC
Mixing
procedure
Added to mix
water or dry
blended
Added to mix
water or dry
blended
Added to mix
water
Added to mix
water or dry
blended
Packing
Comments
50 lb.
sack
For use
water
50 lb.
sack
For low density
slurries, good in sat.
Salt & f. H2O
strong dispersant
8 gal.
cans
50 lb.
sack
in
fresh
H.T. Fluid Loss
Additive
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SCHLUMBERGER / DOWELL CEMENT ADDITIVES (continued)
DISPERSANTS (Friction Reducers)
Name
Temp. range
D-80
Up to 350 0F
D-606
Up to 400 0F
D-135
Up to 375 0F
Normal
concentration
Up to 0.4 gps
Up to 1.0%,
BWOC
Up to 0.3 gps
Mixing
procedure
Added to
mix water
Added to
mix water
Added to
mix water
Packing
Comments
8 gal.
cans
50 lb.
sack
5 gal.
cans
Liquid D-65
Sodium Sulfate
Stabilizer for D-600
ACCELERATORS
Name
CaCl2
Temp.
range
Up to 100 0F
Normal
concentration
Up to 2.0%,
BWOC
D-53
Up to 100 0F
D-75
Up to 200 0F
Up to 10.0%,
BWOC
Up to 1.0 GPS
NaCl
Up to 360 0F
Up to 5.0%,
BWOC
Mixing
procedure
Added to mix
water or dry
blended
dry blended
Added to mix
water
Added to mix
water or dry
blended
Packing
Comments
100 lb.
sack
Calcium Chloride
50 KG
sack
52 gallon
drum
50 Kg.
sack
Order of mixing is
critical
Sodium Chloride
NON-FOAMERS
Name
D-47
D-144
Temp.
range
Up to
0
500 F
Up to
500 0F
Normal
concentration
1 PT/10 BBLS
2 PT/10 BBLS
Mixing
procedure
Added to mix
water
Added to mix
water
Packing
Comments
5 gallon
can
5 gallon
can
2 PT/10 BBLS IN
BENTONITE SLURRIES
5 PT/10 BBLS IN LATEX
SLURRIES
Packing
Comments
100 lb.
sack
100 lb.
sack
Silica Flour
STRENGTH RETROGRESSION PREVENTERS
Name
Temp. range
D-66
250 0F – 500 0F
D-30
250 0F – 500 0F
12 of 48
Normal
concentration
25%-100%,
BWOC
25%-100%,
BWOC
Mixing
procedure
dry blended
dry blended
Silica Sand
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SCHLUMBERGER / DOWELL CEMENT ADDITIVES (continued)
HEAVY WEIGHT ADDITIVES
Name
D-76
Temp.
range
Up to
500 0F
Micro-Max
Up to
0
500 F
D-76.1
Up to
0
500 F
Normal
concentration
Depends on
required slurry
density
Depends on
required slurry
density
Depends on
required slurry
density
Mixing
procedure
dry blended
Packing
Comments
100 lb.
sack
Hematite (Fe3O4)
Added to mix
water or dry
blended
dry blended
100 lb.
sack
Soluble in HCl
100 lb.
sack
Ferrosilicon
GAS MIGRATION ADDITIVES
Name
Temp. range
D-600
Up to 400 0F
Normal
concentration
0.9 – 2.5 GPS
D-135
Up to 400 0F
0.1 – 0.25 GPS
D-500
Up to 200 0F
0.9 – 2.5 GPS
Mixing
procedure
Added to
mix water
Added to
mix water
Added to
mix water
Packing
Comments
55 gal drum
Gas Block, Order of
mixing critical
Gas Block Stabilizer
Order of mixing critical
Low Temp. Gas Block
(Cem-Seal)
5 gal can
55 gal drum
EXTENDERS (LIGHT WEIGHT ADDITIVES)
Name
Temp. range
D-20
Up to 400 0F
D-75
Up to 200 0F
Normal
concentration
Up to 6.0%, BWOC,
when prehydrated
Up to 1.0 GPS
Mixing
procedure
Added to
mix water
Added to
mix water
Packing
Comments
1.5 ton super
sacks
52 gallon drum
Bentonite (PH)
Order of
mixing critical
EXPANDING ADDITIVES
Name
B-82
Temp.
range
Up to
0
350 F
Normal
concentration
Up to 10.0%,
BWOC
Mixing
procedure
dry blended
Packing
Comments
50 lb. sack
Normal concentration 5.0%
BACTERIACIDES
Name
M-290
Temp.
range
Up to
0
120 F
Normal
concentration
0.5 gal/1000 gals
Mixing
procedure
Added to mix
water
Packing
Comments
5 gal can
Add to tank prior to
filling with water
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BJ SERVICES CEMENT ADDITIVES
RETARDERS
Name
Normal
concentration
Up to 1.0%,
BWOC
Mixing
procedure
Added to
mix water or
dry blended
Packing
Comments
R-3
Temp.
range
Up to
210 0F,
BHCT
50 lb.
sack
Can be added to cement
containing high temp.
retarder to extend
thickening time.
R-8
200 - 400 0F,
BHCT
Up to 2.5%,
BWOC
50 lb.
sack
R-9
250 - 450 0F,
BHCT
Up to 3.0%,
BWOC
Added to
mix water or
dry blended
Added to
mix water or
dry blended
50 lb.
sack
Added with high temp.
retarders to extend
thickening time.
FLUID LOSS ADDITIVES
Name
FL-25
BA-10
Temp.
range
Up to
200 0F,
BHCT
Up to
240 0F,
BHCT
Normal
concentration
Up to 1.5%,
BWOC
Up to 2.0%,
BWOC
Mixing
procedure
Added to mix
water or dry
blended
Added to mix
water or dry
blended
Packing
Comments
50 lb.
sack
For use in fresh
water
50 lb.
sack
For low density
slurries, good in sat.
Salt & f. H2O
DISPERSANTS (Friction Reducers)
Name
CD-32
Temp.
range
Up to 350
0
F
Normal
concentration
Up to 2.0%,
BWOC
Mixing
procedure
Added to
mix water
Packing
Comments
8 gal.
cans
Liquid D-65
ACCELERATORS
Name
A-7
A-10
A-3L
A-5
14 of 48
Temp.
range
Up to
100 0F
Normal
concentration
Up to 2.0%,
BWOC
Up to
0
100 F
Up to
200 0F
Up to
360 0F
Up to 10.0%,
BWOC
Up to 1.0 GPS
Up to 5.0%,
BWOC
Mixing
procedure
Added to
mix water or
dry blended
dry blended
Added to
mix water
Added to
mix water or
dry blended
Packing
Comments
100 lb.
sack
Calcium Chloride
50 KG
sack
52 gallon
drum
50 Kg.
sack
Gypsum cement
Order of mixing is
critical
Sodium Chloride
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BJ SERVICES CEMENT ADDITIVES (continued)
NON-FOAMERS
Name
FP-6L
FP-9L
FP-12L
Temp.
range
Up to
500 0F
Up to
500 0F
Up to
0
500 F
Normal
concentration
1 PT/10 BBLS
2 PT/10 BBLS
2 PT/10 BBLS
Mixing
procedure
Added to mix
water
Added to mix
water
Added to mix
water
Packing
Comments
55 gal.
drum
55 gal.
drum
55 gal.
drum
2 PT/10 BBLS IN
BENTONITE SLURRIES
5 PT/10 BBLS IN LATEX
SLURRIES
5 PT/10 BBLS IN LATEX
SLURRIES
Packing
Comments
100 lb.
sack
100 lb.
sack
Silica Flour
STRENGTH RETROGRESSION PREVENTERS
Name
Temp. range
S-8
250 0F – 500 0F
S-8C
250 0F – 500 0F
Normal
concentration
25%-100%,
BWOC
25%-100%,
BWOC
Mixing
procedure
dry blended
dry blended
Silica Sand
HEAVY WEIGHT ADDITIVES
Name
Temp. range
W-5
Up to 500 0F
Micro-Max
Up to 500 0F
Normal
concentration
Depends on
required slurry
density
Depends on
required slurry
density
Mixing
procedure
dry blended
Packing
Comments
100 lb.
sack
Hematite (Fe3O4)
Added to mix
water or dry
blended
1,500 lb.
Big Bag
Soluble in HCl
GAS MIGRATION ADDITIVES
Name
BA-86L
Temp.
range
Up to 400 0F
Normal
concentration
1.0 – 3.0 GPS
LS-1
Up to 400 0F
0.1 – 0.35 GPS
Mixing
procedure
Added to mix
water
Added to mix
water
Packing
Comments
55 gal
drum
5 gal can
order of mixing
critical
B-86L stabilizer,
order of mixing
critical
EXTENDERS (LIGHT WEIGHT ADDITIVES)
Name
Temp. range
Bentonite (PH)
Up to 400 0F
Sodium
Silicate
Up to 200 0F
Normal
concentration
Up to 6.0%,
BWOC, when prehydrated
Up to 1.0 GPS
Mixing
procedure
Added to
mix water
Packing
Added to
mix water
55 gallon
drum
Comments
1.5 ton
super sacks
Order of
mixing critical
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BJ SERVICES CEMENT ADDITIVES (continued)
EXPANDING ADDITIVES
Name
EC-2
Temp.
range
Up to
350 0F
Normal
concentration
Up to 10.0%,
BWOC
Mixing
procedure
dry blended
Packing
Comments
50 lb. sack
Normal concentration 5.0%
BACTERIACIDES
Name
X-CID
16 of 48
Temp.
range
Up to
0
120 F
Normal
concentration
1 lb/100 bbls
Mixing procedure
Packing
Added to mix water
6 lb can
Comments
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CHAPTER 2
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CEMENTING
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NOWMCO CEMENT ADDITIVES
RETARDERS
Name
NR-1
NR-5
Temp.
range
Up to
200 0F,
BHCT
200 - 350 0F,
BHCT
Normal
concentration
Up to 1.0%,
BWOC
Up to 2.5%,
BWOC
Mixing
procedure
Added to
mix water or
dry blended
Added to
mix water or
dry blended
Packing
Comments
50 lb.
sack
50 lb.
sack
FLUID LOSS ADDITIVES
Name
NFC-3
NFC-4
Temp.
range
Up to
220 0F,
BHCT
Up to
0
220 F,
BHCT
Normal
concentration
Up to 2.0%,
BWOC
Up to 2.0%,
BWOC
Mixing
procedure
Added to mix
water or dry
blended
Added to mix
water or dry
blended
Packing
Comments
50 lb.
sack
50 lb.
sack
DISPERSANTS (Friction Reducers)
Name
DFR-1
Temp.
range
Up to 350
0
F
Normal
concentration
Up to 2.0%,
BWOC
Mixing
procedure
Added to
mix water
Packing
Comments
50 lb.
sack
ACCELERATORS
Name
CaCl2
DAL-1
SODIUM
SILICATE
SALT
Temp.
range
Up to
100 0F
Normal
concentration
Up to 2.0%,
BWOC
Up to
100 0F
Up to
200 0F
Up to
0
360 F
Up to 10.0%,
BWOC
Up to 1.0 GPS
Up to 5.0%,
BWOC
Mixing
procedure
Added to
mix water or
dry blended
dry blended
Added to
mix water
Added to
mix water or
dry blended
Packing
Comments
100 lb.
sack
Calcium Chloride
50 KG
sack
52 gallon
drum
50 Kg.
sack
Gypsum cement
Packing
Comments
5 gal can
2 PT/10 BBLS IN
BENTONITE SLURRIES
Order of mixing is
critical
Sodium Chloride
NON-FOAMERS
Name
DAF-1
Temp.
range
Up to
0
500 F
Normal
concentration
1 PT/10 BBLS
Mixing
procedure
Added to mix
water
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NOWMCO CEMENT ADDITIVES (continued)
STRENGTH RETROGRESSION PREVENTERS
Name
Temp. range
SFA200
SFA100
250 0F – 500 0F
250 0F – 500 0F
Normal
concentration
25%-100%,
BWOC
25%-100%,
BWOC
Mixing
procedure
dry blended
dry blended
Packing
Comments
100 lb.
sack
100 lb.
sack
Silica Flour
Silica Sand
HEAVY WEIGHT ADDITIVES
Name
Temp. range
Hematite
Up to 500 0F
Normal
concentration
Depends on
required slurry
density
Mixing
procedure
dry blended
Packing
Comments
100 lb.
sack
Hematite (Fe3O4)
EXTENDERS (LIGHT WEIGHT ADDITIVES)
Name
Temp. range
Bentonite (PH)
Up to 400 0F
Sodium
Silicate
Up to 200 0F
18 of 48
Normal
concentration
Up to 6.0%,
BWOC, when
prehydrated
Up to 1.0 GPS
Mixing
procedure
Added to
mix water
Packing
Added to
mix water
55 gallon
drum
Comments
1.5 ton
super sack
NOWCHECK,
Order of mixing
is critical
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CHAPTER 2
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2.0
SLURRY DESIGN
2.1
Factors That Influence Cement Slurry Design
Lab tests are run prior to pumping cement in a well. Collecting accurate data
prior to designing the cement ensures a good cement design. The following
factors will effect the cement slurry design:
•
•
•
•
•
•
•
•
•
•
•
•
2.2
Well depth
Well temperature
Mud column pressure
Viscosity and water content of cement slurry
Strength of cement require to support the pipe
Quality of available mixing water
Type of mud & density
Slurry density
Cement shrinkage
Permeability of set cement
Fluid loss requirements
Resistance to corrosive fluids
Limitations of Thickening Time Test Data
The thickening time test is a dynamic test. While the cement slurry is being
tested, measurements are being made of the consistency (viscosity) under
downhole circulating conditions. The thickening time test does not give
information on how the cement slurry performs under down hole static
conditions. The thickening time test does not give useful information on the
following:
•
•
•
•
The setting profile of the cement after the plug is bumped.
The compressive strength of the cement.
How the fluid loss to the formation affects the cement slurry.
How long the cement will be pumpable during a shutdown. This is
different for each cement slurry and the particular well conditions.
To determine theses parameters, tests that simulate the slurry’s environment
under static/dynamic conditions must be performed.
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Typical Thickening Time
120
100
80
Temp deg F
Pres. psi
60
Cons. Bc
40
1:50
1:42
1:34
1:25
1:17
1:09
1:01
0:53
0:45
0:36
0:28
0:20
0
0:00
20
Time (HRS:MINS)
Shown above is a typical thickening time curve for Class G cement + 1% CaCl2 @ 118 pcf,
0
a BHCT of 100 F. When the consistency reaches 100 Bc the thickening time is terminated.
The Aramco Oilwell Cement lab has five HT/HP Consistometers for the
determination of thickening time.
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2.3
Fluid Loss Tests
Cement is like drilling mud in some aspects, as it is a suspension of solids.
Chemical reactions occur on the surface of the solid particles of cement after
water has been added. The rate that a cement slurry loses water through a
high permeability zone under pressure is called fluid loss or filtration rate.
The water that is lost from the slurry does not give the cementing properties
that were originally designed.
When water is lost from the cement slurry, the slurry property’s change:
•
Viscosity increases which increases friction or pump pressures. – High
loss of water will result in a highly viscous cement slurry which is
unpumpable.
•
Thickening time decreases
•
Higher solids to liquid ratio – cement bridges may form in areas of
narrow clearances
The water that is lost from the cement slurry will have higher compressive
strengths. High fluid loss cement slurries can be used when squeezing high
injection rate leaks or perforations.
Two types of tests are preformed for cement slurries. 1) HT/HP Fluid
loss test and 2) Stirred fluid loss test. The permeable medium for both
tests is a 325 mesh screen.
2.3.1
HT/HP Fluid Loss Tests (BHCT<190 0F)
The cement slurry is condition at bottom-hole circulating temperature
(maximum 190 0F) under atmospheric pressures. The cement is then
transferred to the fluid loss cell and tested at the bottom-hole
circulating temperature and 1000 psi. The filtrate collected is used to
calculate the fluid loss.
2.3.2
Stirred HT/HP Fluid Loss Tests (BHCT>190 0F)
The cement slurry is condition in the test apparatus at bottom-hole
circulating temperature and 1100 psi. The cell is then rotated 180
degrees and the test cement slurry falls on to the 325 mesh screen.
Back pressure (100 psi) is maintained through out the testing period.
The filtrate collected is used to calculate the fluid loss.
Cements tested with the Stirred fluid loss cell generally give higher
fluid loss values as compared to the same cements tested on the
HT/HP fluid loss cell.
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The stirred fluid loss cell gives more accurate fluid loss
values than the conventional fluid loss test.
2.4
WOC Time
The industry accepts a compressive strength of 500 psi for drilling out the
casing shoe. This is also true for testing and drilling out the top of the liner.
On Arab-D wells, where the top of the liner is shallow and the cement density
is low the 500 psi compressive strength may take up to 10 hours to develop.
On deep gas wells with long liners, up to 30 hours may be required for the
cement to develop 500 psi compressive strength.
2.4.1
Ultrasonic Cement Analyzer (UCA Test)
The UCA is a non-destructive test that gives sonic (compressive)
strength data as a function of time. This test is usually run for 24
hours. The test is run for longer periods of time depending on the
setting profile of the cement. The most important use of the data from
the UCA is WOC (waiting on cement) time. It should be noted that
this test uses uncontaminated cement slurry unless otherwise
specified. Mud contamination in cement slurries can either shorten or
lengthen the initial set of the cement. Mud contamination also
reduces the final compressive strength.
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ULTRASONIC CEMENT ANALYZER
3000
2000
1000
0
0
50
100
150
TIME (HOURS)
Shown above is the compressive strength of a 7” liner jobs for a Khuff gas well
2.4.2
Static Gel Strength Analyzer (SGSA Test)
The SGSA/UCA is a non-destructive test that gives static gel strength &
sonic (compressive) strength data as a function of time. The most
important use of the data from the SGSA are 1) the time that the cement
slurry begins to gel (zero gel) and the time that the slurry reaches a gel
strength of 1200 lb/100 ft2 (maximum gel) and 2) sonic strength which
WOC (waiting on cement) time is determined. Hydrostatic pressure from
the cement slurry is being lost at the Zero Gel point. At the maximum gel
point the cement is so thick that fluids (including gases) can not pass
through the cement column. For gas and fluid migration control, the
shorter the time between zero gel and maximum gel the better the chance
for preventing migration of downhole fluids through annulus to surface.
Some literature states that gel strength of 500 lb/100 ft2 is the point that
gas leakage can be contained. It should also be noted that this test uses
uncontaminated cement slurry unless otherwise specified.
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SGSA/UCA Data
3500
Temperature (°F)
2800
ZERO
GEL
2100
1400
Static Gel Strength
(lb/100ft2)
MAX
GEL
700
Compressive
Strength (psi)
15:54
14:08
12:22
10:36
8:50
7:04
5:18
3:32
1:46
0:00
0
Time
This Static gel strength data is for a 150 pcf cement used to cement across
abnormal pressure Jilh formation
The Saudi Aramco Oilwell Cement lab has three SGSA/UCA
units for the determination of static gel strength.
2.5
Pressurized Mud Balance & Densitometers
A pressurized fluid density balance is used to monitor the density
of cement slurry that is mixed in the field. Non-pressurized fluid
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density balances (mud balance) should be avoided as errors of up
to 15 pcf can occur due to entrapped air in the cement slurry. The
pressurized density balance greatly reduces the volume of trapped
in the slurry. High density cement slurries that are mixed with latex
additives tend to trap more air than conventional cements.
A pressurized fluid density balance should be used to calibrate any
densitometers on the cementing units. Calibration should be made
at two densities. It is recommended to calibrate the densitometer at
the cement density and either the spacer or mud density. Once the
calibration is complete, it should not be re-adjusted before or
during the cement job unless confirmed by the pressurized density
balance. The densitometers should be placed on the pressure side
of pumps to guaranty accurate density measurements.
Pressurized Mud Balance
2.6
Free Fluid Test (free water)
If excess water is added to the cement beyond the requirement for fluidity or
chemical reaction the solid particles separate from the slurry leaving the
lighter excess water on top. This excess fluid is called free fluid. Neat class
G cement mixed at 118 pcf should have a maximum free fluid of 1.4%
according to API Spec 10A, Specification for Cements and Materials for Well
Cementing, 22nd Edition, January 1995.
2.7
Rheology Test
Measuring the rheological properties of a cement slurry provide information of
the cement slurry’s flow properties and settling tendency. The Fann model 35
rotational viscometer is the most widely used instrument used for
determination of rheological properties for well cements. The rheological
model is first determined from the Fann readings. Two models are considered
for cement slurries (Power Law and Bingham Plastic). Turbulent flow is more
easily achieved if n’ (power law) approaches 1 and YP (Bingham Plastic)
approaches 0 or negative. Density settling is possible if n’ >1.0 or if YP<1.
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2.8
Mud-Spacer-Cement Compatibility Test
Rheology data of cement, spacer and mud are used as guidelines to
determine if the fluids are compatible. Rheology of the mixtures of various
concentrations of cement-spacer, spacer-mud and cement-spacer-mud are
taken to evaluate the effect of mixing of the three fluids. Sever gelling is
noted when the rheology readings of the mixtures is much higher than the
three initial readings of the cement, spacer and mud. Highly compatible fluids
are determined when the Fann readings of the mixtures of the fluids fall in
between the readings of the base fluids. Example of mud compatibility test is
shown below.
API Compatibility of Heated Fluid Mixtures
Well no./Job Type
Date: DD/MM/YYYY
Lab. Project No. xx-xxxxx
Data Taken @ xxxoF
_______________________________________________________________________________
Viscosity Dial Reading
Sample Type
600
100% Mud (xxx pcf) Oil / Water based
100% Spacer (xxx pcf)
100% Cement (xxx pcf)
75% Mud / 25% Spacer
25% Mud / 75% Spacer
75% Spacer / 25% Base Cement Slurry
25% Spacer / 75% Base Cement Slurry
25% Mud / 50% Spacer / 25% Base Cement
Slurry
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300
200
100
6
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2.9
Gas Migration Additives
Every service company has cement additives that helps reduce or eliminate
gas migration during the setting of cement. Service companies also have
cement additives that expand after the cement has set. Most additives that
are supposed to prevent gas migration as the slurry sets produce cement
slurry that has low fluid loss. Common additives to prevent gas migration
during the setting of cement are D-600 (Dowell), Latex 2000 (Halliburton) and
B-86L (BJ). All of these latex additives require the addition of stabilizer D-135,
Stabilizer 434B and LS-1 respectively. Studies show that these polymers and
latex additives fill the porosity of the cement matrix giving the cement very
low permeability during the transition from slurry to solid.
Expanding additives (Microbond-HT, B-82 and EC-2) all expand after the
cement has set. This expansion is dependent on the exposure temperature of
the cement. The maximum linear expansion with 5% (by weight of cement) of
these additives is around 2.5%. It is possible for gas leaking up the annulus,
after the cement job, to stop some time later (up to one month) due to late
expansion of set cement, which contains these additives. Cements without
expanding additives normally shrink after the hydration reaction is complete.
Expanding additives and latex additives have been successfully used in
cementing the abnormally pressured Jilh formation. More recently expanding
additives have been used to cement the Arab-D open hole sections of deep
gas wells. These wells have abnormal pressure due to their location, which is
usually near to water injectors.
2.10 Cementing: Pre-Job Considerations for Slurry Design
The following will aid in planning a successful cement job.
•
•
•
•
•
•
•
•
•
What is the depth? MD, TVD?
What is the BHST?
What is the BHCT?
Has correction been made for Horizontal section of the well with respect
to BHCT?
What is the required density? (LOC or Abnormal Pressure Zones)
What is the estimated job time?
What is the chemical composition of the mix water? Ca+2,Mg+2,Clvalues?
What is the chemical composition of the drilling fluid’s filtrate?
Ca+2,Mg+2,Cl- values?
Has bactericide been added to the mix water?
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•
•
Is there a potential for annular flow of gas or liquid as the cement sets?
Are there any special or unusual well conditions that must be
considered?
2.11 Pre-Job Meeting
Before every cement job, the Foreman will hold a pre-cement meeting to
assure that the objectives are understood, assignments made and possible
problems and solutions are discussed. Those involved in the meeting will be
the Drilling Engineer, Contract Toolpusher, Foreman, Cementer(s) and the
Driller. The liner hanger representative will be on location for liner jobs. The
Engineer is available for cement slurry design, volume calculations and
recommended pressures for bumping the plugs. He will also discuss the
mixing, displacing, and thickening times. All three parties, Engineer,
Foreman, and Cementer will individually calculate and compare the slurry
and displacement volumes.
Assignments will be made as to who will:
•
Monitor the cement slurry weight.
•
Pump water and mud to the pump trucks or cementing unit.
•
Insert plugs. (Foreman & Cementer)
•
Check displacement volumes.
•
Catch samples. It doesn't do much good to catch a dry sample of
cement unless a container of mixing water is caught at the same time.
All signals for communications will be reviewed. The pressure recorder on the
cementing unit, the 5 or 6 pen drilling recorder and the radioactive
Densiometer (if used) should all be inspected prior to the job to insure that
they are working properly.
The Foreman must not have any duties that will tie him down to any one
operation. He must be free to supervise the overall operation and be able to
go to any trouble that may occur.
To avoid any potential problems in communications onshore, the pump truck
should be located so that visibility is good between the driller's console and
the pump truck. The best way to accomplish this is by placing the pump truck
at the end of the catwalk.
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2.12 Cementing Information Form
Casing:
Cement pumps:
_____________in OD
_____________Gr.
_____________in ID
_____________in DD
_____________bbl/ft Cap.
_________in. Liner
_________in. stk
_________bbl/stk
Mud Weight:
_________PCF
_____________ bbl/ft Disp.
_____________psi IYP
_____________psi Col.
_____________lb M load
_____________ lb MS load
_____________ft MD
_____________ft TVD
_____________ft DVlower
_____________ft DVupper
_________PPG
Hole:
________in. size
________ft MD
________ft TVD
________bbl/ft Cap
________ bbl/ft Cap + excess
Cement:
_______________sks
_______________bbl
_______________PCF
_______________PPG
Mud Buoy.
Factor:______
Cement Pump: _______________stk/min = _____________bbl/min
Mud Pump:
_______________stk/min = _____________bbl/min
Casing Vol.
1)_______ft X ______bbl/ft
= ________bbl
2)_______ft X ______bbl/ft
= ________bbl
3)_______ft X ______bbl/ft
= ________bbl
Total casing inside volume
= ________bbl
________stk
________stk
________stk
________stk
Annulus Vol. 1)_______ft X ______bbl/ft
= ________bbl ________stk
2)_______ft X ______bbl/ft
= ________bbl ________stk
3)_______ft X ______bbl/ft
= ________bbl ________stk
4)_______ft X ______bbl/ft
= ________bbl ________stk
Total annulus volume = ________bbl ________stk
Cem Head to Shoe: _________bbl = _________stk = ________min
Head to Plug Bump : _________bbl = _________stk = ________min
Bottom Plug Ruptures at: ___________psi*
Proper DV plug Loaded?______________
Mixing Cement Time: ____________hours/minutes
Displacing Cement Time: ______ Time Start_______ Time End_______ Total
DVlower free fall plug time: ________min
DVupper free fall plug time: ________min
Top of Cement: 1)___________bbl / _________bbl/ft = ___________ft
2)___________bbl / _________bbl/ft = ___________ft
3)___________bbl / _________bbl/ft = ___________ft
Total 1), 2) & 3) = ___________ft
WOC Time = __________________ hours
*Usually not run in Saudi Aramco Operations
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3.0
LAB TESTING OF CEMENT
3.1
Types of Tests
The cement lab routinely performs the following test on all field cement jobs.
•
Thickening Time (pumping time)
•
Fluid Loss (only if the slurry contains fluid loss additives)
•
Free fluid (free water, vertical or 45 degrees)
•
Rheology (determine turbulent flow rate)
•
Sonic Strength (compressive strength)
•
Slurry Density (pressurized density balance)
The cement lab can perform the following special test at the request of
Drilling Operations or Drilling Engineering:
•
•
•
•
•
•
3.2
Static Gel Strength
Settling (density settling)
Expansion (both linear & radial)
Cement-Spacer-Mud compatibility
Gas Migration Potential
Cement ROP (Kick-off/Sidetrack Plugs)
When To Send Samples For Testing
Cement Samples should be sent in for testing for the following reasons:
•
Forman or Engineer suspects a problem with cement, cement additives
or mix water.
•
Service company lab not functioning
•
BHST > 2200F
•
Khuff wells: K2 wells, 13 3/8” casing and deeper,
•
K1 wells, 9 5/8” casings and deeper
•
All CTU Cement Jobs
•
Abnormal well conditions that may adversely affect the cement job.
•
Remote locations *
*For remote locations, cement and rig water should be sent to Saudi Aramco
and Service Company labs at least three days before the cement job.
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3.3
Initial Pilot Testing
This test is performed on lab cement, raw water (rig water if in stock) and lab
additives. The most recent batch of cement from the factory is used to
perform these tests. The standard tests are carried out. The most important
function of performing this test is to save lab and rig time. Lab tests are
performed to determine the retarder and fluid loss additive concentrations to
meet the thickening time and fluid loss requirements. Pilot tests are not
always performed prior to the writing of the program. Database searches are
usually a good starting point in the design of the cement slurry.
3.4
Pilot Testing prior To Mixing
Samples of rig cement blend and rig water are collected and tested for the
critical physical properties. This test is used to compare test results from the
Aramco oilwell cement lab with the Service company’s lab. When comparing
the thickening time results of both labs the following rule should apply: The
thickening time results that have the highest concentration of retarder for the
shortest acceptable thickening time is the cement formulation that should be
mixed in the field. This applies only if all other tests like fluid loss,
compressive strength development, etc. are within the requirements set by
Drilling Engineering. These requirements are usually listed on the drilling
program.
3.5
Field Sample Confirmation Testing
Samples of cement blend and mixing fluid (water plus cement additives) are
sent in by the Service Company to both Saudi Aramco and service company
oilwell cement labs. The results are usually faxed to the rig as soon as the
thickening time is finished. The compressive strength data is usually sent the
next day. For sample sizes see section 4.6.
4.0
MIXING CEMENT
The most important cement slurry property that can be measure in the field is slurry
density. All lab tests are performed at the designed slurry density. Variation in
slurry density in the field will produce cement slurry that may be unpredictable with
respect to thickening time, fluid loss, rheology, free fluid, settling, static gel strength
and compressive strength. The pressurized density balance is the best device
readily available to field personnel to measure cement density. Batch mixing is
the most effective way to ensure accurate slurry density.
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4.1
Mix Water Quality
The water used as pre-blended cement mix water should be reasonably
fresh. If the water is too hard (high Calcium & Magnesium concentration) then
alternative sources of water should be located. If the proposed water is high
in Chloride then alternative sources of water should be located. If no
acceptable water can be found send a sample of the proposed water to the
cement lab and a softening treatment can be recommended in most cases.
Softening treatments usually include adding Soda Ash and or Caustic
causing a heavy white precipitate to settle to the bottom of the tank. The clear
water should be skimmed off the top after the precipitate has settled to the
bottom of the tank. Sometimes there are exceptions to this rule and they
should be clearly defined in the drilling program. Biocide should be added to
all mix waters that contain retarders, friction reducers or fluid loss additives. If
any mix water is questionable then verify that such water is acceptable with
the Drilling Superintendent / Engineer / Oilwell cement lab prior to blending
chemicals.
4.2
Type of Chemicals and Quantity to Be Blended
The type of chemicals and quantity to be blended in the mix water will be
specified in the drilling program or separate cementing procedure
(supplement to the program) based on lab data. Mix those chemicals in the
water on location. This allows an "on site" check of the water quality and type
and quantity of chemicals blended. The Drilling Foreman is personally
responsible for confirming that the proper types and amounts of chemicals
and water are utilized in preparing the "mix water” blend.
4.3 Mix Water Blending and Storage System
Mix water must at all times be completely isolated from any source of
contamination. The fluid handling system used to blend and pump the cement
mix water should be completely isolated from all other fluid systems. A
common manifold for the pre-flush, mix water, wash water and mud systems
is not acceptable. It is acceptable to utilize a manifold for other fluids than
cement mix water; i.e., pre-flush, wash water and mud. An individual fluid
handling system of tanks and lines to the cementing unit is necessary for the
mix water system. This will usually involve rigging up special lines and tanks.
Rig up as necessary to achieve the above.
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4.4
Cement Job Quality
The preparation work prior to performing a complicated cement job is
crucial to the success of the cement job. Batch Mix cement when
possible. This gives you a positive check of the total batch of cement
slurry before it goes downhole. On large jobs (where you can't batch
mix), mix and pump a small amount to the desert before pumping
cement downhole. This short 'pump test' will exercise the pump
system and prove that the system can blend cement slurry with the
fluid properties and weight desired. On large critical jobs, where one
particular service company does not have the sufficient batch mixing
capacity, employ the use of other service company batch mixers. It is
recommended that only one Service Company pump the cement job.
The Foreman should completely satisfy any question he might have
regarding the mechanical reliability of the equipment, cementing
technique to be used, mix water blend and mix water system
reliability, well conditions, etc. before mixing cement. Don't hesitate to
discuss any question with the Drilling Superintendent and eliminate as
many problem areas as possible.
4.5
Pre-mixing additives
The tanks that the mixing fluid will be stored should be clean. Lines filling the
tank should be flushed if used for purposes other than transporting water.
Liquid Bactericide (biocide) should be poured on the bottom of the tank prior
to filling the tank. Most resident bacteria colonies will be on the tank bottom.
Bacteria thrive on cement chemicals like retarders, fluid loss additives and
dispersants. Fill the tank with water. Mixing water should be cool. If Wasia
water is used, it must be allowed to cool in open tanks for at least 24 hours.
Past experience has indicated that many 'flash sets' were the direct result of
using a Hot, saline water. The calcium & chloride content of the mixing water
should be checked prior to mixing. Temperature, calcium and chloride
content of the mix water should be recorded. Biocides generally have short
half-lives. Additional biocide should be added every eight hour during the
hotter months (April through October). During the cooler months (November
through March) add biocide every 12 hours. Check with the Service
Company or the Aramco cement lab for proper order of addition of cement
chemicals prior to pre-mixing additives to the water.
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4.6
Sampling and Sample sizes
4.6.1
Sample Containers
All sample containers should be clean and free of moisture. The
sample containers for dry cement should be air tight. The sample
containers for water and the mixing fluid should be leak proof. Saudi
Aramco Material Stock number (25-008-865) One-gallon wide mouth
plastic bottles are good for both dry cement and mix fluid.
4.6.2
Dry Cement Sampling
For sampling dry cement either of two methods are acceptable. 1)
First Aerate the cement for five to ten minutes, then open the hatch on
the bulk storage unit and sample the cement blend approximately one
foot (12”) below the top level. 2) Pressurize the bulk storage unit,
then blow out a volume of cement that would represent the volume left
in the line, then catch the required sample of dry cement.
4.6.3
Sampling of Mix Fluid
After all the cement additives have been mixed in the water, continue
to circulate the fluid for thirty minutes. At this point sample the fluid
from the top of the tank. Do not sample from a valve. If any fisheyes
(dry additive that have gelled due to improper hydration) are floating
on the top, do not include them in the sample.
4.6.4
Sample Size of Lab Testing
For pilot testing purposes, each lab should receive a minimum of two
gallons of water from the same source that will be used for cementing.
The minimum dry cement sample size for lab testing is one gallon for
each laboratory and each stage. For a three stage cement job, where
all three stages are requested to be tested, the samples should be
distributed as follows: Three dry cement samples would go to the
Saudi Aramco Cement lab and the other three would go to the Service
Company lab.
The minimum mix water sample size is one gallon.
This is
approximately twice the amount required to mix with one gallon of
cement. Additional water is required because adjustments may be
needed to lengthen the thickening time of the field mixed sample.
Usually, the labs will have some leftover cement blend from the pilot
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tests performed prior to mixing. The lab will only resort to using that
sample as a last resort.
4.6.5
Sample Labeling
All samples should be labeled as follows:
•
Well Name & No.
•
Rig Name & No.
•
Date
•
Job Description & Stage
•
Description of Sample
•
Include all the additives that are mixed in the water or blended in
the cement.
•
Name of Lab (Saudi Aramco or Service Co.)
5.0
BALANCED PLUGS
Many operations require that a cement plug be set in the open-hole or casing to
plug back a well to a shallower depth for a number of reasons. The most important
and common applications include the following:
A)
Balanced Plug Method
The ideal cement plug is placed so there is no tendency for the cement slurry
to continue to flow in any direction at the time pumping is stopped. This
involves balancing the hydrostatic pressures inside and outside the drill pipe
or tubing so that the height of cement and displacing fluid inside the drill pipe
or tubing equals the height of fluids in the annulus. The pipe or tubing is then
pulled slowly from the slurry, leaving the plug in place. To allow the pulling of
a "dry" string of tubing, common field practice is to cut the displacement
volume short by 1/2 to 1 barrel.
The characteristics of the mud are very important when balancing a cement
plug in a well, particularly the ability to circulate freely during displacement.
Whenever possible, the mud should be conditioned thoroughly to uniform
densities and rheological properties and the same mud used as the
displacement fluid.
Movement of well fluids while the cement plug is setting may affect the quality
of the plug, therefore, it is imperative that care be taken in accurately spotting
the slurry and moving the pipe slowly out of the slurry to avoid backflow,
slugging, or swabbing action. The amount of pre-flush or spacer, cement
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slurry, and volume of displacement fluid must be carefully calculated to
ensure equal volumes of fluid ahead of and behind the cement plug as it is
being placed in the hole. The quantities that must be calculated are as
follows:
A)
B)
C)
D)
E)
Determine the drill pipe or tubing capacity, the annular capacity, and
hole or casing capacity.
The length of the cement plug or the number of sacks of cement for a
given length of plug.
The volumes of spacer needed before and after the cement to balance
the plug properly.
The height of the plug before the pipe is withdrawn.
The volume of the displacement fluid.
M M
M
W
W
M
M
M
W
W
W
(a) Displacing
cement.
M
M
M M
W
W
M
M
M
(b) Cement, water
and mud balanced.
(c) Pulling string
above top of cement.
W
M
M
M
(d) Reversing out.
M = Mud
Balanced Plug Technique
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Balanced Plug Formulas
Cement requirements: N = L * Ch
Y
Spacer Volume behind
the slurry to balance plug:
Length of balanced
plug before pulling
pipe from slurry:
Mud Volume for
pipe displacement:
where:
Vb = Cp* Va
Ca
N = sacks of cement
L = plug length, ft.
Ch = hole or casing capacity, cu ft/ft
Y = slurry yield, cu ft/sack
where: Va = spacer volume ahead, bbl
Vb = spacer volume behind, bbl
Ca = annulus capacity, cu ft/ft
Cp = pipe capacity, cu ft/ft
Lw = N * Y where: Lw = Plug length before pulling the
(Ca+Cp)
pipe from the slurry, ft
Vd = [(Lp - Lw) * Cp] - Vb
where: Vd = displacement volume, bbl
Lp = total pipe length, ft
*Cp = pipe capacity, bbl/ft
Vb = spacer volume behind, bbl
* Note pipe capacity, Cp, is expressed in different units.
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5.1
Loss Circulation Plugs
When mud circulation is lost during drilling, it is sometimes possible to restore
lost returns by spotting a cement plug across the thief zone and then drilling
back through the plug. Thixotropic cements or low thickening time cements
are usually recommended for this application. See Chapter 2, Section F for
more details.
5.2
Kick-Off/Sidetrack Plugs
5.2.1
Kicking Off:
For Deviated and Horizontal wells, cement Kick-off plugs can be used.
Generally these plugs are not as effective as using a whip stock. Kickoff cement plugs are set in open hole. Additives are mixed in the
cement to both densify and lower the ROP in the cement plug.
Removing the water (higher density cements) reduces the porosity
which lowers the ROP in the set cement. Frac proppants or frac sand
can be added to the cement slurry to aid in reducing the ROP in the
cement plug to obtain a more successful Kick-off. Ample curing
(WOC) time should be given to the cement plug so that the plug
obtains at least 90 % of its final strength. It is very difficult to get a
cement plug that is harder than the formation unless the kick-off point
is in a weak unconsolidated sand or very high porosity zone.
5.2.2
Sidetracking:
In sidetracking a hole around unrecoverable junk, such as a stuck
drillstring, it is necessary to place a cement plug above the junk at a
required depth that will allow sufficient distance to kick off the cement
plug and drill around, bypassing, the original hole and junk. Highdensity cement plugs are usually recommended for this application.
5.3
Isolation/Abandonment Plugs
For more details on Abandonment guidelines and cement plugs, see Chapter
2, section G.
Zone Isolation: One common reason for plugging back is to isolate a specific
zone. The purpose may be to recomplete a zone at a shallower depth, to
shut-off water, or to prevent fluid migration into a low-pressure depleted zone.
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Abandonment: To seal off selected intervals of a dry hole or abandon an
older, depleted well, a cement plug is placed at the required depth to prevent
zonal communication and migration of fluids in the wellbore.
Producing
Zone
Cement
Plug
Depleted
Zone
PLUG BACK DEPLETED ZONE
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6.0
DISPLACEMENT PROCEDURES
6.1
Casing
Rig pumps will normally be used to displace the cement in full string cement
jobs. When using the rig pumps, pre-calibrate the number of strokes per
barrel using a trip tank. This will insure that the pump rate can be reduced
prior to the plug bumping. Pump displacement fluid until the plug has bumped
but DO NOT OVER DISPLACE MORE THAN ½ THE SHOE TRACK
CAPACITY. Record whether circulation was maintained. Record the plug
bumping pressure. After the plug bumps, hold pressure for a few minutes and
then slowly release pressure to make sure the float equipment is holding.
On Multistage Cementing jobs where displacement type plugs are used the
same displacement rule applies. Usually the bypass plug is displaced 10
barrels short of the bypass baffle. In this case the over displacement would
equal 10 barrels plus half the shoe track volume. If the plug has not bumped
(landed or seated in the DV) by this time then hold pressure until the cement
has set. The Saudi Aramco cement lab has many compressive strength
records on the setting behavior (WOC time) of class G cement at many
different conditions. They can provide the rig with a WOC time.
6.2
Liners
On all liner jobs, the pumps on the cement truck will be used for
displacement, unless under emergency conditions (volumetric
displacement is more accurate than a stroke counter). Additional mud
de-foamer is usually required to remove entrapped air from the mud and get
more accurate volume on the displacement. If you can see the pressure
build up (usually about 800 psi) as the 'dart' shears the brass pins before
releasing the 'wiper 'plug'; make a note of this volume. This volume added to
the liner volume can be used to more accurately determine when the 'wiper
plug' will seat in the baffle. If you miss the shear pressure and the 'wiper
plug' does not bump after the calculated displacement, DO NOT OVER
DISPLACE. It is far easier to drill out cement than it is to squeeze the shoe!
Generally, it is recommended to pull three to five stands before reversing out
excess cement. Special instructions will be included in the drilling program
should alternative procedures be required after the cement is pumped on
liner liner jobs. Do not displace cement with oilmud, or water based mud or
brine that has high Calcium content.
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6.3
Turbulent Flow
Turbulent flow is always the best flow regime for cleaning mud off casing and
formation face. Unfortunately, turbulent flow can not be achieved easily due
to formation frac gradient, balance pressure or horsepower required to
achieve turbulent flow. Lab reports show the rate required to achieve
turbulent flow. Turbulent flow is easier achieved in smaller cross sectional
areas. The same cement slurry would reach turbulent flow faster in a 4 ½”
liner in 6 inch hole than a 13 3/8” casing in a 17.5” hole.
7.0
REMEDIAL CEMENTING
7.1
Bradenhead Squeeze
The original method of squeezing was the Bradenhead method, which is
accomplished through tubing or drillpipe without the use of a packer. BOP
rams are closed around the tubing or drill pipe and the injection test carried
out to determine the formation breakdown pressure. The cement slurry is
then spotted as a balanced plug, and the work string is pulled up and out of
the slurry. The annulus is then shut off by closing the annular preventers or
pipe rams around the cementing string. Displacing fluid is pumped down the
tubing forcing the cement slurry into the zone until the desired squeeze
pressure is reached or until a specific amount of the fluid has been pumped.
This method is used extensively in squeezing shallow wells and sometimes
when squeezing off zones of partial lost circulation during drilling operations.
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Sp ot
Cemen t
A pp ly
Sq ue ez e
Pressu re
Rev erse
Circulat ion
Br adenhead Squeez e
When shallow wells are squeezed by this method, fluids in the tubing are
displaced into the formation ahead of the cement. In deeper wells, the
cement may be spotted halfway down the tubing before the annulus is shut in
at the surface. The applicability of Bradenhead squeezing is restricted
because the casing must be pressure tight above the point of squeezing and
because maximum pressures are limited by the burst strength of the casing
and the pressure rating of the wellhead and BOP equipment at the surface.
Also, it is sometimes difficult to spot the cement accurately across the interval
without using a packer.
7.2
Packer Squeeze
Packer Squeeze
The main objective of this method is the isolation of the casing and wellhead
while high pressure is applied downhole. The selective testing and cementing
of multiple zones is an operation where isolation packers are commonly used.
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The packer squeeze method uses either an expendable, drillable, packer
such as a cement retainer or a retrievable packer tool run on a work string
and positioned near the top of the zone to be squeezed. This method is
generally considered superior to the Bradenhead method since it confines
pressures to a specific point in the hole. Before the cement is placed, an
injection test is conducted to determine the formation breakdown pressure.
When the desired slurry volume has been pumped or squeeze pressure is
obtained, the remaining cement slurry is reversed out. Squeezing objectives
and zonal conditions will govern whether high pressures or low pressures are
used.
Displacement
Brine
Fresh Water
Spacer
Brine
Pumped
Cement
Slurry
Brine
Fresh
Water
Spacer
Fresh Water
Pre-Flush
Cement
Retainer
Brine
Water
Cement
Slurry at
Perfs
Perfs
PACKER SQUEEZE JOB
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There are two common methods for placing the cement at the zone of interestBullheading
BU L L H EA D I N G
Ap p lie d
Casi ng
Pressu re
Ap p lie d
Casi ng
Pressu re
Di spl ace me nt
Fl ui d
Sometimes it is necessary to bullhead
cement between casing strings into the
annulus in order to bring cement back to
surface and to seal off the annulus. If this
is required, precautions must be taken not
to exceed the collapse rating of the inner
casing string when squeezing the cement
slurry down the casing annulus.
Cem en t
Cem en t
Mud
Mud
P u m p Ce m en t w i t h P a c ke r se t
D i sp l a c e M u d i n t o F o r m a t i o n
Ho l d A n n u l u s P r e ss u r e
In this method, a packer is set and
pressure is applied to the annulus. An
injection rate is established into the zone;
then the cement is mixed and pumped
down the work string. The mud, or brine,
as well as the cement is then forced into
the zone under pressure until the desired
squeeze pressure is obtained. The packer
is not released until the job is completed.
A p p ly Sq u e e z e
P r e ss u r e
Spotting
SPOT T I N G
Ap p lie d
Casi ng
Pressu re
Di spl ace me nt
Fl ui d
Cem en t
Cem en t
Mud
Mud
S p o t Ce m en t
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S t a b i n t o P ac k e r
A p p l y C as i n g P r es s ur e
D i sp l a c e C e m e n t
A p p l y S q u e e z e P r e s su r e
In this method, after establishing an
injection rate into the zone, the packer
is released or the by-pass opened. The
cement slurry is circulated down the
work string to just above the packer.
The packer is then re-set or the bypass closed, and the cement slurry is
squeezed away into the zone until the
desired
squeeze
pressure
and
volumes are reached. With this
method, the amount of mud or brine
that will be forced into the perforations
ahead of the cement is kept to a
minimum.
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CHAPTER 2
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DRILLING MANUAL
June 2006
DRILLING PRACTICES
CEMENTING
___________________________________________________________________________________________________________________________
Packer Squeeze Tools
The use of squeeze packers makes it possible to apply higher pressures to specific
downhole points than can be applied with the Bradenhead method. The two commonly
used packers are the drillable and the retrievable.
Drillable Squeeze Packers
Drillable packers, which are expendable, are left in the well
and can be drilled out after the squeeze operation. The
drillable packer contains a poppet-type backpressure valve to
prevent backflow at the completion of displacement and a
sliding valve for when it is desirable to hold pressure in either
or both directions. The sliding valve makes it possible to
support the weight of the hydrostatic fluid column and relieve
the cement of this weight while it is setting. Excess cement
can be reversed out of the drillpipe without applying the
circulating pressure to the squeezed area below the packer.
The tubing or drillpipe can also be withdrawn from the well
without endangering the squeeze job. Another advantage is
that they can be set close to the perforations or between sets
of perforations and are easily drilled if required.
Cement retainers set on drillpipe or wireline are used
instead of packers to prevent backflow when no cement
dehydration is expected or when high negative differential
pressures may disturb the cement cake. In certain situations,
potential communication with upper perforations could make
use of a retrievable packer a risky operation. When
cementing multiple zones, the cement retainer will isolate the
lower perforations, and subsequent zone squeezing can be
carried out without waiting for the cement to set. Cement
retainers are drillable packers provided with a two-way valve
that prevents flow in either or both directions. The valve is
operated by a stinger run at the end of the work string.
Drillable
Squeeze Packer
Drillable bridge plugs are normally used to isolate the
casing below the zone to be treated. They are of similar in
design to the cement retainer, and they can be set on
wireline or on drillpipe. Bridge plugs do not allow flow through
the tool.
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CHAPTER 2
SECTION
D
DRILLING MANUAL
June 2006
DRILLING PRACTICES
CEMENTING
___________________________________________________________________________________________________________________________
Retrievable Squeeze Packers
Retrievable packers are usually rented on a job basis and,
after the squeeze job, is removed from the well. Unlike
drillable packers, the retrievable packer can be set and
released as many times as necessary.
Retrievable packers with different design features are
available on the market. Most are of a non-drillable material
and are available in most API sizes. The ones used in
squeeze cementing, compression or tension set packers,
have a bypass valve to allow the circulation of fluids when
running in and once the packer is set. This packer feature
permits the spotting of pre-wash fluids and cement down to
the zone, cleaning of tools after the job, reversing of excess
cement without excessive pressures, and prevents a piston
or swabbing effect when tripping the packer in or out of the
hole.
Retrievable bridge plugs are easily run and operated tools
with the same function as the drillable bridge plugs. They
are generally run in one trip with the retrievable packer and
retrieved later after the cement has been drilled out. Most
operators will spot frac sand or acid soluble calcium
carbonate on top of the retrievable bridge plug before doing
the squeeze job to prevent cement from settling over the top
of the retrievable bridge plug.
Retrievable
Squeeze Packer
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DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
D
June 2006
DRILLING PRACTICES
CEMENTING
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8.0
CEMENTING EQUIPMENT
Schlumberger/Dowell Cementing Equipment
Left: 200 barrel Batch Mixer, Right: Batch Mixer inside view
Left: Cement Pump Truck
Right: Field Bulk Cement Storage Unit
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DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
D
June 2006
DRILLING PRACTICES
CEMENTING
___________________________________________________________________________________________________________________________
Halliburton Cementing Equipment
Left: 100 barrel Batch Mixer
Right Cement Pump Truck
Left: Bulk Cement Storage Unit
(2000 cubic feet)
Right: 18 5/8” Cementing Head
BJ Services Batch Mixer
Above: 120 barrel Cement Batch Mixer
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DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
E
June 2006
DRILLING PRACTICES
WELLHEADS
___________________________________________________________________________________________________________________________
WELLHEADS
1.0
INTRODUCTION
1.1 Wellhead Function
1.2 Tree Function
1.3 Ring Joint Flanges
1.3.1 Ring Gaskets
1.4 Typical Wellhead
1.4.1 Casing Head
1.4.2 Casing Spool
1.4.3 Tubing Spool
1.4.4 Tubing Bonnet (Tubing Head Adapters)
1.4.5 Tree Assemblies
2.0
STANDARD SAUDI ARAMCO WELLHEAD COMPONENTS
2.1 Casing Heads (Landing Base)
2.2 Casing Spools
2.3 Tubing Spools
2.4 Tubing Hangers (Extended Neck) for Oil Service
2.5 Tubing Hangers (Extended Neck) for Gas Service
2.6 Tubing Bonnets for Oil Service
2.7 Tubing Bonnets for Gas Service (With Master Valve)
2.8 Tubing Bonnets for Special Service (Electric Penetrators)
2.9 DSDPO Flange, Double Studded Double Pack-Off Flange
2.10 Trees
2.11 Loose Valves
2.12 Valve Bores and End-To-End Dimensions
3.0
INSTALLATION AND TESTING PROCEDURES
3.1 Primary and Secondary Seals
3.2 Casing Head
3.3 Slip Type Casing Hangers
3.4 Casing and Tubing Spool
3.5 Tubing Hangers
3.6 Tubing Bonnet and Trees
3.7 Trees
4.0
BACK PRESSURE VALVE INSTALLATION PROCEDURES
4.1 Back Pressure Valves for Oil Well Service
4.2 Back Pressure Valves for Khuff Gas Service
4.3 Type ‘H’ Back Pressure and Two Way Check Valve
4.4 Running Procedures for Type ‘H’ plugs.
4.1.1 Method 1: Installation Using the Retrieving/Running Tool
4.1.2 Method 2: Installation Using the Running Tool
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
E
June 2006
DRILLING PRACTICES
WELLHEADS
___________________________________________________________________________________________________________________________
WELLHEADS
1.0
INTRODUCTION
1.1
Wellhead Function
The wellhead performs three important functions:
A) Provides connection and support for blow out preventers and other well
control equipment.
B) Provides a sealed connection and support for each tubular string.
C) Provides a connection and support for the tree.
1.2
Tree Function
The tree also performs three functions:
A) Controls the flow of fluids from the well bore.
B) Provides a means of shutting on the well.
C) Provides a means of entering the well for servicing and workover.
1.3
Ring Joint Flanges
Flanges are the most commonly used end connections in the oil industry
apart from welds and threads (Figure 2E-1). API has standardized flanges
that are covered in API Spec 6A. ASME/ANSI has standardized flanges that
are covered by ASME/ANSI Spec 16.5. Because Saudi Aramco uses both
API and ANSI flanges, knowledge of the similarities and differences is
required. Some ANSI ring joint flanges will mate with API flanges but the
pressure ratings are different.
24.0000
1.500" X 20 BOLT HOLES
21.000
15.47
3.44
14.53
13.66
RING GROOVE
Figure 2E-1: API 13-5/8" 3,000 psi Flange
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WELLHEADS
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ANSI Class 600 flanges will mate to API 2,000 psi, ANSI Class 900 flanges
will mate to API 3,000 psi and ANSI Class 1500 flanges will mate to API
5,000 psi. If an ANSI flange is connected to an API flange, the connection is
DERATED to the pressure rating of the ANSI flange because it will not hold
as much pressure as the API flange. A comparison of some common flange
sizes is given in Table 2E-1 and working pressures of ANSI flanges by
temperature is given in Table 2E-2.
Table 2E-1
Comparison of Common API and ANSI Flanges
Size/WP
Ring
OD
Bolt
No. of Bolts
Bolt Circle
API
12"/3M
R-57
24
1 3/8
20
21
ANSI
12"/900
***
24
1 3/8
20
21
API
11"/5M
R-54
23
1 7/8
12
19
ANSI
10"/1500
***
23
1 7/8
12
19
API
11"/3M
R-53
21 1/2
1 3/8
16
18 1/2
ANSI
10"/900
***
21 1/2
1 3/8
16
18 1/2
API
7"/5M
R-46
15 1/2
1 3/8
12
12 1/2
ANSI
6"/1500
***
15 1/2
1 3/8
12
12 1/2
API
7"/3M
R-45
15
1 1/8
12
12 1/2
ANSI
6"/900
***
15
1 1/8
12
12 1/2
API
4"/3M
R-37
11 1/2
1 1/8
8
9 1/4
ANSI
4"/900
***
11 1/2
1 1/8
8
9 1/4
API
3"/3M
R-31
9 1/2
7/8
8
7 1/2
ANSI
3"/900
***
9 1/2
7/8
8
7 1/2
API
2"/5M
R-24
8 1/2
7/8
8
6 1/2
ANSI
2"/1500
***
8 1/2
7/8
8
6 1/2
*** The ring groove size must be checked for each flange.
Note:
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•
Only API flanges are used on producing wellheads, trees and drill
through equipment such as blowout preventers.
•
ANSI flanges, fittings and valves are used on water wells, pipelines,
gas plants and some surface production units.
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CHAPTER 2
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Table 2E-2 Ratings for Group 1.1 Materials
Working Pressure by ANSI Class, psig
Temperature °
-20 to 100
200
300
400
500
150
285
260
230
200
170
300
740
675
655
635
600
400
990
900
875
845
800
600
1,480
1,350
1,315
1,270
1,200
900
2,220
2,025
1,970
1,900
1,795
1500
3,705
3,375
3,280
3,170
2,995
2500
6,170
5,625
5,470
5,280
4,990
4500
11,110
10,120
9,845
9,505
8,980
Only API flanges are used on producing wellheads, trees and drill through
equipment such as blowout preventers. ANSI flanges, fittings and valves are
typically used on water wells, pipelines, gas plants and on some surface
production units.
1.3.1
Standard Ring Gaskets:
At Saudi Aramco our standard is the type R ring gasket for low
pressure connections and the BX for high pressure applications. The
oval ring and octagonal ring are both API type R ring gaskets as
shown in Figure 2E-2. These gaskets are designed to be used in
2,000, 3,000 and 5,000 psi flanges only. Stud bolts used with type R
gaskets must perform the double duty of holding pressure while
keeping the gasket compressed. When making up the flanges, the
curved surface of the relatively soft oval ring is mated with the flat
surfaces of the harder flange ring groove. A small flat is pressed on
the curved section of the oval ring. The size of this flat depends on
the bolt make-up torque. This is the main reason that ring gaskets
can only be used one time and must be replaced with a new gasket
each time a flange is made up.
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E
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WELLHEADS
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R OVAL
R OCTAGONAL
RX
BX
Figure 2E-2: API Ring Gaskets
As normal tightening proceeds, forces accumulate and deform the
ring to produce a seal. By the time all bolts around the flange have
been tightened, the first bolt is loose again. In most API flanged
connections with type R gaskets, it is necessary to tighten bolts
around the flange several times to reach a stable condition. The
octagonal R does not have to deform as much as the oval R to create
a seal.
When internal pressure forces become great enough to cause flexing
in an API connection that uses either of the type R gaskets, the
bolting contact force on the seal ring begins to decrease. If flange
separation forces exceed the limited resilience of the seal, leakage
will occur. External shock loads, such as drilling vibration, add to the
compressive loading of the stud bolts. This further deforms the
gaskets and can cause leaks making repeated tightening necessary.
The API type BX ring gasket has been developed primarily for use in
10,000 psi and greater working pressure equipment. There are
certain exceptions to this where the BX type gasket is used in 5,000
psi flanges. This pressure energized ring joint gasket is for use with
type BX flanges only and is not interchangeable with type R or RX
gaskets. The BX flanges are designed to make up face to face at the
raised face portion of the flanges. Figure 2E-2 illustrates the BX
flanges at initial contact.
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Drilling & Workover Engineering Department
CHAPTER 2
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E
June 2006
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WELLHEADS
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1.4
Typical Wellhead:
The typical wellhead for a three string well will consist of: (Figure 2E-3):
A)
B)
C)
D)
E)
The casing head (sometimes referred to as the Landing Base or
Bradenhead).
The Intermediate casing head (or Casing Spool);
The Tubing Head (or Tubing Spool);
The Tubing Bonnet (or Tubing Head Adapter);
The Tree.
TREE
TUBING BONNET
TUBING SPOOL
INTERMEDIATE
CASING HEAD
CASING HEAD
Figure 2E-3: A Three String Wellhead
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WELLHEADS
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1.4.1
Casing Head:
The casing head is attached to the top of the surface casing (Figure
2E-4). Since the other tubular strings are tied to the casing head, the
surface casing must support the weight of all the subsequent casing
and tubing strings, along with the entire wellhead system.
CASING STUB
CASING HANGER
CASING
HEAD
BASE
PLATE
CONDUCTOR PIPE
SURFACE CASING
CASING - HOLE
ANNULUS
CEMENT
INTERMEDIATE CASING
Figure 2E-4: The Casing Head
The casing head is welded onto the surface casing. The base plate
(support unit) is installed under the casing head and is not welded to
the conductor or casing head. The casing head accepts the next
string of casing, either a protective string or the production string
depending on the well design. The next string of pipe is hung by
means of a casing hanger in the casing head.
The intermediate string is hung in the casing head with a casing
hanger and cemented in place. The casing hanger holds the
intermediate casing and seals the casing to casing annulus. Hangers
are discussed in more detail later in this chapter.
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WELLHEADS
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1.4.2
Casing Spool:
The casing spool is bolted onto the casing head (Figure 2E-5). It can
be used to suspend either the production casing string, as shown, or
an additional string of protective casing. For each additional protective
string, an additional casing spool is required.
CASING STUB
CASING SPOOL
CASING HEAD
SURFACE CASING
INTERMEDIATE CASING
PRODUCTION
CASING
Figure 2E-5: The Casing Spool
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The casing spool consists of a lower flange for connection to the
casing head and an upper flange for connection to the subsequent
wellhead section. A cylindrical bore with shoulders is machined into
the upper half to receive the casing hanger. The casing spool contains
a primary seal (the casing hanger) inside the top flange and a
secondary seal (the packoff) located inside the lower flange (Figure
2E-6). The names primary seal and secondary seal were derived from
a pressure change situation. If the casing spool has a 3,000 psi
bottom flange and a 5,000 psi top flange, the casing hanger seal is
the first seal to prevent the 5,000 psi fluid from getting to the 3,000 psi
flange face. The packoff bushing is the second preventive seal.
The secondary seal performs essentially the same function as the
primary seal of the casing head. Aramco has two wellhead
manufacturers supplying wellhead material. Each system has its own
secondary seals. Cooper (makes Cameron & McEvoy) supplies an Xbushing and Vetco Gray supplies an AK bushing. The AK bushing is
redesigned from the original CWC bushing so that regardless of which
spool is installed, the casing stub (Figure 2E-10) is cut to the same
height for the Vetco Gray spool as for the Cameron or McEvoy spool.
RING GASKET
RING GASKET
GROOVE
CASING HANGER
TEST PORT
INJECTION PORT
RING GASKET
GROOVE
SECONDARY SEAL
Figure 2E-6: The Casing Spool with Secondary Seal
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A ring gasket, made of a special metal alloy, is placed between all
flanged connections. The ring gasket fits into specially machined
grooves in the upper flange of the casing head and the lower flange of
the intermediate casing head. The gasket serves to contain pressures
in the wellhead in the event that either or both the primary and
secondary seals should fail. Each ring gasket is designed to withstand
a maximum pressure that the tubulars will be exposed to during the
life of the well. A further explanation of ring gaskets and pressure
ratings is discussed later. The side outlets on the casing spool are
used to check and relieve pressure inside the casing - casing annulus.
1.4.3
Tubing Spool
The tubing head suspends the production tubing and seals off the
tubing casing annulus (Figure 2E-7). Like the casing spool, the tubing
head includes a secondary seal and side outlets. The top flange of the
tubing head is used to connect blowout preventers during
conventional workover operations; that is, workovers that require
pulling the tubing. The lower flange connects to the top flange of the
section below it. A ring gasket is also used between the flanged
connections.
POLISHED NIPPLE
TUBING HEAD
TIE DOWN PIN
TUBING
HANGER
PRODUCTION
CASING
TUBING
Figure 2E-7: The Tubing Head
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The tubing hanger assembly performs essentially the same function
as the casing hanger; i.e., it suspends the tubing and seals off the
tubing - casing annulus. The full weight of the tubing string is virtually
supported by the tubing hanger. The tubing hanger is usually
equipped with a polish nipple to seal inside the tubing bonnet (Figure
2E-8). However, sometimes the tubing hanger is equipped with an
extended neck that is an integral part of the hanger. The polish nipple
is a separate item threaded into the tubing hanger.
The side outlets of the tubing head can be accessed to; (1) inject a
fluid into the tubing casing annulus, as in a gas lift operation; (2)
monitor annulus pressure; (3) test annulus for leaks; (4) relieve
pressure in the tubing - casing annulus; and (5) supply an exit for the
sub-surface safety valve control line.
The tie-down pins serve to secure the tubing hanger in the spool. If
the tubing is attached to a downhole packer, there is a possibility that
the tubing will expand under flowing conditions causing a force large
enough to break the seal between the hanger and the spool. For a
more detailed view of a tubing hanger refer to Figure 2E-12.
1.4.4
Tubing Bonnet (Tubing Head Adapters):
The tubing bonnet (Figure 2E-8) is the equipment that allows the tree
to be attached to the wellhead. It has a sealing mechanism, extended
neck or polish nipple, which keeps wellbore fluid from coming in
contact with the tubing head or the tubing hanger. The tubing bonnet
configuration is usually equipped with studs on top and a flange on
the bottom although it can be supplied flange by flange or stud by
stud. Ring gaskets are installed on top and on the bottom.
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TUBING BONNET
TUBING HEAD
TUBING
HANGER
WITH POLISH NIPPLE
PRODUCTION
CASING
TUBING
Figure 2E-8: Tubing Bonnet and Polish Nipple
1.4.5
Tree Assemblies:
The tree is a system of gate valves that regulates the flow of fluids
from the well, opens or shuts production from the well, and provides
entry into the well for servicing. The tree is connected to the
uppermost flange of the wellhead that, typically, is the upper tubing
head flange.
A typical tree includes several gate valves, a flow tee and a tubing
bonnet. This system routes well production into the flow line. The flow
line then conducts the fluids from the tree to surface treating facilities.
The gate valves are technically the same but are referred to by
different names. They include the master valve, the wing valve and
the crown valve. Each valve can have a backup and the valves can
operate manually or hydraulically. Each valve has only two operating
positions; fully open or fully closed. They are used to open or shut the
flow from the well.
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WELLHEADS
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2.0
SAUDI ARAMCO STANDARD WELLHEAD COMPONENTS
Saudi Aramco currently purchases wellhead components from four manufacturers.
These are Cameron, FMC, Gray and WGI.
These components are
interchangeable as wellhead sections, that is you may use a Cameron Casing
Head, then install a FMC Casing Spool, then a Gray Tubing Spool with a WGI
Tubing Bonnet. You cannot, however interchange casing or tubing hangers. A
Cameron head must have a Cameron hanger, a FMC head must have a FMC
hanger etc.
Saudi Aramco stocks all of the major components to drill, complete and workover
our wells. The following sections are a listing of the major components by size,
pressure rating and service type. Refer to the Drilling and Workover Materials list
for current Stock Numbers.
2.1
2.2
2.3
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Casing Heads (Landing Bases):
Top Flange
Bottom
13” 3M
13-5/8” Socket Weld
13” 5M
13-5/8” Socket Weld
20” 3M
18-5/8” Socket Weld
26” 3M
24” Socket Weld
26” 3M
26” Socket Weld
Casing Spools:
Top Flange
11” 3M
11” 5M
11” 5M
11” 10M
13” 3M
13” 3M
13” 5M
13” 10M
20” 3M
Bottom Flange
13” 3M
13” 3M
13” 5M
13” 5M
13” 3M
20” 3M
13” 5M
16” 5M
26” 3M
Casing Hanger
9-5/8” Automatic
9-5/8” Automatic
13-5/8” Automatic
18-5/8” Automatic
18-5/8” Automatic
Packoff
9-5/8”
9-5/8”
9-5/8”
9-5/8”
9-5/8”
13-3/8”
9-5/8”
13-3/8”
18-5/8”
Casing Hanger
7” Automatic
7” Automatic
7” Automatic
7” Automatic
7” Automatic
9-5/8” Automatic
7” Automatic
9-5/8” Automatic
13-3/8” Automatic
Tubing Spools:
Top Flange
Bottom Flange
Packoff
Outlet Size
11” 3M
11” 3M
11” 3M
11” 3M
11” 5M
11” 10M
11” 3M
11” 3M
13” 3M
13” 3M
13” 5M
13” 10M
7”
7”
9-5/8”
9-5/8”
9-5/8”
9-5/8” Metal Seal
2” X 2”
6” X 2”
2” X 2”
6” X 2”
2” X 2”
3” X 3”
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CHAPTER 2
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2.4
2.5
2.6
2.7
2.8
Tubing Hangers (Extended Neck) for Oil Service:
Bowl Size
Tubing Size
Thread
11”
2-3/8”
EUE
11”
2-7/8”
EUE
11”
3-1/2”
EUE
11”
4-1/2”
New Vam
11”
7”
New Vam
BPV Prep
2” Type ‘H’
2-1/2” Type ‘H’
3” Type ‘H’
4” Type ‘H’
7” Type ‘J’
Tubing Hangers (Extended Neck) for Gas Service:
Bowl Size
Tubing Size
Thread
11”
3-1/2”
PH-6
11”
4-1/2”
New Vam
11”
5-1/2”
New Vam
11”
7”
New Vam
Tubing Bonnets for Oil Service:
Studded Top
Bottom Flange
Flange
2” 3M
11” 3M
3” 3M
11” 3M
4” 3M
11” 3M
7” 3M
11” 3M
7” 5M
11” 5M
BPV Prep
3” Type ‘H’
4” Type ‘H’
5” Type ‘H’
7” Type ‘K’
Seal Neck Diameter
(inches)
5-1/2
5-1/2
5-1/2
7-5/8
7-5/8
Tubing Bonnets for Gas Service (with Master Valve):
Valve Bore
Studded Top Flange
4-1/2”
7” 10M
5-1/2”
7” 10M
7”nom. (6-3/8” act.)
7” 10M
Bottom Flange
11” 10M
11” 10M
11” 10M
Tubing Bonnets for Special Service (Electric Penetrators):
Studded Top Flange
7” 3M
3” 3M
4” 3M
Bottom Flange
20” 3M
11” 3M
11” 3M
Penetrator
Genco Model 1
Genco Model 1
Genco Model 1
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2.9
DSDPO Flanges:
Casing Size
4-1/2”
4-1/2”
5”
5”
7”
7”
7”
7”
7”
9-5/8”
9-5/8”
9-5/8”
9-5/8”
9-5/8”
13-3/8”
13-3/8”
13-3/8”
18-5/8”
Studded Bottom
Flange
11” 3M
13” 3M
11” 3M
13” 3M
11” 3M
11” 5M
11” 5M
11” 10M
13” 3M
13” 3M
13” 3M
13” 5M
13” 5M
13” 10M
13” 3M
13”5M
16” 5M
26” 3M
Studded Top
Flange
11” 3M
13” 3M
11” 3M
13” 3M
11” 3M
11” 5M
11” 10M
11” 10M
13” 3M
13” 3M
13” 5M
13” 5M
13” 10M
13” 10M
20” 3M
20” 3M
20” 3M
26” 3M
2.10 Trees:
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Size
Working Pressure
Service
2”
3”
4”
7”
4”
7”
7”
3”
4”
Size
5”
7”
10”
3M
3M
3M
3M
3M
3M
5M
10M
10M
Working Pressure
10M
10M
3M
Onshore
Onshore
Onshore
Onshore
Offshore
Offshore
Offshore
Khuff
Block Khuff
Service
Block Khuff
Block Khuff
Power Water Injection
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
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2.11 Loose Valves:
Size
2”
3”
4”
7”
2”
3”
4”
3”
4”
7”
2”
3”
4”
7”
2”
Working Pressure
3M
3M
3M
3M
5M
5M
5M
10M
10M
10M
3M
3M
3M
3M
10M
2.12 Valve Bores and End-To-End Dimensions
Nominal Size (inches)
Valve Bore (inches)
3,000 psi Working Pressure
2-1/16
2-9/16
3-1/8
4-1/16
5-1/8
7-1/16
Type
Manual
Manual
Manual
Manual
Manual
Manual
Manual
Manual
Manual
Manual
Hydraulic Actuator
Hydraulic Actuator
Hydraulic Actuator
Hydraulic Actuator
Hydraulic Actuator
End-to-End (inches)
2.06
2.56
3.12
4.12
5.12
6.38
14.62
16.62
17.12
20.12
24.12
24.12
2.06
2.56
3.12
4.12
5.12
6.38
14.62
16.62
18.62
21.62
28.62
29.00
2.06
2.56
3.12
4.06
5.12
6.38
20.50
22.25
24.38
26.38
29.00
35.00
5,000 psi Working Pressure
2-1/16
2-9/16
3-1/8
4-1/16
5-1/8
7-1/16
10,000 psi Working Pressure
2-1/16
2-9/16
3-1/8
4-1/16
5-1/8
7-1/16
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3.0
INSTALLATION AND TESTING PROCEDURES:
3.1
Primary and Secondary Seals:
We mentioned in section 1 that one of the purposes of wellhead is to support
the tubular strings. Another purpose of wellhead is to seal and isolate the
tubular strings from one another. This is done by installing a minimum of two
seals on each string of pipe. These are the Primary Seal and the Secondary
Seal. The Primary Seal is on the casing or tubing hanger. The secondary
seal is in the bottom of either the next spool section, the tubing bonnet or the
DSDPO, if one is used.
We use three types of secondary seals at Saudi Aramco. First the injectable
seal. This is a seal that is activated by injecting plastic packing behind it as
we do in X and AK bushings. The second type is the interference fit seal.
This type is activated by simply bolting up the flange, the seal energizes
automatically. The third type is the metal-to-metal seal. The pack-offs that
use this seal have sized metal rings that must be installed by a Service Hand.
The metal-to-metal seal is also used as the tubing hanger primary and
secondary seal on 10,000 psi (Khuff) tubing hangers. The table below lists all
three types and where they are used:
Interference Seals
Injectable Seals
Sized Metal to Metal
Metal-to Metal
3.2
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Bottom of casing and tubing spools to
seal on 9-5/8” and smaller pipe. All 3,000
psi and 5,000 psi tubing bonnets.
Bottom of spools to seal on 13-3/8” and
larger pipe. All Double Studded Double
Pack-off flanges (DSDPO)
Bottom of 10,000 psi (Khuff) tubing spools
Tubing hanger primary and secondary
seals for 10,000 psi (Khuff) equipment
Casing Heads:
The casing head is installed on the conductor casing by slipping the socket in
the bottom of the head over the casing and welding inside and outside. The
assembly is then pressure tested through a ½” NPT test port between the
welds, the O.D. of the casing and the I.D. of the socket. This area is marked
in red in Figure 2E-9. A detailed installation procedure, WRS-602, issued by
DMD is contained in the Appendix, section D of this manual. Test pressure is
determined by taking 80% of the rated collapse of the casing or the working
pressure of the top flange, whichever is less. Maximum test pressures are
tabulated below.
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
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June 2006
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WELLHEADS
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Figure 2E-9: Installed Casing Head
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WELLHEADS
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Maximum pressures for testing Casing Heads
3.3
Casing Size
Casing Grade
13-3/8
13-3/8
13-3/8
13-3/8
13-3/8
13-3/8
18-5/8
18-5/8
24
24
26
26
J-55
J-55
L-80
NT-95-HS
S-95
NT-95-HS
K-55
K-55
GR-B
X-42
X-42
X-42
Casing
Weight
61#
68#
72#
72#
72#
86#
87.5#
115#
97#
176#
105#
136#
Rated Collapse
1,540
1,950
2,670
2,820
2,820
6,240
630
1,140
Maximum Test
Pressure
1,200
1,550
2,100
2,250
2,250
5,000
500
900
1,080
850
Slip Type Casing Hangers
At Saudi Aramco we commonly use the slip type casing hanger. There are
two styles of these hangers the Automatic and the Manual. Automatic and
Manual refer to the way that the seal on the hanger is activated. The
Automatic seal is energized by setting casing weight on the hanger, it usually
requires around 50,000 lbs to effect a seal. The Manual hanger will not seal
until cap screws in the top of the hanger have been tightened.
All of the casing hangers we use may be installed from the drill floor through
a BOP stack or the stack may be picked up, secured, and the hanger
installed from underneath. There are some considerations when installing a
hanger through the BOP stack:
•
•
•
•
The casing must be well centered in the stack.
There can be no casing couplings in the stack. The hangers will not go
over them.
The hanger should be lowered through the stack with soft line.
It is usually not recommended that any hanger larger than 13-5/8” X 7”
be set through the stack. This is because of the weight of the hanger.
We currently use four manufacturer’s casing hangers these are Cameron,
FMC, Gray and WGI. You may not mix hangers and spools. If you have a
Cameron head or spool you must use a Cameron hanger, a Gray spool must
use a Gray hanger etc. This is because the profile on the outside of the
hanger must match the profile of the head. These profiles are propriety to the
manufacturer and are never interchangeable.
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All of our casing hangers basically operate the same way. First lay boards or
metal straps across the opening; either the rotary table or the top flange of
the casing spool as appropriate. The hanger splits open to allow you to wrap
it around the casing. Be careful when doing this so as not to tear the seal
element. Set the hanger on the boards or straps so that it is level. Remove
the shipping retaining pins or screws that hold the slip segments in place.
Coat the casing and the outside of the hanger with light oil. Ensure that the
side outlet valve on the casing head or spool is open and that all fluids have
drained to the level of the outlet. Remove the boards and lower, do not drop,
the hanger into the bowl. Only after the hanger is in the proper position, top
of the hanger 1 to 2 inches below the top flange, can casing weight be set on
the slips. Pick up the BOP stack and make the rough cut six to eight inches
above where the final cutoff will be. Nipple down the BOP. Installing the next
wellhead section is discussed in Chapter 2E, section 3.4 Casing and Tubing
Spools below. Figure 2E-10 shows a Casing Head with the hanger installed.
3.4
Casing and Tubing Spools
The tubing spool is identical to the casing spool except at Saudi Aramco we
have lock screws installed in the top flange of the tubing spool. These lock
screws serve two main purposes. First they help energize the primary seal
especially when there is a very light tubing string. Second they act as a
retention device for the tubing hanger. The retention device would be
necessary if, for example, the tubing string parted. Since the tubing hanger
is locked in place you could still set a back-pressure valve and retain control
of the well.
Figure 2E-10: Casing Head with Hanger Installed
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WELLHEADS
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Before installing the spool, lay it on its side and wash the inside of the spool
thoroughly, removing all grease and dirt. Visually check the secondary seals
in the bottom of the spool for damage or cuts, replace the seal if any are
found. Next, measure from the face of the bottom flange to the shoulder just
above the secondary seal. This is the final cut-off height for the casing stub.
Saudi Aramco’s standard cut-off is 4-1/2 inches, but this should always be
verified before making the final cut. After the final cut is made bevel both the
inside and outside of the casing stub. Beveling helps the spool slide on more
easily and ensures that there are no burrs or lips on the I.D. that would cause
a tool to hang up. Rig pick-up lines to the top flange of the spool so that it
hangs level, suspend it over the casing stub. Clean ring grooves and install a
new ring gasket. Coat the casing stub and the secondary seal with light oil.
Install two studs under each valve orient the spool as required and lower the
spool slowly over the casing stub. Fill the bowl above the casing hanger with
hydraulic oil. Take care that the stub does not hang-up and cut the
secondary seal. Install the rest of the studs and nuts and tighten the flange
using normal oilfield practice.
Figure 2E-11: Casing Spool Nippled up on Casing Head
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After the flange is tightened, activate the secondary seals (see section 3.1
above). Now hook up the test pump to the test port and apply test pressure
using hydraulic oil. Test pressure is generally 80% of the rated collapse
pressure of the casing or the working pressure of the flange, whichever is
less. Hold the test pressure for 15 minutes then bleed all pressure to zero.
Install the blind plug in the test port. Figure 2E-11 is a depiction of a casing
spool installed on a casing head the area in red indicates the void being
pressure tested.
3.5
Tubing Hangers
All of the tubing hangers used by Saudi Aramco (Figure 2E-12) are mandrel
type hangers with extended necks. They are shipped to the field with a pup
joint installed to ease make-up onto the tubing string. After the tubing string
has been spaced-out pick up the tubing hanger in install on the top joint of the
string. Take care not to damage the O.D. of either the hanger or the
extended neck as deep scratches or gouges in this area can prevent the
hanger from sealing. Check that all of the lock screws in the top flange of the
tubing spool are fully retracted and do not extend into the head. Install a
landing joint in the top of the hanger then slack-off on the tubing string and
land the hanger in the bowl. Tighten the lock screws, remove the handling
joint and install the Back Pressure Valve. Now you may nipple down the
BOP stack and you are ready to install the tubing bonnet and tree.
Figure 2E-12: Tubing Spool with Tubing Hanger Installed
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3.6
Tubing Bonnet
Before installing the tubing bonnet turn it on its side and wash thoroughly,
removing all grease and dirt. Visually inspect the bore of the bonnet and the
seals for damage. Rig slings to the bonnet so that it picks up level, suspend
it over the extended neck of the tubing hanger. Clean all ring grooves and
install new ring gasket. Coat the extended neck of the hanger and the seals
in the bonnet with light oil. Fill the bowl on top of the hanger with hydraulic
oil. Install four studs 90o from each other to help line up the bonnet. Turn the
bonnet to the required orientation and lower over extended neck. Install all
studs and nuts and tighten using good oil field practice. Test the connection
using hydraulic oil for 3,000 psi and 5,000 psi equipment and nitrogen for
10,000 psi completions. NOTE: Gray has a portable nitrogen test unit that
should be used for these tests. Hold test pressure for 15 minutes then bleed
all pressure to zero. Figure 2E-13 shows the test area of a bonnet and tubing
hanger.
Figure 2E-13: Tubing Spool with Bonnet Installed
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WELLHEADS
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3.7
Trees
Rig slings to the tree (Figure 2E-14) so that it will pick up level. Clean the
ring grooves and install a new ring gasket. Orient the tree as required and
land. Tighten studs using good oil field practice before removing the slings.
Rig down the slings. Retrieve the Back Pressure Valve and install a two way
check valve, or test plug. Rig up pump to the wing valve and with all valves
open test to the working pressure of the tree. Bleed pressure to zero, close
master valve and pressure up to working pressure. With master valve closed
test each valve in turn. After tree has been tested pull the two way check
valve, or test plug and install back pressure valve, if required by the Drilling
Program. Close all valves to secure well.
Figure 2E-14: Tree, Bonnet and BPV Installed
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E
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WELLHEADS
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4.0
BACK-PRESSURE VALVES AND TUBING TEST PLUGS:
Saudi Aramco uses three types of Back-Pressure valves on new wells. These are
the type ‘H’ the type ‘K’ and the type ‘J’.
4.1
Back Pressure Valves for Oil Well Service:
Size
2-3/8”
2-7/8”
3-1/2”
4-1/2”
7”
Profile
Type ‘H’
Type ‘H’
Type ‘H’
Type ‘H’
Type ‘J’
Note: Please be reminded that the old style hangers had the Gray Type ‘K’
profile or the type ‘H’ profile depending on which company manufactured the
hanger. The well file must be checked to determine which BPV should be
installed during workover operations. All drilling rig Foremen should check 23/8” through 4-1/2” hangers prior to installation, only those with Type ‘H’
profiles should be used.
4.2
Back Pressure Valves for Khuff Gas Service:
All new hangers for Khuff service have the following profiles:
Size
3-1/2”
4-1/2”
5-1/2”
7”
Profile
Gray Type ‘K’
Type ‘H’
Type ‘H’
Gray Type ‘K’
Note: Please be reminded that the older hangers had the Gray Type ‘K’
profile. The well file must be checked to determine which BPV should be
installed during workover operations. All rig Foremen should check 3-1/2”
and 4-1/2” hangers prior to installation, only those with Type ‘H’ profiles
should be installed.
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DRILLING MANUAL
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CHAPTER 2
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E
June 2006
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WELLHEADS
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4.3
Type ‘H’ Back-Pressure and Two Way Check Valves
The threaded style Back-Pressure Valve (BPV) and Two-Way Check Valves
(TWCV) combine internal running threads, external setting threads and an
internal stinger. The type ‘H’ BPV is designed to hold pressure from the
wellbore, or below, only. Cameron rates these BPV’s at 20,000 psi. They
have an internal, female, right hand running thread that mates with the
running, or retrieving tool, and an external, male, left-hand ACME setting
thread that mates with the tubing hanger.
Please refer to Figure 2E-15, below. The internal plunger consists of a valve
and spring assembly that will seal and hold pressure from below. When
offset this plunger, see Figure 2E-16, allows pressure to by-pass and
equalize above and below the BPV. This plunger also allows fluid to be
pumped through the BPV in the event that it is necessary to pump kill fluid
into the well with the plug installed. The external seal is a lip type seal on the
O.D. of the BPV. This seal is energized when the plug is rotated into the
mating profile in the tubing hanger. The type ‘H’ BPV should not be overtightened. Over-tightening this type of plug will not help it seal, but can make
it hard to remove.
Figure 2E-15: BPV, Plunger Closed
Figure 2E-16: BPV, Plunger Open
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WELLHEADS
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The type ‘H’ TWCV is designed to plug the tubing in order to test the tree or
the BOPE. It will also seal pressure from below. Refer to Figures 2E-17 and
2E-18 below. The plug uses a two-way plunger that will hold tubing pressure
from below or moves down and seals test pressure from above. The tubing
pressure can be bled down by inserting the retrieving/running tool, which will
offset the plunger and allow pressure to by-pass. This plug is not to be used
for nipple-up or nipple-down operations! When performing these operations
the BPV shall be installed. When nipple down, nipple up, operations are
complete the BPV shall be removed and the TWCV installed and the
equipment can be tested.
Figure 2E-17: TWCV; Pressure from Below
Figure 2E-18: TWCV; Pressure from above
There are two tools available to install and remove these plugs. Figure 2E-19
shows a running/retrieving tool and Figure 2E-20 shows a running tool. The
running/retrieving tool can be used to install and remove the plugs. The
running tool can only be used to install the plugs and should never be used to
remove any plug.
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CHAPTER 2
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DRILLING MANUAL
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DRILLING PRACTICES
E
WELLHEADS
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Figure 2E-19: Retrieving/Running Tool
4.4
Figure 2E-20: Running Tool
Running Procedures for Type ‘H’ Plugs
Before Starting:
•
•
•
•
•
Thoroughly clean the plug with solvent.
Inspect the lip seal, replace if damaged or cut.
Inspect the running threads and setting threads for damage.
Inspect the plunger and spring to ensure that they are not damaged.
If possible set the plug in the hanger (before the hanger is installed).
4.4.1
Method 1: Installation using the Retrieving/Running Tool (Figure
2E-19)
A)
Measure from the lock-screws on the top flange of the tubing
spool to the top of the tree connection (if installing through a
tree), or to the drill floor (if installing through BOPE). To this
dimension add 18 to 36 inches. This is the length of polished
rod required.
B) Assemble the polish rod and attach the Retrieving/Running tool
to the bottom piece.
C) Thread the plug onto the Retrieving/Running tool (8 to 8-1/2
rounds) and tighten with two 18” pipe wrenches. The connection
should be tight enough that when threading the plug into the
hanger it will not break out before it is seated.
D) Coat the plug threads and lip seal with an even application of
never-seize.
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E)
Lower the assembly through the tree, or BOP, and stab plug into
the hanger.
F) Turn to the right one turn to align the threads.
G) Turn to the left 4 to 6 rounds until the rod becomes hard to turn.
This is the break-over point and indicates that the plug has
seated.
H) With an 18” pipe wrench, continue to rotate the rod to the left until
they become easy to turn. This indicates that the
Running/Retrieving tool is now backing out of the plug
I) Continue to turn 8 to 10 rounds to completely disengage the
Running/Retrieving tool.
J) Remove the rod assembly from the tree, or BOP.
4.4.2
Method 2: Installation using the Running Tool (Figure 2E-20)
A)
B)
C)
D)
E)
F)
G)
H)
I)
J)
K)
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Measure from the lock-screws on the top flange of the tubing
spool to the top of the tree connection (if installing through a
tree), or to the drill floor (if installing through BOPE). To this
dimension add 18 to 36 inches. This is the length of polished
rod required.
Assemble the polish rod and attach the Running tool to the
bottom piece.
Thread the plug onto the Running tool and make it up until it
bottoms out, no torque is required.
Coat the plug threads and lip seal with an even application of
never-seize.
Lower the assembly through the tree, or BOP, and stab plug into
the hanger.
Turn to the right one turn to align the threads. Watch for the rod
to drop about ½ inch; this indicates that the torque pin has
engaged the slot on the top of the plug.
Turn to the left 4 to 6 rounds until the rod becomes hard to turn.
This is the break-over point and indicates that the plug has
seated.
With an 18” pipe wrench, continue to rotate the rods to the left
until a maximum of 50 ft lbs. has been applied. Under no
circumstances should the plug be over-tightened.
Pick up the rod about ½ inch and continue to turn to the left to
thread the running tool out of the plug.
Continue to turn 8 to 10 rounds to completely disengage the
Running tool.
Remove the rod assembly from the tree, or BOP.
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
F
June 2006
DRILLING PRACTICES
LOST CIRCULATION
___________________________________________________________________________________________________________________________
LOST CIRCULATION
1.0
INTRODUCTION
2.0
CONVENTIONAL LOSS CIRCULATION MATERIAL
2.1
2.2
3.0
ACID SOLUBLE GROUND MARBLE
3.1
3.2
4.0
Characteristics
Procedures
CEMENT PLUG
8.1
8.2
9.0
Characteristics
Slurry Volume Calculations
Pilot Testing
Pumping, Displacement Rates and Equipment
Procedures
THIXOTROPIC CEMENT
7.1
7.2
8.0
Types of Polymer Plugs
Flo-Chek
Temblok-100
High Temperature Blocking Gel
Protectozone
BARITE PLUG
6.1
6.2
6.3
6.4
6.5
7.0
Characteristics
Procedures
POLYMER PLUG
5.1
5.2
5.3
5.4
5.5
6.0
Characteristics
3.1.1 Selection of CaCO3 Particle Size Basis
3.1.2 Typical CaCO3 Pill Formulation
3.1.3 Average Properties of CaCO3 Carrier Fluid
Recommended Procedures
GUNK PLUG
4.1
4.2
5.0
Characteristics
Procedures
Characteristics and Precautions
Procedures
FOAM CEMENT
9.1
9.2
Characteristics
Procedures
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
F
June 2006
DRILLING PRACTICES
LOST CIRCULATION
___________________________________________________________________________________________________________________________
LOST CIRCULATION
1.0
INTRODUCTION
1.1
Loss of circulation occurs when the formation drilled is extremely permeable
and a pressure differential is applied toward the formation. The mud loss rate
dramatically increases by the excessive overbalance pressures created by
the hydrostatic head of the column of mud in the hole. In some cases,
decreasing the differential pressure by reducing the fluid density and pumping
rate or pressure will stop fluid losses and regain circulation. However, the
most effective method for combating lost circulation is to reduce the
permeability of the borehole wall by introducing properly sized bridging
material, commonly known as loss circulation material (LCM) into the rock
pores with a high viscosity pills. Bridging particles contained in the mud will
not seal the zone if they are smaller than the formation pores.
Potential loss of circulation zones usually encountered in Saudi Aramco’s
fields include
Pre-Neogene Unconformity (PNU)
Umm Er Redhuma (UER)
Wasia Formation
Shuaiba
Arab-D Reservoir
Hanifa Reservoir
Lower Fadhili Resrevoir
Haurania Zone
Below the base of the Jilh dolomite
1.2
Major losses
Major losses
Major losses
Major losses
Loss circulation material (LCM) is normally added to the circulating drilling
mud, or in a high viscosity pill to be spotted across the lost circulation zone.
The LCM includes, but is not limited to
A)
Conventional bridging agents;
Fibrous Material ............................................Cedar Fiber
Flake Material ...............................................Mica coarse and fine
Cellophane
Granular Material ..........................................Walnut shells
Cotton seed hulls
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B)
Acid soluble sized Calcium Carbonate (CaCO3);
Ground marble fine .......................................(10 microns)
Ground marble medium ................................(150 microns)
Ground marble coarse ..................................(600 microns)
Marble chips .................................................(2000 microns)
Note: Acid soluble CaCO3 is also a granular material
C)
Reinforcing plugs, cement and others;
Gunk Plug
Barite Plug
Polymer Plug
Cement Plug
Foam Cement
Thixotropic Cement
D)
1.3
Approximate Size of
Opening Sealed (Inches)
Severity of Loss
0.125 – 0.250
Seepage to Complete
0.250 – 12.00
12.00 up
Severe Complete
Losses
Complete (cavernous)
Complete (cavernous)
Materials and Size
ranges
•
•
•
•
•
•
•
•
Medium to Coarse Granular
Fibrous Material.
Fine to Coarse Flakes
Marble Chips
Barite Plug
Cement Plug
Gunk or Polymer Plug
Drill “Blind”
Drilling may continue without full returns through PNU and UER, using water
and gel sweep to ensure hole cleaning. If circulation is lost while drilling
through the Wasia Aquifer with mud, circulation must be regained (do not
switch over to water and drill ahead) by using one or a combination of the
following techniques:
A)
B)
C)
D)
E)
2 of 26
The size of the bridging agents are very important, providing
consideration is given to the type of loss zone and the severity. The
following list provides a general guide for LCM applications:
Conventional LCM pill.
Cement Plug. With open-ended drill pipe +50’ above the LC zone, spot
118 pcf Class-G neat cement; plug length not to exceed 500’.
Gunk Plug.
Thixotropic Cement.
Foam Cement. Only to be used when all above techniques have failed
to regain circulation.
SAUDI ARAMCO
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
F
DRILLING MANUAL
June 2006
DRILLING PRACTICES
LOST CIRCULATION
___________________________________________________________________________________________________________________________
1.4
If loss of circulation is anticipated while drilling a potential hydrocarbonbearing zone, run large jet nozzles and BHA without mud motor.
1.4.1
If case loss of circulation is encountered, attempt to regain with at
least two consecutive LCM pills:
A)
B)
C)
1.4.2
If unable to regain circulation, continue drilling with mud cap to the
next casing point.
A)
2.0
Sized CaCO3 LCM pills. Do not use any other damaging nonacid soluble materials in this pill.
Polymer plugs such as Flo-Chek, Zone-lock, FlexPlug and
others. Detailed mixing and pumping procedures for this type of
plug should be provided by the Service Company in order to
tailor the pill to the specific well conditions.
Cement or gunk plugs should not be considered unless severe
loss of circulation is encountered just below the shoe and could
not be regained utilizing Sized CaCO3. In this case, cement
plugs or gunk plugs will have to be utilized to regain circulation
to enable drilling to continue.
The only exception to this policy applies when experiencing
complete loss of circulation in the Arab-D reservoir while drilling
Khuff/Pre-Khuff well.
In these wells, circulation must be
regained before proceeding to the casing point (base of Jilh
Dolomite).
CONVENTIONAL LOSS CIRCULATION MATERIAL
2.1
2.2
Characteristics
2.1.1
Materials used generally include Mica Course, Mica Fine, Cotton
Seed Hulls, Basco Cedar and Walnut shells.
2.1.2
Prepare LCM pill by isolating the desired volume from the active mud
system and mixing 30 to 150 lbs./bbl of LCM. Any combination of the
above LCM can be included in this mixture.
Procedures
A)
Establish the approximate point of the loss, type of formation, mud level
in the hole and rate of loss.
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CHAPTER 2
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June 2006
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3.0
B)
Run in hole with open-ended drill pipe 25 to 50’ above the lost
circulation zone.
C)
Pump LCM pill down drill pipe until it clears the bottom.
D)
Pick up drill pipe 2 to 4 stands and wait for LCM to settle.
E)
Establish circulation to determine extent of healing and if a second LCM
pill is needed.
ACID SOLUBLE GROUND MARBLE
3.1
Characteristics
3.1.1
Various sizes of ground marble are used to stop lost circulation during
the drilling operations. Selection of the proper particle size distribution
is dependent on the nature of the formation and the severity of the lost
circulation. To seal off a rock with large diameter pores, particles
larger than the pore size will be more effective than smaller ones.
Any particle smaller than one third the pore size will pass through the
pore pattern and will not effective in stopping the losses.
Note:
The sealing characteristic of the lost circulation pill is governed
not by the concentration of particles but by the shape and size
distribution of the particles carried in the pill. Properly sized
bridging material must be selected to block the formation pores
effectively at the wellbore face. The particles should have a
broad size range, and 20 - 50 percent of the particles should be
at least one-third the average formation pore size to establish the
desired bridging mechanism. The reservoir engineer or geologist
should be consulted for the proper particle size selection
required for a non-penetrating fluid. The lost circulation pills
must be spotted at the pay-zone by pumping the pill down hole
at a rate that will jam the particles quickly at the entrance of the
formation flow channels. Slow pumping may allow the bridging
particles to seep into the Arab-D vugular and/or fractured rocks.
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CHAPTER 2
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June 2006
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LOST CIRCULATION
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3.1.2
A typical example of a sized CaCO3 pill formulation for Arab-D
payzone is as follows:
Order of addition
for one barrel
•
•
•
•
•
•
•
•
0.01 - 0.02
0.50 - 1.00
1.00 - 2.00
2.00 - 4.00
0.50 - 1.00
30 - 80
100 - 120
Fresh water
Defoamer
Suspending polymer (XC-Polymer)
Primary viscosifier (HEC)
Filtrate control polymer (starch)
Lime or MgO
Ground marble medium (150 microns)
Ground marble coarse (600 microns)
gal
lb
lb
lb
lb
lb
lb
Note:
3.1.3
1.
Add polymers slowly through the hopper to avoid the formation
of lumps or fish eyes and achieve high viscosity and gel
strength.
2.
The concentration and the size distribution of the ground
marble can be tailored or varied according to the severity of
losses. Medium and Coarse can be pumped through the bit
nozzles.
3.
When attempting to stop severe lost circulation with large size
(2000 micron) Marble Chips, use open-ended drill pipe. Due
to the large size of the Marble Chips, the bit nozzles will be
plugged.
Average properties of the carrier fluid prior to adding the CaCO3
should be in the following ranges:
♦
♦
♦
♦
♦
3.2
Funnel Viscosity
PV
YP
Gels
pH
150 - 200 sec/qt
30 - 40 cp
2
40 - 50 lb/100 ft
2
12 - 18 lb/100 ft
10 - 11
Recommended Procedures
A)
Establish the approximate depth of the thief zone, type of formation
(porosity and permeability - is it “super k”?), height mud stands in the
hole and rate of losses.
B)
Run in hole with large size jet nozzles or open ended drill pipe to the top
or near the top of the lost circulation zone.
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CHAPTER 2
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4.0
C)
Pump the Marble chip or sized CaCO3 pill through the drill pipe at
normal rate and speed the pump as the pill clears the drill pipe.
D)
Pick up drill pipe 3 stands and wait on bridging particles or chips to
settle and a cake to build up.
E)
Circulate to determine if the lost circulation zone has been sealed. If full
circulation can be established, run in hole slowly to bottom and resume
normal drilling operation. If partial losses still exist, continue drilling for
a while to generate some drilled cuttings which in many cases have
helped as a sealing mechanism.
F)
Repeat the above procedure and modify the bridging particles size
distribution if required. Perhaps larger particles are needed or the
carrier fluid viscosity should be increased.
GUNK PLUG
4.1
6 of 26
Characteristics
4.1.1
Gunk Plug is bentonite-in-diesel slurry. When dry bentonite is mixed
into diesel oil, the bentonite will not yield and the slurry remains a
relatively thin fluid. This allows the slurry to be pumped to the bit with
relatively low pressure. When the slurry leaves the bit and becomes
exposed to water in the annulus, the bentonite will rapidly hydrate,
causing the slurry to become extremely viscous or gunk like. This
extremely viscous gunk will have high resistance to flow through the
rock pores or channels and in many situations it will provide a
complete seal.
4.1.2
Gunk Plugs will lose strength with time under downhole conditions
and should be followed by a cement plug to provide a permanent seal.
4.1.3
The slurry is jet mixed with a cement unit to 82 lbs./cu.ft. This
normally requires 300 pounds of bentonite per barrel of diesel.
Additions of Mica at (about 15 lbs/bbl) will increase the strength of the
plug, but is optional. The slurry volume to be pumped normally
ranges from 20 to 150 barrels, and is based on the rate of loss
circulation and amount of open hole.
4.1.4
Gunk Plugs may become commingled with water inside the drill string.
If this occurs, pump pressure will become excessive, resulting in a
plugged drill string. For this reason, sufficient diesel spacers are
required ahead and behind the slurry.
SAUDI ARAMCO
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
F
DRILLING MANUAL
June 2006
DRILLING PRACTICES
LOST CIRCULATION
___________________________________________________________________________________________________________________________
4.2
Procedures
A)
B)
5.0
Run with closed end drill pipe and mixing sub to 20 feet above loss
circulation zone. Rig up both the cementing unit and the rig pumps so
that either can be used to displace the slurry. A third pump should be
connected to the annulus.
Pump 10 to 20 barrels of diesel into the drill pipe for the spearhead
spacer. This step is critical to separate the slurry from the waterbased mud.
C)
Jet-mix the slurry to 82 pcf. The slurry can be batch mixed or pumped
on the run.
D)
Tail in with a 10 to 20 barrels diesel spacer.
E)
Displace the slurry at a rate of 3 to 5 barrels per minute with mud.
F)
Begin pumping water-based mud down the annulus at a rate of 1.0 bbl
per minute as soon as the slurry reaches end of the drill pipe.
POLYMER PLUG
Polymer plugs are commonly used for temporarily or permanently healing of loss
circulation. The following are polymers that are available through the in-Kingdom
Service Companies. It is important to emphasize the need to (a) tailor the plug
design for the well conditions, (b) laboratory test the plug to fine-tune the polymer
additive concentrations, and (c) ensure satisfactory polymer plug performance.
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DRILLING MANUAL
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CHAPTER 2
SECTION
F
June 2006
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LOST CIRCULATION
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5.1
Types of Polymer Plugs
Service Company
B.J. Services
Product Name
Remarks
High Temperature It is pumped as a low viscosity liquid
which turns to a rigid polymer plug
Blocking Agent
when subjected to heat, after a
controlled time delay. Can be broken
down with 15% HCl or water containing
oxidizers. Can be jetted out using
coiled tubing or drill pipe.
It is a solids-free solution with a very
Dowell-Schlumberger Permablok
low initial viscosity that can easily
penetrate formation matrix. It is then
activated by temperature to produce a
strong, coherent gel.
Zonelock S and
Zonelock SC
LCM D111
8 of 26
Note: the Maximum temperature that
the hardened gel can withstand is
356oF.
Zonelock S, a solution of liquid
extender D75 and water, forms a rigid
semi-permeable gel when in contact
with a heavy calcium or sodium brine.
Zonelock SC utilizes Zonelock S
followed by a spacer and then cement
slurry. When the slurry contacts the
gel resulting from the D75/calcium
chloride solution, the cement will set
very rapidly (less than 2 minutes). The
Zonelock SC forms a permanent seal
that can only be drilled out.
Extends the use of RFC (Regulated
Fill-Up Cement) to offshore platforms
or areas where solid additives is
impractical. It imparts thixotropic
properties, characteristic of RFC
slurries. D111 slurries do not expand
upon setting. D111 can be used with
any Portland cement and either fresh
or seawater.
Limitation
-Highly
sensitive to
diesel and low
pH
contamination
-On-site mixing
should only be
performed with
fresh water.
-Max. temp. for
D140 hardener
is 225oF.
- A spacer of
fresh water or
Trisodium
Phosphate
M8 must
always be
used between
the D75
solution and
cement
-Can only be
used with
limited
number of
additives.
-Dispersants &
fluid -loss
control
additives
destroy the
thixotropic
properties
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
F
June 2006
DRILLING PRACTICES
LOST CIRCULATION
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Service Company
Product Name
InstanSeal
Protectozone
Halliburton
Flo-Chek
Flex-Plug-W
Temblok-100
Remarks
An unstable inverted emulsion that flips
spontaneously to hard solid gel when
exposed to a pressure drop of 650 psi
or above across the bit nozzles.
A rigid aqueous gel with controlled
setting and breakdown times.
Note: Oilfield brine should not be used;
only use fresh water or prepared NaCl
brine..
A two-fluid system; lead slurry consists
of Flo-Chek Chemical A (Injectrol A) to
which may be added sand and TUF
Additive No. 2.
The Flo-Chek Chemical A is followed
by a fresh water spacer and a
predetermined amount of cement
slurry. The latter is used to obtain the
final and permanent squeeze.
Non-particulate material that reacts
with the drilling mud, resulting in a nonbrittle bridge at the opening of the loss
zone.
Note: Must not contact aqueous fluids
in the mixing equipment.
Long-life viscous gel which is affected
by temperature and pH.
225oF max BHST; above 225oF use
Temblok-90.
Limitation
180oF
maximum
allowable
BHST.
325oF Max.
allowable
BHST.
Injectrol is
highly alkaline.
200oF max
allowable
BHST.
Cannot use as
additive in a
cement slurry.
Easily removed
with acid.
Cannot be
used in CaCl2
brine.
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DRILLING MANUAL
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CHAPTER 2
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LOST CIRCULATION
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5.2
Flo-Chek: Typical Mixing and Pumping Procedures
A)
Run In Hole with open ended drill pipe to just above the loss circulation
zone. Pump rate should be maintained between 3 to 5 bpm.
B)
Pump 1000 gals (24 bbls) of 15% CaCl2 water. Add 62 lbs. of Calcium
Chloride to one barrel of water. Need 1488 lbs of CaCl2 to make 1000
gallons of 15% CaCl2 water.
C)
Pump 5 bbls of fresh water.
D)
Pump 500 gals (12 bbls) of Flo-Chek polymer.
E)
Pump 5 bbls of fresh water.
F)
Pump 50 sacks (10.2 bbls) of cement, mixed at 118 pcf, 5 gals/sack,
and 1.15 cu. ft./sack.
G)
Pump 5 bbls of fresh water.
H)
Pump 500 gals (12 bbls) of Flo-Chek polymer.
I)
Pump 5 bbls of fresh water.
J)
Pump 150 sacks (30.7 bbls) of cement mixed at 188 pcf, 5 gals/sack,
and 1.15 cu. ft./sack.
K)
Displace cement with drill water to the end of drill pipe.
L)
Pull out of hole with drill pipe.
Note:
10 of 26
The Flo-Chek and cement must be suitably separated from each
another by fresh water. It is advisable to pump CaCl2 with rig pumps
while the fresh water spacer, Flo-Chek and cement is mixed and
pumped by Halliburton. The Halliburton pumps must be isolated to
prevent intermixing of cement and Flo-Chek.
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
F
June 2006
DRILLING PRACTICES
LOST CIRCULATION
___________________________________________________________________________________________________________________________
5.3
Temblok–100: Typical Mixing and Pumping Procedures
A)
Run In Hole with open-ended drill pipe to circulate and condition the
hole.
B)
Ensure all equipment that will be used during the job is completely free
of acid or other contaminants that may affect the pH of the fluid. The
tanks, blenders and pumping equipment must be neutralized by
circulating a K-35 solution, which is made up of 100 pounds of K-35 per
1000 gallons of fresh water.
C)
Prepare all fluids into neutralized equipment as follows:
D)
1.
K-35 spacer (per1000 gallons), made up of
1000 gals of Fresh Water
100 lbs of K-35
2.
Temblok-100 (per 1000 gallons) made up of
1000 gallons of Fresh Water
6 lbs TB-41
40 lbs K-35
425 lbs WG-11
35 lbs WG-17
The Temblok-100 system should be prepared as follows:
1.
Mix the saturated salt water as outlined above.
2.
Add the proper amount of TB-41 to the saturated salt water and
mix for 10 minutes.
3.
Load into neutralized mixing tank the proper amount of fresh
water.
4.
Add the appropriate amount of K-35 based on lab tests, to the mix
water and circulate until dissolved. Check the pH to ensure it is
10.5 to 11. If it is less, add small amounts of K-35 until the correct
pH is achieved.
5.
Add the proper amount of WG-11 and circulate to mix all the gel,
try to avoid any air entrapment.
6.
Add the proper amount of WG-17 SLOWLY. The slurry will
become more viscous at this point. Slowly circulate the slurry until
ready to pump.
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Note: The slurry should not be mixed for more than 1-1/2 hours prior to
pumping as the fluid may become too viscous to pump.
E)
Pump the Temblok-100 system, spot and balance as follows:
1.
Pump K-35 spacer (usually 500 linear feet of drill pipe).
2.
Pump Temblok plug (Volume to be determined by plug length
desired).
3.
Pump K-35 spacer (usually 500 linear feet of drill pipe).
4.
Pump the required amount of displacement fluid as fast as
practical to minimize the residence time in the pipe.
F)
Balance the plug as best as possible to reduce any U-tubing or stringing
of the fluid.
G)
Shut down and SLOWLY pull the drill pipe from out of the plug so as not
to cause any swabbing.
H)
Pull the drill pipe up above the plug and reverse circulate until bottom
up are seen to ensure there is no Temblok remaining in the pipe.
Note: Pull far enough above the plug in order not to disturb the
Temblok plug.
12 of 26
I)
Shut down to allow the Temblok to hydrate for at least 2 hours.
J)
Run in hole with drill pipe and make an attempt to tag the plug in order
to confirm its position. This will allow the placement of a second pill
should the first pill be unsatisfactory or not in the correct place.
K)
Pull out of hole with drill pipe if the plug is found to be satisfactory.
SAUDI ARAMCO
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
DRILLING MANUAL
June 2006
DRILLING PRACTICES
F
LOST CIRCULATION
___________________________________________________________________________________________________________________________
5.4
High Temperature Blocking Gel
The following is a general recipe for the BJ Services High Temperature
Blocking Gel. The recipe should be modified depending on the severity of the
Loss Circulation.
Ingredients for 1000 gallons (500 pptg System)
GW-38 Suspending Gel)
BF-7 (Delay Buffer)
Boric Acid (Crosslinker)
GW-38 (Main Polymer)
Breaker
20 – 50 pounds5
12 pounds1
5 pounds
480 – 450 pounds2
Note 3
Note:
1.
2.
3.
4.
5.
5.5
The BF-7 will vary according to the temperature and delay time
required. Delay times can be set from as low as 20 minutes to as
high as 4 hours. At 200oF, the above loading will provide 75
minutes pumping time and 120 minutes setting time.
The GW-38 loading will vary as required. The suspension gel may
be raised (see note 5) to minimize polymer settling at the higher
loading and control leak-off.
An external breaker of either 15% HCl or water containing oxidizers
can be used. The system can be jetted out using coiled tubing or
drill pipe.
The system is highly sensitive to diesel and low pH contamination.
Use the higher loadings to achieve a more viscous base gel. This
will reduce fluid leak-off to the formation.
Protectozone
5.5.1
Protectozone WL300 Plug U803 and WL500 Plug U804 are gel
systems that work at bottom hole static temperatures between 50 and
200oF. The gels are formed by adding varying amounts of LowTemperature Plugging Agent J170 to the appropriate volumes of fresh
water or prepared sodium chloride brine. A water-soluble catalyst
Sodium Dichromate M6 is added for control of setting times. Specific
breakdown times are obtained by using either Breaker J134 or
PROTECTOZONE M24 additive as an internal chemical breaker.
Breaker down times of one day to three weeks can be obtained.
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5.5.2
Ingredients for 500 gallons of gel mix:
1.
2.
3.
4.
14 of 26
Order of Addition
Add fresh water to a clean, acidfree tank. Prepare NaCl brine, if
needed.
Add J170 within 5 min. to reduce
lumping.
Add chemical breakers and
continue agitation.
Prior to pumping, add M6 catalyst
and mix for 2 to 3 minutes
Amounts of Materials
WL300
WL500
488 gal
480 gal
J170
150 lbm
Add J134
Add M6
J170
250 lbm
Add
J134 orM24
Add M6
5.5.3
Protectozone WH500 Plug U805 and WH750 Plug U806 are gel
systems that work at bottom hole static temperatures between 200
and 325oF. The gels are formed by adding varying amounts of HighTemperature Plugging Agent J171 to the appropriate volumes of fresh
water or prepared sodium chloride brine. PROTECTOZONE M24
additive is used when well temperature is between 200 and 255oF.
When well temperatures are between 240 and 325oF, FIXAFRAC J59
Diverting agent is used. Diverting agent FIXAFRAC J66 or J66S rock
salt is recommended to prevent excessive loss to the formation. Gel
life of up to 20 days is possible at temperatures above 200oF.
5.5.4
General Guidelines on Ingredients and Mixing
A)
When using J66 and J66S rock salt, the base fluid for
PROTECTOZONE WH must be prepared 9.5 lbm/gal NaCl
brine. The salt will slightly increase the thickening time of the
WH500/wh750 system.
B)
Do not run J66/J66S in the first 10% of the slurry. This should
allow the slurry to penetrate deeper in the larger fractures and
vugs.
C)
Do not add diverting agent in the last 10% of the slurry (but not
more than the capacity of 500 feet of tubing). This is a safety
measure to avoid solids in that portion of the slurry that may
remain in the tubing during hesitation-squeeze operations. This
length will very for drill pipe depending on the size in use.
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Drilling & Workover Engineering Department
CHAPTER 2
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LOST CIRCULATION
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D)
Add J66/J66S to the middle 80% of the slurry, do not exceed 0.5
lbm/gal. In large-volume treatments, the diverting agent can be
added in stages during the treatment.
E)
M24 breaker is used for temperatures up to 260oFand J59 for
temperatures from 240 to 325oF.
F)
Add 25 lbm of Synthetic polymer J166 per 1000 gallons for
temperatures to 215oF and 50 lbm for temperatures greater than
215oF.
G)
Add 3.5 lbm of Soda Ash M3 for each 25 lbm of J166 used.
H)
Use 500 lbm of High-Temperature Plugging Agent J171 per
1000 gallons at temperatures above 250oF and 750 lbm of J171
per 1000 gallons at temperatures between 240 and 325oF.
Note: Do not use oilfield brines because such waters contain excessive
amounts of calcium and magnesium salts, which can unpredictably
accelerate the setting time.
6.0
BARITE PLUG
A barite plug is very effective in stopping underground blowouts and severe loss
circulation. The important fact is that an underground blowout cannot be controlled
by conventional methods because the wellbore will not stand full of kill-weight mud.
Usually, the first step to shutting off the underground flow is the spotting of a high
density barite pill between the flowing and lost returns zones. The barite pill slurry
is usually mixed with cementing equipment and is spotted on bottom where the
high density of the plug (18 – 22 ppg or 119 – 164 pcf) holds additional pressure on
the formation, eventually stopping underground crossflow. After the crossflow is
stopped, barite settles out and forms a pressure competent bridge. Sometimes
sloughing of the shale also occurs as a result of the fresh filtrate that is created as
a result of the barite settling out. This shale sloughing helps in bridging the hole,
thus creating zonal isolation.
A barite pill can also be used to control high pressure, low permeability formation
so that another string of casing can be set. This type of formation will cause
severely gas-cut returns, but will not usually cause appreciable well flow; however,
the casing seat usually will not hold the mud weight required to contain the
formation.
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DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
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F
June 2006
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LOST CIRCULATION
___________________________________________________________________________________________________________________________
6.1
Composition and Density
6.1.1
The Barite plug consists of barite, water, a thinner and pH controller.
The thinner is needed to deflocculate the barite slurry, which results in
improved pumpability and allows the barite to settle from the slurry at
a predictable rate. Common deflocculating agents include
A)
SAPP (Sodium Acid Pyrophosphate) which is stable up to 180o
F temperature. Usually SAPP has high fluid loss (≈25cc). It is
ineffective with some barites and cannot tolerate excessive salt
or calcium in the mix water. Pilot testing of the barite plug in the
lab is highly recommended prior to field use.
B)
Lignosulfonate is stable up to 350o F temperature. It has a low
fluid loss characteristic of ≈5cc.
6.1.2
Caustic soda is used as a pH controller. It provides the alkaline
environment (pH 10-11) necessary for the lignosulfonate to be
effective.
6.1.3
The recipe for one barrel of 157 pcf barite slurry includes:
A)
B)
C)
D)
16 of 26
0.54 bbl water
691 lbs barite
8 lbs lignosulfonate
1 lb caustic soda
6.1.4
The lignosulfonate recipe above will work for all barites and in brines
up to sea-water salinity and hardness, provided the pH is kept up
close to 11. For mix waters with hardness above 250 ppm, the
hardness should be reduced by raising the pH to 11 and then adding
soda ash as necessary. With any high salinity brine, pilot testing is
recommended to insure the final slurry meets the requirements.
6.1.5
Since SAPP will deflocculate some, but not all, barite slurries, it may
occasionally be substituted for the lignosulfonate in the recipe. Proper
concentrations would be 1/2 ppb SAPP and 1/4 ppb caustic soda.
6.1.6
A 157 pcf slurry density usually provides a good balance between
maximizing slurry density and adequate pumpability. In some cases
pilot testing may indicate a more appropriate density and the recipe
may be modified accordingly.
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
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June 2006
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6.2
Slurry Volume Calculations
6.2.1
Slurry volumes depend on the amount of open hole and the severity
of the kick. These volumes normally range from 300 sacks (40 bbls)
to 3000 sacks (400 bbls).
6.2.2
If the kick pressure is know or can be estimated, then the height of the
barite slurry needed to kill the kick can be calculated as follows
H = KD/B
Where
H = Barite pill height (feet)
K = Excess kick pressure equivalent above mud
weight (in pcf). For example, a “ten pcf kick”
is K = 10
D = Depth of kick (feet)
B = Excess barite slurry density above mud density
(pcf)
The slurry volume should be 125 to 150% of the annular capacity
necessary to give the height of the plug desired, but should not be
less than 40 barrels (300 sacks). If a second barite plug is required,
then the slurry volume should be greater than the first.
6.3
Pilot Testing
Because of variations and possible contamination of ingredients, it is always
advisable to pilot test a barite slurry in the field prior to pumping in the well.
Prepare a sample of the slurry using the above recipe and ingredients
(section 7.1.3) at the wellsite. After stirring well, the sample should have the
expected density and be pumpable. If the brine needs to settle in the
wellbore, the pilot test should reflect so. Reasonable settling is 2 inches in a
mud cup after 15 minutes. The settled cake should be hard and somewhat
sticky, not soft and slippery. The settling test is not a guarantee that the
barite pill will form an effective plug under downhole conditions, but will
certainly give an indication of the settling characteristics.
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Drilling & Workover Engineering Department
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DRILLING MANUAL
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LOST CIRCULATION
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6.4
Pumping, Displacement Rates and Equipment
6.4.1
Pumping and Displacement Rates
A barite pill should be pumped and displaced at a rate somewhat
higher than the kick rate. If the kick rate is unknown, a reasonable
rate (5 – 10 barrels per minute) should be used for the first attempt,
although prolific blowouts can ultimately require kill fluid placement
greater than 100 barrels per minute.
6.4.2
Equipment
The equipment needed on location to prepare and pump a barite plug
is as follows:
(a)
(b)
(c)
A cementing unit equipped with a high pressure jet in the mixing
hopper
A means of delivering the dry barite to the cementing unit
Sufficient clean tankage for the mix water so that the
lignosulfonate and caustic soda can be mixed in advance
The barite slurry may be pumped into the drill pipe either through a
cementing head or through the standpipe and Kelly. In either case,
the pump tie-in to the drill pipe should contain provisions for hooking
up both the cementing unit pump and the rig pump so that either can
be used to displace the slurry. If this is not done and the cementing
unit breaks down, the barite may settle in the drill pipe before the mud
pump tie-in can be made or the cementing unit repaired. Blockage of
the drill string by barite settling will complicate the well control
problem.
6.5
Procedures
6.5.1
If Pipe is Free
If pipe is free at the end of the pumping operation, it may be possible
to pull out of the plug. The risk of pulling out of a plug that is set to
contain an underground blowout is high, especially if a second barite
plug becomes necessary. The risk considerations are as follows:
18 of 26
A)
The pipe may become stuck at the shallower depth. This limits
the effectiveness of subsequent barite plugs if required.
B)
A stripping operation may be necessary to pull the pipe or to
return to bottom.
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
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F
June 2006
DRILLING PRACTICES
LOST CIRCULATION
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6.5.2
Leave Pipe in Place (Underground Blowout)
A)
Mix and pump the slurry at the appropriate rate. Monitor the
slurry density with a densometer in the discharge line or a
pressurized mud balance. Displace the slurry immediately at the
same rate.
B)
Overdisplace the slurry by 5 barrels to clear the drill string.
Continue to pump 1/4 barrel at 15 minute intervals to keep the
drill string clear unless pressure remains on the drill pipe.
C)
To verify whether the underground flow has been stopped, a
noise log can be used. Temperature surveys can be used in
addition for confirmation or if the noise log is not available,
however the noise log is more definitive than temperature logs.
If temperature surveys are to be used, wait 6 to 10 hours for the
temperature to stabilize. The survey will show a hotter than
normal temperature in the shallower zone of lost returns. After 4
hours. a second temperature survey will show a decrease in
temperature (cooling) across the zone of lost returns.
D)
After confirming that underground crossflow has been stopped,
bullhead a cement slurry through the bit to provide a permanent
seal. Observe the annulus during pumping. If the casing
pressure begins to change a lot or a sudden change in pumping
pressure is observed, the barite plug may have been disturbed.
In this case, over-displace the cement to clear the drill string.
Additional cementing might be desirable to obtain a squeeze
pressure.
E)
Plug the inside of the drill string. This can be accomplished by
either under-displacing the cement plug in step (D) above, or
preferably setting a wireline bridge plug near the top of the
collars. Cement should be dump bailed on top of the wireline
bridge plug for additional safety.
F)
Pressure test the plug, inside the drill pipe.
G)
Perforate the drill string near the top of the barite plug and
attempt to circulate.
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♦ It may be difficult to tell whether the well is circulating or
flowing from the charged formation.
Pressure
communication between the drill pipe and annulus is one
clue. Another is that a pressure increase should have
appeared on the drill pipe from the annulus pressure or on
the casing from hydrostatic pressure in the drill pipe when
the perforation was made.
♦ Consideration should be given to circulating with lighter mud
because of the known zone of lost returns.
1.
2.
20 of 26
Well will circulate
i)
Use drill pipe pressure method to circulate
annulus clear of formation fluid.
ii)
Run a free-point log.
iii)
Begin fishing operations.
Well will not circulate
i)
Squeeze cement slurry through perforation(s).
Cut displacement short on final stage to provide
an interior plug or set wireline bridge plug. WOC
and pressure test plug.
ii)
Run free-point log.
iii)
Perforate the pipe near the indicated free point.
iv)
Circulate using drill pipe pressure method until
annulus is clear. If well will not circulate, squeeze
perforation(s) with cement or set a wireline bridge
plug above perforation(s), and reperforate up the
hole.
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
F
June 2006
DRILLING PRACTICES
LOST CIRCULATION
___________________________________________________________________________________________________________________________
6.5.3
Pull Out of Plug (High Pressure, Low Permeability Formation)
A)
Mix and pump the slurry. Monitor the slurry weight with a
densometer in the discharge line or a pressurized mud balance.
If mixing is interrupted for any reason, immediately begin
displacement of the slurry using either the cement unit pumps or
the rig pumps. Work the pipe while pumping and displacing.
B)
Displace the slurry with mud at the same rate. Cut the
displacement short by 2 or 3 barrels to prevent backflow from
the annulus. If a drill pipe float is in the drill string, overdisplace
the slurry.
C)
Immediately begin pulling the pipe. It may be necessary to strip
the pipe through the annular preventer. Pull at least one stand
above the calculated top of the barite slurry.
E)
1. If no pressure is recorded on the annulus, continue working
the pipe while observing the annulus mud level.
i)
ii)
Annulus full: Begin circulating at a low rate keeping
constant watch on the pit levels.
Annulus not full: Fill annulus with water and observe. If
annulus stands full, begin circulating at a slow rate.
Consider cutting the mud weight if feasible.
2. If pressure is recorded on the annulus, circulate the annulus
clear using normal well control techniques. Continue working
the pipe.
i)
ii)
If returns become gas free, the barite pill was successful
and the well is dead.
If returns do not become essentially gas free after
circulating two or three annular volumes, the barite pill was
not effective. A second plug will be necessary.
E)
After determining that the well is dead, go back in the hole to
near the top of the barite slurry. Set a balanced cement plug
and pull out a few stands. This step is sometimes eliminated.
F)
After waiting for the cement to set up, run back in hole and tag
the top of the cement plug.
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DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
June 2006
DRILLING PRACTICES
F
LOST CIRCULATION
___________________________________________________________________________________________________________________________
7.0
THIXOTROPIC CEMENT
7.1
Characteristics
Thixotropic slurries have the shear-thinning characteristic. This means that
the slurry under shear will stay in fluid phase but develops a gel structure
when the shearing force stops.
7.2
Procedures
Typical Thixotropic cement job.
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A)
Run in hole open-ended to 25 feet above loss circulation zone.
B)
Pump desired volume of a selected polymer plug.
C)
Follow with Thixset cement slurry.
i)
Slurry mix: Class-G Cement + 1.0% Comp A + 0.25% Comp B +
fresh water + defoamer.
ii)
The above mix is a Halliburton recipe. Equivalent chemicals and
mixes can be used from the other In-Kingdom pumping service
companies.
D)
Continue pumping cement until the agreed upon volume has been
pumped or until squeeze pressure is noted. A pressure increase of 250
psi is sufficient for squeeze applications of this nature.
E)
Displace the cement with fresh water. Shut down, pull at least four
stands and clear drill pipe.
F)
Once the drill pipe and annulus are clean, pull out of hole.
G)
Wait on cement 6 to 8 hours to give the cement time to set.
H)
Run in hole with drill pipe and tag top of cement. Attempt to fill annulus.
If returns are noticed, resume drilling, otherwise, consider repeating
process or attempting different process.
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
SECTION
F
June 2006
DRILLING PRACTICES
LOST CIRCULATION
___________________________________________________________________________________________________________________________
8.0
CEMENT PLUG
When mud circulation is lost while drilling, it is sometimes possible to restore
returns by spotting a cement plug across the thief zone, and then drill back through
the plug. The balanced cement plug is usually preferred and it is the most
common method.
8.1
Characteristics
When placing a cement plug across a thief zone to combat lost circulation, it
is important to take every precaution to ensure that the cement sets properly.
The following are general preventive measures:
A)
Use neat cement with 0.25 lbs/sack of Cellophane Flakes (optional).
Thickening time should be checked against the estimated cement
placement time.
B)
In shallow thief zones, avoid circulating cement extensively. Extensive
circulation will retard the development of cement strength. It is
desirable to achieve early strength and allow the cement to set without
agitation.
C)
Use sufficient spacer that is compatible with the mud ahead of the
cement (water spacer is usually used).
D)
When calculating cement volume, include 50 to 100 feet of cement
height above the thief zone depending on the severity of the losses.
E)
Place the plug with care and move the pipe slowly out of the cement to
minimize swabbing action and mud contamination.
F)
Allow ample time for the cement to set prior to drilling out.
Note: Cement placement failures commonly occur due to fluid backflow,
slugging or improper displacement volumetric calculations.
8.2
Procedures
A)
Determine the severity of circulation loss to decide on the cement plug
length above the thief zone. Maximum plug length is 500 feet.
B)
Run in hole with open-ended drill pipe to 10 feet below the bottom of the
loss zone. Spot a 100 bbl LCM pill (50 #/bbl) across loss zone.
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C)
Pick-up 30-50’ above the circulation loss zone. Pump down the drill pipe
the calculated spacer, cement, spacer and kill fluid. This involves
balancing the hydrostatic pressure inside and outside the drill pipe so
that the height of the cement and displacing fluid inside the drill pipe
equals the height of fluids in the annulus (see sketch below).
Note: Do not use a water spacer if loss circulation is in the Wasia.
M
M
M
W
W
M
M
M
W
W
W
M
W
M
(a) Displacing
cement.
M
(b) Cement, water
and mud balanced.
M
M
M
M
W
W
M
M
(c) Pulling string
above top of cement.
M
(d) Reversing out.
M = Mud
Balanced Plug Technique
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W = Water
D)
Pick up drill pipe to +400 feet above the top of the calculated spacer.
While pulling out of the cement, pull slowly to avoid swabbing and mud
contamination.
E)
Pump mud down the casing-drill pipe annulus and reverse circulate (if
possible) to insure pipe is clean of cement.
F)
POH to casing shoe. WOC. Attempt to fill hole. If unsuccessful, RIH with
open-ended drill pipe and tag top of cement. Set a second cement plug
on top of Plug #1. Repeat process as described above.
G)
If the hole can be successfully filled, pull out of hole with open ended
drill pipe. Run in hole with bit and drill out cement plug while keeping a
close watch on the mud level in hole. If hole starts taking fluid, note
depth and consider spotting of another cement plug or other type of
plugs.
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
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F
June 2006
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LOST CIRCULATION
___________________________________________________________________________________________________________________________
9.0
FOAM CEMENT
9.1
Characteristics
Foam Cement is a mixture of cement slurry, foaming agents, and a gas
(usually nitrogen). When properly mixed, the process forms an extremely
stable, lightweight, low permeability slurry that looks like gray shaving cream.
Foam cement slurries can be prepared in the range of 30 to 112 pcf, which
develop relatively high compressive strength in a minimum period of time.
Although Foam Cement is mainly used in primary cementing, it may be used
as a plug to regain lost circulation in zones where all other loss circulation
methods have failed.
9.2
Procedures: (Foam Cement with Flo-Chek or Flo-Chek 1:1)
A)
The fluid level should be determined as close as possible with an
estimate of the fluid density in the well bore.
B)
All personnel should be prepared for N2 gas cut returns and a method
of choking the well flow should be installed. It is not advisable to take
Foam Cement returns through the rig’s choke manifold. A disposable
adjustable choke should be installed if possible. Due to the viscous
nature of Foam Cement, it is likely that a cement sheath will be left in
the drill pipe. To help reduce this effect, a drill pipe wiper plug and
catcher attachment should be installed so that the drill pipe may be
cleaned during displacement.
C)
RIH with open ended drill pipe, with a plug catcher if available, to a
depth that is at least 50’ above the loss circulation zone.
Note:
It is advisable to lead in with a slug of mud containing LC
material.
D)
Flush and fill lines with fresh water. Pressure test lines to 3000 psi.
E)
OPTIONAL: Pump the following sequence with the annulus open at
+3BPM:
1.
2.
3.
4.
5.
6.
7.
8.
24 bbls CaCl2 Brine Water as an activator solution
5 bbls Fresh Water as a spacer
12 bbls Flo-Chek or Flo-Chek 1:1
5 bbls Fresh Water as a spacer
24 bbls CaCl2 Brine Water as an activator solution
5 bbls Fresh Water as a spacer
12 bbls Flo-Chek or Flo-Chek 1:1
5 bbls Fresh Water as a spacer
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F)
Follow the Flo-Chek system with Foam Cement consisting of Class G
mixed at 118 pcf. Add N2 on the fly to bring the combined slurry weight
to 63.5 – 67 pcf. The cement pump rate should be held to +3BPM. The
foaming solution, consisting of 1.5% BWOMW HOWCO SUDS and
0.75%BWOMW HC-2, will be injected at a combined rate of 0.6 gal/bbl
of slurry. Foamer FDP-C552 may be substituted for the HOWCO SUDS
& HC-2 at the same loading.
Note: At any time during the pumping process, with the annulus open,
be sure to close it once returns are noticed. Monitor the pressure
closely after the annulus has been closed and be prepared to
shutdown quickly.
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G)
Continue pumping Foam Cement until the agreed upon volume has
been pumped or until squeeze pressure is noted. A pressure increase
of 250 psi is sufficient for squeeze applications of this nature.
H)
Drop the drill pipe wiper plug, if available, and displace the Foam
Cement with fresh water.
I)
Shut down, pull at least four stands, shear plug catcher and allow the rig
to reverse out any remaining cement that may be in the drill pipe. Be
prepared to reverse out under pressure. If Foam Cement is reversed
out, it will exit at an extremely high velocity. Control and regulate the
return rate using surface valves or choke manifold.
J)
Once the drill pipe and annulus are clean, POOH.
K)
Wait on cement 12-14 hours to allow the cement time to set.
L)
RIH with drill pipe and tag top of cement. Attempt to fill annulus. If
returns are noticed, resume drilling. Traces of N2 will be seen at
surface while drilling through the Foam Cement column.
SAUDI ARAMCO
DRILLING MANUAL
Drilling & Workover Engineering Department
CHAPTER 2
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G
June 2006
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ABANDONMENT GUIDELINES
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ABANDONMENT GUIDELINES
1.
CEMENT PLUGS
1.1 Introduction
1.2 Open Hole
1.2.1 Hydrocarbon Bearing Formations
1.2.2 Porous Aquifers
1.2.3 Last Casing Shoe
1.2.4 Extended Open Hole
1.3 Cased Hole
1.3.1 Casing-to-Formation Annulus
1.3.2 Hydrocarbon Zones
1.3.3 Water Source Zones
1.3.4 Injection Zones
1.3.5 Extended Cased Hole
1.3.6 Casing-To-Casing Annuli
1.3.7 Other Protective Plugs
2.
MARKERS
2.1 Onshore
2.2 Offshore
3.
RADIOACTIVE TOOLS (Lost in Hole)
3.1 General Information
3.2 Procedures
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ABANDONMENT GUIDELINES
1.0
CEMENT PLUGS
1.1
Introduction
Wells may be abandoned for any one of a number of reasons. Abandonment
procedures in newly drilled wells are largely dictated by individual well
conditions. Factors affecting abandonment programming include:
A)
B)
C)
D)
E)
F)
G)
H)
I)
Mechanical condition
Hole problems while drilling
Location
Casing configuration and cementation integrity
Productive nature and interrelation of porous
hydrocarbon bearing zones
Corrosion considerations
Local development plans
Governmental directives
Economic considerations
aquifers
and/or
Proper abandonment is therefore a combination of sound judgment and
applicable oilfield practices tailored to a particular well. The guidelines
presented herein are intended to establish uniform abandonment objectives
while recognizing practical limits often imposed by well conditions.
1.2
Open Hole
1.2.1
Hydrocarbon Bearing Formations
Cement plugs are placed across all hydrocarbon bearing formations
and extend at least 100’ below and 100’ above each formation. The
presence of the plug across the hydrocarbon formation nearest the
last casing shoe is to be confirmed by setting down the string weight
on the plug after waiting on cement (WOC). Presence of all plugs
isolating gas reservoirs should be checked in the same manner.
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1.2.2
Porous Aquifers
Porous aquifers are to be isolated by cement plug placed across
and/or between zones resulting in at least 100' of plug height
separation between zones where possible. Check integrity (drill string
weight) of the plugs as follows:
A)
B)
C)
1.2.3
Separating aquifers from uphole hydrocarbon zones
Separating aquifers, which are potable or suitable for irrigation
purposes. The workover engineer should check with the
Hydrology Dept. for this information
Separating all abnormally pressured water bearing zones
Last Casing Shoe
A 300' cement plug should be placed across the last casing shoe and
will extend at least 150' above the shoe. The plug should be tagged
with the drill string and pressure tested to at least the maximum
equivalent mud weight used in the open hole plus 25%. The tag up
and pressure test should be witnessed by the Aramco representative
on the rig and noted in the tour report.
1.2.4
Extended Open Hole
In long sections of open hole which would not be plugged for reasons
above, a 300' cement plug should be placed at no greater than 2000'
intervals. The plug placement should be tagged with the drill string.
Long open hole sections are common on deep exploratory wells.
1.3
Cased Hole
1.3.1
Casing to Formation Annulus
A)
2 of 8
Where cement is not returned to surface during a cement job,
the top of cement can be estimated from volumes of cement
pumped, fluid returned and the hole diameter. Cement bond logs
and/or temperature surveys can be run to determine the cement
top and should normally be adequate confirmation of annular
shut off integrity in critical situations. Under certain
circumstances, however, perforating, cement squeezing and a
dry test may be warranted.
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B)
1.3.2
If the bond is questionable, the annulus should be cement
squeezed
between
hydrocarbon
reservoirs,
between
hydrocarbon and separate porous aquifers, and between
separate porous aquifers. The UER is usually isolated from the
Khobar by cement squeezing the RUS whereas the Wasia is
isolated from the upper aquifers by cement squeezing the LAS.
Hydrocarbon Zones
All hydrocarbon zones tested or commercially produced then
abandoned should be squeeze cemented after ensuring annular shut
off and pressure tested to at least 50% above the balance mud weight
equivalent (not to exceed the derated casing burst pressure). Gas
zones are to be squeezed through a cement retainer, capped with at
least 50' of cement, tagged and pressure tested as above. Depending
upon the condition of the casing, a retrievable isolation test packer
may be run for this pressure test if required.
1.3.3
Water Source Zones
Annular shut-off (formation to casing) should be ensured prior to
squeeze cementing water source zones. If squeezing is unfeasible, an
interior cement plug extending at least 100' below and 100' above will
be placed, tagged, and pressure tested to the safe casing limit.
1.3.4
Injection Zones
Abandoned injection zones (water injection, disposal, product
injection) should be cement-squeezed after confirming annular shut
off above and below the zone. Squeeze integrity should be pressure
tested to BH injection pressure + 25% equivalent.
1.3.5
Extended Cased Hole
In long sections of cased hole which would not be plugged for reasons
above, a 300' cement plug should be placed at no greater than 3000'
intervals. The plug placement should be tagged with the work string.
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1.3.6
Casing to Casing Annuli
In some cases, an attempt should be made to cement sections of
previously uncemented casing to casing annuli particularly when such
section lie opposite hydrocarbon zones or corrosive aquifers having
no cement rise on the outside string.
1.3.7
Other Protective Plugs
Abandonment cement plugs should be spotted across other
susceptible points in the well as follows:
A)
B)
C)
D)
2.0
300' cement plug centered on any exposed liner top(s)
300' cement plugs centered across exposed stage cementing
equipment
Cement plug having adequate height to extend 100' below and
above any problem points (casing parts, splits, patches, prior
remedial perforations, etc.) in the innermost string
From surface to 300' depth (onland) and to 300' below mudline
(offshore)
MARKERS
Once a well has been plugged with cement to the surface, an abandonment
marker is installed for future identification.
2.1
Onshore
Onshore abandoned wells should have the landing base removed and
salvaged. A steel plate will be welded on the casing cut-off and a 4-1/2" OD
steel post is to be welded on top of the steel plate; a sign marker will be
installed on top of the post. The post should be at least 4' long and extend at
least 4' above ground level. The well name and abandonment date should be
clearly embossed on both the post and sign marker, with weld material.
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Abandonment Marker
Well Number and
Abandonment Date
4-1/2” Steel Post
(with Well Name and Abandonment Date)
Sweet Sand
Ground Level
Cellar
Conductor
Cement Plug #3
Surface Casing
Cement Plug #2
Intermediate Casing
Cement Plug #1
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ABANDONMENT GUIDELINES
___________________________________________________________________________________________________________________________
2.2
Offshore
Offshore markers are similar to onshore markers except there is no post or
abandonment marker. The blind flange is labeled with the well name and
abandonment date.
3.0
RADIOACTIVE TOOLS
3.1
General Information
When a radioactive source becomes stuck in a well during drilling operations,
every reasonable attempt should be made to recover the source. If the
attempt fails, the source should be abandoned properly per the following
procedure in section 3.2. This procedure does not call for the well to be
entirely abandoned, only the radioactive source. The decision whether or not
to salvage the upper portion of the well should be made on a case-by-case
basis.
3.2
Procedures
The following procedure conforms to the rules and regulations set forth by the
United States Nuclear Regulatory Commission, specifically Title 10, Chapter
1, Part 39 (Licenses and Radiation Safety Requirements for Well Logging).
3.2.1
The Manager of Drilling and Workover Engineering Department will
submit a statement to the logging company. A copy of this statement
will be forwarded to Government Affairs representative.
The
statement is to include the following:
A)
B)
C)
D)
3.2.2
6 of 8
Source description; radio-isotope, quantity & activity
The depth at which the source is stuck
A summary of the attempts to retrieve the source
A plan for the abandonment of the source in the well
Spot a +120 pcf cement plug directly above the fish. The plug is to be
dyed red (use AMS No. 09-612-747) and dressed to a minimum of 50’
above the radioactive source.
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ABANDONMENT GUIDELINES
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3.2.3
Place a steel object of adequate size, such as a used bit or whipstock,
on top of the plug to prevent the inadvertent reentry of the abandoned
hole interval. The bit or whipstock may be placed using a shear sub.
See wellbore schematic below.
3.2.4
Install a permanent plaque on the wellhead. It must include:
A)
B)
C)
The word “Caution”
The radiation symbol
The words “Saudi Aramco”
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D)
E)
F)
G)
H)
I)
The field name and well number
Total depth of the well
Date that the source was abandoned
Depth of the source
Depth of the plug
Radio-Isotope, quantity & activity of the source
The plaque is to be corrosion resistant. It is usually made of engraved
stainless steel, provided by the logging company and is to be installed
by Saudi Aramco. See schematic below.
3.2.6
The Drilling Engineer is to include at least 3 references to the lost
radioactive source in the well’s Completion Report.
A)
B)
C)
8 of 8
Lost tools section on the Cover Page (page 1)
Plugs/junk section in the Summary of Operations (page 2)
Discussion section in the Summary of Operations
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CHAPTER 2
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CORING
1.0
CORING APPLICATIONS AND TECHNOLOGY
1.1 Coreheads
1.2 Conventional Core Barrel
1.3 Fiberglass Inner Tubes
1.4 Stabilization
1.4.1 Corehead Stabilization
1.4.2 Inner Barrel Stabilization
1.4.3 Drill Collar Stabilization
1.5 Operating Procedures: Conventional Coring
1.5.1 Starting Practice
1.5.2 Jamming
1.5.3 Making a Connection
1.6 Operating Parameters
1.6.1 Circulation rate
1.6.2 Rotary Speed
1.6.3 Weight on Bit
1.7 Coring with Lost Circulation Material
2.0
PROCEDURES
2.1 Handling a Standard Core Barrel
2.2 Core Barrel Pick-Up
2.3 Coring Practices
3.0
WELLSITE GEOLOGIST REQUIREMENT
3.1 Conventional Core Using a Metal Inner Barrel
3.1.1 Equipment Requirements
3.1.2 Operations
3.1.3 Numbering
3.1.4 Marking
3.2 Conventional Core Using a Fiberglass Inner Barrel
3.3 Preserved Cores
3.3.1 Procedure
3.3.1.1 Material Needed
3.3.1.2 Mixing Procedure
3.4
Transporting Cores to Dhahran
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CORING
1.0
CORING APPLICATIONS AND TECHNOLOGY
Coring is the removal of formation from the wellbore through mechanical means in
as nearly as possible, an undamaged or physically unaltered state. A core sample
is only as good as the formation data that can be derived from it. Detailed
information from target formations is essential for the successful evaluation of both
primary and secondary recovery programs. Core samples can yield this critical
subsurface information. With
quality cores, oil companies can
more fully understand formation
characteristics
and
more
efficiently achieve production
objectives. High quality cores
provide the most accurate
lithology,
porosity
and
permeability
information
for
building the geologic model of
the reservoir. Such models are
important tools, for example, in
evaluating horizontal and vertical
permeability. Core samples can
provide the petrophysicist and
the reservoir engineer with
accurate saturation, wettability
and electrical properties of the
formation.
When
secondary
displacement is the objective,
core sample data are essential. Core quality is the key. The sample must be
obtained without altering its native (or in-situ) properties.
It is therefore essential that every coring job is correctly planned and programmed
with well-defined objectives, so that all the wellsite personnel know their individual
roles. A written program should be available, setting out the type and size of core,
drilling mud to be used, documentation requirements, and geological description,
packing and storage instructions, and the destination of the core.
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1.1
Coreheads
There are three types of core heads that are used by Saudi Aramco. They
are the polycrystalline diamond compact (PDC), the natural diamond and the
thermally stable polycrystalline (TSP) bits.
Natural Diamond
TSP
PDC
The following table shows the coreheads available for use by Saudi Aramco along
with the corresponding formations of each corehead type
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Formation
Formation Description
Rock Type
Bit
IADC
Code
Recommended
Christensen
Coreheads
Corehead
Type
Recommended
Corepro
Coreheads
SHU’AIBA
Soft formation with low
compressive and high
drillability.
Soft to medium formation
with low compressive
strength interbedded with
hard layers.
Marl, Chalk,
Carbonate
417-447
ARC-412
PDC
CM-468FRS
CM-369FS
Sand,
Anhydrite,
Dolomite
517- 537
ARC-435
ARC-325
PDC
CM468FRS
CM369FS
KHUFF
Medium to hard formation
with high compressive
strength.
Limestone,
Dolomite,
Anhydrite
537-627
C-201
SC-777
Natural Diam.
TSP
CD3X5/9
CT3X8
UNAYZAH
JAUF
Hard and dense formation
with very high
compressive strength and
some abrasive formation
layers.
Siltstone,
Sandstone
627-737
SC-777
C-23
SC-279
SC-280
TSP
Natural Diam.
Impregnated
CD3X5/15
CD4X5/15
(Nat. Diam.)
UNAYZAH
SAQ
Extremely hard and
abrasive formation.
837
SC-279
SC-280
Impregnated
No. Impreg.
Avail.
CD4X5
(Nat. Diam.)
KHAFJI-SD
ARAB-D
HANIFA
1.2
Quartzite
Sandstone
Conventional Core Barrel
The Christensen 250P core barrel is reliable, easy to use and maintain. It is
available in many different sizes in order to accommodate the various hole
sizes drilled and to match the availability of fishing tools. The following table
lists the various conventional core barrel sizes most commonly used in Saudi
Arabia.
Barrel Size
Std.
Length (ft)
# Turns in
Safety Joint
Make-up
torque (ft-lb.)
Fluid Cap.
(GPM)
Recommended
Max. Pull (k-lb.)
4-3/4 x 2-5/8
6-3/4 x 4
60
60
13
6
4,700
11,100
164
387
232
407
Because of the standardization of parts, any outer tube, inner tube that
should become damaged can easily be replaced out of stock without costly
machine shop work.
There are also high-torque core barrels that can be used when deep coring is
required. These are equipped with HT-30 threads for the 6-3/4 in. tool with a
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make-up torque of 30,000 ft-lb. and a HT-10 thread on the 4-3/4 in. barrel that
is made up with 10,000 ft-lb.
All conventional core barrels, with the exception of the 3-1/2 in. conventional
slim hole, come equipped with a safety joint. The safety joint allows the inner
tube to be removed with the core if the core barrel should ever become stuck
in the hole.
A drop ball arrangement is used to vent mud to the region between the inner
and outer tubes when the core enters the barrel. The drop ball can either be
run in place or dropped after the hole has been cleaned out by circulating
(see diagram below). In caving holes where mud can readily drop solids, or
where fill can settle on bottom, it is necessary to circulate through the inner
tube extensively until bottom is reached. When this is the case, the drop ball
can be left out of the barrel to allow full circulation through the inner tube
when washing to bottom. After bottom is clean, the ball is dropped to divert
mud around the inner tube before starting to core.
It is best to cut the largest diameter core while still being able to wash over
and fish for the tool in the event it becomes necessary to fish. The larger the
core, the faster the penetration rate will be. When coring naturally fractured or
broken formations, the larger core tends to hole the natural position and
causes fewer jamming problems.
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1.3
Fiberglass Inner Tubes
Where formations are soft and unconsolidated, a fiberglass inner core barrel
is used to ensure higher recovery rates. The fiberglass inner tube is fully
interchangeable with the conventional steel barrel. The fiberglass makes a
smooth internal wall with a low co-efficient of friction, allowing easy entrance
of the core into the barrel and core jamming in fractured formations is
minimized, resulting in higher core recovery. The fiberglass is strong and
corrosion proof. It is resistant to the corrosive actions of acids, chemicals and
salts from the mud system or core material.
The strong but light weight glass fiber-reinforced epoxy allows easy handling
of the fiberglass inner-tube on the rig site. The pin and box standard threaded
steel connectors on both the lower and upper ends, make the fiberglass inner
tube fully compatible with a conventional steel system using standard spare
parts. Coring with fiberglass inner tube does not create any additional
difficulties when making up, adjusting or breaking out the core barrel. Overall,
coring with the fiberglass inner tube is performed in exactly the same manner
as coring with the conventional steel inner tubes.
Due to a higher co-efficient of thermal expansion, the fiberglass inner tube
expands with heat faster than the steel outer tube. When spacing the
fiberglass inner tube, the gap between the inner shoe and the core head must
allow for this difference. The following table gives spacing compensation for
different temperatures.
Temp Differential
°F
50
100
150
200
250
300
350
30 ft
In.
0.07
0.15
0.22
0.30
3.37
0.44
0.52
60 ft
In.
0.15
0.30
0.44
0.59
0.74
0.89
1.03
The fiberglass inner tube sections are adjusted the same way as the
conventional steel liner, by adding or removing shims.
Pressure drop through the annular space between the outer tube and the
inner tube may become important when coring with fiberglass inner tubes of
more than 90 ft. in length. Besides the core barrel geometry, pressure drop
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depends on mud weight, flow rate, and viscosity of the mud. The following
equation yields a fairly good approximation of that pressure drop.
2
⎛Q⎞
∆P/ft = (1.01) × (a) × ( ∂ ) × ⎜ ⎟ × (1 − (PV − 12 )/200 )
⎝b⎠
Where:
a, b are geometric constants
∂ = pcf
PV = centipoise
∆P/ft = psi
Q = gpm
The table below was based upon a 73-pcf mud with a PV of 15.
a
b
gpm
∆P/ft
4.75 x 2.62
229
10,335
90
120
164
1.26
2.24
4.25
6.75 x 4.00
164
18,808
180
250
340
1.09
2.10
3.89
The fiberglass is easily cut with a power saw. After the core has been
recovered, the fiberglass inner-tube containing the core is cut to length,
numbered and sealed with rubber end caps.
1.4
Stabilization
1.4.1
Corehead Stabilization
Coring in deviated holes should be performed with a corehead
equipped with a tandem mounted stabilizer, whenever possible. This
will keep the corehead flat on bottom, providing sufficient cooling and
correct removal of cuttings, resulting in good core recovery.
1.4.2
Inner Barrel Stabilization
The inner barrel should be stabilized preferably with a stabilizer in the
center.
1.4.3
Drill Collar Assembly Stabilization
The first stabilizer should be placed directly on top of the core barrel,
followed by a stabilizer at 30 ft. and one at 60 ft. above the barrel. The
remaining stabilizers should be evenly spaced out over the rest of the
assembly as required.
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1.5
Operating Procedures: Conventional Coring
Before completing the assembly of a core barrel, it should be determined
whether a ball will be run in place or dropped from the surface after bottom is
reached. When hole conditions dictate that circulation is going to be required
in order to reach bottom, the ball should be left out of the barrel when it is
assembled.
After the bottom is clean, the barrel should be raised several feet off bottom
while circulating to insure the inner barrel is clean. When the ball is dropped
to its seat in the barrel, after bottom is reached, the circulation fluid passes
around the outside of the inner tube in the conventional manner.
Precautionary procedures should be completed before running the core
barrel in the hole for removal of the float from the drill collar unless a flap type
float or full flow drill pipe is used. It is also imperative that the bore of the jars
be checked to assure passage of the ball (usually 1-1/4 in. diameter).
When the last stand of drill pipe has been lowered into the well, and the kelly
attached, circulation should be established. In full hole coring, entry into the
hole should be methodical. Caution should be exercised in all tight places to
avert core head sticking. Tight places must be reamed out. Reaming of long
intervals should not be done with core bits. When nearing the bottom and
contact is made with cavings, it is necessary to rotate and circulate. Be sure
all measurements are correct to determine bottom exactly.
After bottom has been reached and the hole circulated, the kelly should be
raised to the first joint of the drill pipe. The kelly is then removed and the ball
dropped.
1.5.1
Starting Practice
Once the ball has been dropped, replace the kelly and pump the ball
down at a good circulation rate. Allow one minute per 1000 ft. While
the ball is falling, record the pump rate and standpipe pressure. As the
ball nears bottom, slow the pumps down to allow the ball to seat
properly. As soon as the ball is seated, record the increased
standpipe pressure and return to bottom. Once on bottom, begin
rotating slowly (30-40 rpm), and start adding weight in increments of
2000 lbs. Gradually increase WOB, rpm, and fluid volumes until
optimum coring conditions are found.
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1.5.2
Jamming
Blocking the inner barrel or jamming is one of the most common
problems of coring. Jamming of the inner barrel is usually caused by a
formation condition (fractures, unconsolidated material, swelling
shales). If the barrel jams in soft unconsolidated formations the
penetration rate may remain the same but most likely will decrease.
The stand pipe pressure will increase initially and then decrease as
the core bit drills off. A change in torque, pump strokes, or a decrease
in pump pressure will also indicate a jammed core barrel.
Plugging of the core barrel from an accumulation of foreign particles in
the mud system such as rubber, LCM, or other junk in the mud
system may cause an abrupt increase in standpipe pressure.
1.5.3
Making a Connection
When it is necessary to pull off bottom to make a connection or
remove the core barrel, the following procedure is recommended.
Stop the rotation and shut off or idle the pump, raise the core barrel
until the weight indicator shows the core spring has gripped the core
and the core breaks, or until a strain begins to exceed the pull below.
For a 2-5/8 in. core, 10,000-lb. pull and for a 4-in. core 20,000-lb. pull.
If the core does not break with the maximum strain, then start the
pump and hold the strain on the core until it breaks. It may be
necessary to hold the strain for 10 minutes or longer for the core to
break. After the core has broken, raise the bit 10 feet and then lower
slowly back to within one foot of bottom. A constant check of the
weight indicator should be made to see that its readings drop
gradually with out any obstruction caused by any core left in the hole.
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If the core appears to be properly caught in the barrel, pick up and make
a connection, if not come out of the hole. It is advisable when making a
connection to lock the rotary table and back the kelly out with tongs. Then
the coring assembly can be placed back on bottom, after the connection,
exactly as it was before.
When coring is to be resumed after the
connection, go back to bottom without
rotating. With the pump on, apply normal
weight to release the core catcher so the
core can enter the core barrel. Pick up to
starting weight then start rotating slowly
and gradually return to normal coring
operations. In those instances when there
is a possibility of loose junk or pieces of
core on the bottom, it is best to use
lighter weight for the first 6 inches. The
pump can then dispose of small pieces of
junk, or fractured formation before normal
coring weight is resumed. It is after a
connection that most inner barrel
jamming occurs. Therefore, be alert to
the rig floor indicators.
1.6
Operating Parameters
1.6.1
Circulation Rate
Diamond core bits will function very satisfactorily with a wide variety of
circulating, including fresh water, salt water, crude oil, as well as
various other water and oil based muds. Sand content of the mud
should be kept at a minimum (less than 1%) to keep fluid damage to
parts of the core barrel, bit shank, and bit crown to a minimum.
The volume of liquid to be circulated is determined by well condition,
the size and design of the bit, type of mud, depth of hole, drill pipe and
core barrel, pump capacity, but most important, the fluid
characteristics. Annular velocities as low as 90 ft./min. have been
used without creating problems when coring with good mud. Sufficient
high velocities prevent the settling of cuttings.
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Core bits of the same size but differing designs are made for the
same circulating rate. Special requirements however for high mud
weights or plastic viscosities may affect these circulation rates.
The average circulation rate should be used with varying bit weights
and rpm to determine the optimum penetration rate. Circulation rates
can be varied to provide efficient cleaning and cooling, thus
maximizing core bit life.
Too low a volume may not clean the entire face of the bit, resulting in
the regrinding of the cuttings or the possible burning of the bit,
reducing the bit’s penetration rate.
High fluid volumes may be detrimental when the bit is starting. Too
high of a volume may cause the bit to lift off bottom and bounce with
subsequent diamond fracture reducing penetration rate and bit life.
High volume can also cause the inner barrel to rotate, which can
create jamming problems.
When coring in soft formations, consideration should be given to the
cutting of short cores. Soft, unconsolidated formations can support
very little weight and if the weight of the core above the throat of the
bit exceeds the formation strength, any further attempts to cut more
core will result in grinding up and washing away the core.
1.6.2
Rotary Speed
The best rotational speed for coring is usually established by the
limitations of the drilling equipment. Depth and size of hole, size and
condition of the drillpipe, size and number of drill collars and the
formation being cored all must be considered when establishing the
rotational speed. The following chart depicts recommended rotary
speeds for core bits.
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RPM
___________________________________________________________________________________________________________________________
Recommended Rotary Speed for Core Bits
Generally core bits are run with lower rotary speeds than diamond
drilling bits. Core barrels have been operated at on downhole motors
with rotary speeds in of 300 rpm to 400 rpm. However, this is only
recommended in homogeneous formations where there are minor
jamming probabilities. Penetration rates can be increased with higher
rotary speeds. Slow rotary speeds have been beneficial when coring
fractured formations. Using speeds of 30 to 40 rpm produces less
disturbance of the core.
As long as sufficient hydraulics are used to keep the bit clean, the
best rotational speed can be found by either reducing or increasing
rotational speed while keeping the weight on the bit constant.
Certain formations such as sticky shales or anhydrites can cause
excessive torque. By using a different combination of weight and
RPM, a smooth coring operation can be obtained.
1.6.3
Weight on Bit
Consistent with good oilfield practice, the weight on bit should never
exceed the weight of the drillcollars. This condition keeps the drillpipe
in tension and helps to eliminate undesired whip and vibration of the
drill string. In unstabilized situations, whipping of the drill string causes
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shock loading of the diamonds, and premature bit failure. Using a
stabilized barrel and drillstring can eliminate this whipping.
The proper weight on bit for each core run can be determined by
increasing the bit weight in steps of 1,000 to 2,000 lbs., with a
constant rpm. Coring should continue at each interval while carefully
observing the penetration rate. Optimum weight on bit has been
reached when continued increases in weight do not increase
penetration rate, or requires excessive torque to rotate the bit. Using
too much weight can cause the diamonds to penetrate too deeply into
soft formations and with an insufficient amount of mud flowing
between the diamonds and the formation, could result in poor removal
of cuttings. The core bit could clog or even burn, resulting in poor
penetration rate and bit life. In harder formations excessive weight can
cause the tips of the diamonds to burn or shearing off, both which
reduce the bit life.
Weight on bit (pounds)
After the desired bit weight is determined, every effort should be made
to keep the weight constant. The brake should be tended at all times.
Do not apply more weight then let it off only to apply more weight
again. Automatic drillers normally do a good job of maintaining a
constant weight on bit. The following chart depicts recommended
weights on bit for core bits.
har
o
ati
orm
f
d
fo
soft
S
3,
C2
n(
i
rmat
on
8
C2
0)
1,
(C20
4
ARC
12)
Bit Size (inches)
Recommended Drilling Weight for Core Bits
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1.7
Coring With lost Circulation Material
Core barrels have effectively operated using muds with large quantities of lost
circulation material (LCM). Close attention to the thorough mixing of the mud
to prohibit any large concentration of the LCM into masses or lumps, which
may subsequently block the various parts of the core barrel or plug the
waterways of the bit. LCM could also get on top of the core and prevent it
from entering the barrel. LCM should not be mixed while coring operations
are in progress, unless absolutely necessary.
When coring with LCM, the core barrel is usually run in the hole without the
drop ball in place. This prevents clogging of the bearing assembly. The drop
ball is used while coring to deter LCM from accumulating between the core
and the inner-barrel which could result in a jammed core.
It may be necessary to break circulation several times on the way down the
hole to keep from plugging the barrel and allowing lost circulation material to
accumulate in it. When LCM is used in the mud system, circulation should
begin 60-ft off bottom. After circulation is established, the core barrel should
slowly be washed to the bottom. If the lost circulation zone is very close to the
bottom of the hole, a minimum of fluid circulation may be required. When this
is the case, the rpm of the core bit should be kept as low as possible because
the lost circulation material together with the cuttings, could cause clogging of
the bit.
2.0
PROCEDURES
2.1
Handling a Standard Core Barrel
The following is the recommended procedure for handling a standard core
barrel.
A)
B)
C)
D)
E)
14 of 23
Make up all inner barrel joints by hand with chain tongs.
Make up all outer barrel joints with pipe tongs. No more than three
wraps on the cat-head are recommended. If a torque indicator is
available on the rig floor then the make up values below should be
observed.
All threads on Eastman Christensen core barrels are right hand threads.
When the barrel is to be transported or laid down for a long period, all
outer barrel threads should be broken loose in order to facilitate the
maintenance and removal.
When making up all joints clean and dope threads.
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Core Bbl. Size
(Inches)
4.75 x 2.625
6.75 x 4.0
2.2
Normal Make-up
Torque (ft-lb)
4,700
11,100
Rough Drilling
Make-up Torque
5,800
13,900
Yield Torque
(ft-lb)
7,900
18,500
Core Barrel Pick-up
The following is a step by step procedure on how to pick up a core barrel.
A)
B)
C)
D)
E)
F)
G)
H)
I)
J)
K)
2.3
Pick up the lower section.
Run the lower section through the rotary table and set the slips and
safety clamp on the outer section.
Remove the pickup sub from the outer barrel.
Lift the inner barrel one-foot above the outer barrel, and place the clamp
on the inner barrel.
Remove the pick up sub from the inner barrel.
Tighten the pickup sub into the upper section at the safety joint, and
pickup with elevators.
Remove the protector sub from the outer barrel and the inner tube cap
from the inner barrel, and tighten the inner barrels.
Raise the elevators and remove the inner barrel clamp. Lower the upper
barrel and tighten the outer barrel. Remove the safety clamp on the
outer barrel.
Lower the barrel to the stabilizer and tighten, then attach the safety
clamp.
Remove the inner barrel at the safety joint. If the barrel has been run,
check the points to be checked before each core is cut, and inspect the
bearing. If undue damage or wear is apparent, then the bearing should
be replaced.
Tighten the safety joint and remove the barrel from the hole. Remove
the protector sub, place the core bit on the barrel and tighten. On the
first run or after each bit change, the adjustment shims should be
checked. To run a 90-ft. barrel, it is suggested that a top section be
used. Lay down the safety joint and the bearing assembly and add one
top section. Recheck spacing if possible.
Coring Practices
The diamond bit or corehead should only be run into the well after the hole is
free of all obstructions and reaming is not necessary. If reaming is necessary,
ream with a drill bit. This should be done if any increased overpull is
experienced other than normal while pulling the bit out for the coring run, or if
the bit is pulled out undergauge. Repeat reaming procedure until no further
hole problems are experienced. This is due to the fact that reaming creates
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heavy loads and excessive heating that the watercourses are not designed to
cope with. If reaming is unavoidable, circulate at maximum rates, limit rotation
to 30 rpm, and weight on bit should be minimal.
Use a 60-ft. core barrel when cutting cores. If poor recovery is experienced,
consider using a 30-ft. core barrel, or core only 30 ft. with a 60-ft. barrel.
When cutting a large core, i.e. 5-1/4 in., 7-3/4 in., or 8 in., 30 ft. may be the
maximum core length because of potential handling constraints.
When coring is performed, in an 8-1/2 in. hole, use a 6-1/8 in. drilling jar in
the drill string. Space out using pup joint is necessary to ensure that coring
begins with a full kelly. After breaking the core, it frequently jams, therefore
maximum core recovery will be obtained in this manner.
Decreasing torque and increasing pump pressure are indicative of a
formation change. Decreases in pump pressure, torque and penetration rate
together indicate that the core has jammed. If pump pressure and torque
have increased simultaneously, an ‘O’ ring groove has developed. There is
no point in continuing to core if the rate of penetration (ROP) is slow, because
the core has jammed. If this is the case, the formation is being ground away
and not recovered.
When pulling out with a core barrel, do not rotate out. Use a pipe spinner.
3.0
WELLSITE GEOLOGIST REQUIREMENTS
3.1
Conventional Core Using a Metal Inner Barrel
3.1.1
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Equipment Requirements
A) Core trays
B) Core tags
C) Wire for tags
D) Rapidograph for marking tags
E) Magic marker for marking core trays
F)
Clip board
G) Geologic hammer
H) Tape measure, calibrated in feet and tenths of feet
I)
Core tray covers (wooden), wire, pliers
J)
Personal safety equipment
i.
Long sleeve shirt and pants
ii.
Safety hat
iii.
Safety glasses
iv. Safety shoes
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v.
3.1.2
Operations
A)
B)
3.1.3
Work gloves
Mark one end of each core tray with the tray number using the
magic marker (see figure below). Core trays are numbered in
sequence. Tray number 1 is the bottom of the core. Core
number 1 may have 10 trays, numbered 1-10, core #2 may have
24 trays marked 1 through 24, etc. Record this information on
the coring data sheet, an example is attached.
Arrive at the rig floor with trays and hammer in time to handle
the core as it is extracted from the barrel.
Numbering
Cores are numbered in sequence as they are cut. Core #1 will always
be the first core cut, core #2 the second core cut, etc. in each well.
3.1.4
Marking
Handling conventional cores during transport, examination and
analysis presents many opportunities to misplace or disorient core
samples. Marking conventional cores at the rig site with vertical lines
and depths will preserve the vertical orientation of the cores.
Wellsite geologists will be responsible for marking the core for
orientation and depth using the following procedure:
The core should be laid out, wiped dry, fitted and measured. Using
black and red felt tip magic markers, two adjacent vertical lines should
then be inscribed which should run the entire length of the core. When
viewed in the upright position, the red line should be on the right and
the black line on the left. Depths should be marked every six feet.
The above procedure should be carried out by wellsites as soon as a
core is laid down.
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Top of Core
Core Barrel
4
3
2
1
Bottom of Core
Core Trays with
Bottom Ends Numbered
AW XXX
Bottom End
of Core Tray
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CORE-3
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Extracting Core and Arranging Trays
FIELD:
WELL:
CORE#
FROM:
TO:
CORE CUT:
FT.
RIG:
CORE ENGINEER:
TRAY
NO.
23
22
21
20
19
18
17
16
15
14
13
12
11
10
9
8
7
6
5
4
3
2
1
AMOUNT
CORE
FROM
DATE:
RECOVERED:
FT.
FT.
INTERVAL
TO
GEOLOGIST:
%RECOVERED:
CORE HEAD:
REMARKS
N.R.
TOTAL
Coring Data Sheet Form
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RED LINE
BLACK LINE
6221'
6222'
Marking Conventional Cores
CORE DATA
DATE ....................
FIELD ...............................
WELL NO .........................
CORE NO .........................
FROM ........... TO............
RECOVERED ........................FT.
GEOLOGIST .........................
DEPTH OF CORE THIS TRAY
FROM ......... TO .............
TRAY ___ OF ____
TRAY NO. 1 IS BOTTOM CORE
Standard Aramco Core Tag
3.2
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Conventional Core Using a Fiberglass Inner Barrel
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After the core has been cut, the barrel is pulled to the surface. The outer
barrel with the diamond corehead attached to its lower end is held in the slips
and the inner barrel containing the core is taken out of the outer barrel and
laid down on the catwalk. Then the fiberglass with the core inside is marked
and cut in 2.7-ft. sections. Each section should be properly marked with ‘T’ for
top and ‘B’ for bottom, to keep the orientation in order (see diagram below).
The numbering of each section of the tube should be the same as previously
mentioned for the trays.
Generally in Exploration wells the core from each fiberglass tube is
transferred to the metal trays and labeled as mentioned previously above. In
Development wells the cores are kept in the fiberglass, closing both ends with
rubber caps and marked as shown below.
11
Rubber
Cap
10
T
9
7
HWYH-200 C#1
TUBE#6
8
6
B
5
Rubber
Cap
4
3
2
Cut Here
1
Schematic Diagram Showing How to Mark, Cut and Label Fiberglass Core
3.3
Preserved Cores
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Preserved cores preserve freshly cut cores against drying, oxygen exposure
and bacterial action by sealing the cores immersed under deoxygenated
brine. The core is preserved to maintain reservoir characteristics of core
samples and consequently to improve the quality of data obtained through
laboratory core analysis.
3.3.1
Procedure
A)
Materials Neededi.
PVC core tube for each section (2.7-3.0 ft. lengths)
ii.
Sodium Chloride
iii.
Calcium Chloride
iv. Magnesium Chloride
v.
Sodium Metabisulfite
vi. Nitrogen Cylinder
vii. Regulator with plastic hose
viii. Water
ix. Strap wrench
x.
Magic markers
xi. Bucket
xii. Weighing balance
B)
Mixing Procedure1)
Prepare the brine by combining the following components
in the following proportions.
i.
NaCl
58.5 lbs. for each barrel (42 gallons)
ii.
CaCl2, 2H2O
12.6 lbs. For each barrel
iii.
MgCl2, 6H2O
4.2 lbs. For each barrel
iv. Na2S2O5 1.3 gms. (for each tube, added before
closing the tube. This is not added with the bulk
mixture)
2)
PVC tubes are labeled with the following information:
3)
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i.
Well Name & Number
ii.
Core Number
iii.
Tube Number
iv. Interval (amount of core in the tube)
As the core is removed from the core barrel, it is laid in the
metal core trays which are filled with water (preferably the
same brine which will be used to preserve) to prevent from
drying and oxygenating.
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3.4
4)
Place the core in the PVC tube and fill the tube with brine.
Leave only a small gas space to allow for thermal
expansion.
5)
Deoxygenate the brine in the tube and displace air from
the top of the tube by bubbling Nitrogen into the bottom of
the tube for 10 minutes.
6)
Shortly before the nitrogen purge is completed, add
Sodium metabisulfate to the tube (amount mentioned
above) as an oxygen scavenger.
7)
Close the cap tightly.
Transporting Cores to Dhahran
Cores are very expensive and contain valuable information, so the proper
handling of them is essential. The following steps should be observed when
shipping cores:
A)
B)
C)
D)
Each metal tray with core should be covered with a wooden top and
tied up properly so that no piece of core can fall during loading and
unloading.
Cores collected in fiberglass tubes should be capped from both ends
with the right size of cap and re-inforced with metal rings. The
fiberglass tubes should be strapped on a wooden palette before
shipping.
Preserve core tubes should be kept in an upright position in a metal
basket.
The rig foreman arranges for sending the cores and he should
prepare a shipping manifest stating the number of tubes/trays and
address the shipment to:
CORE STORAGE BUILDING # 3170, DPC-155, DHAHRAN
The well site geologist will report details of the shipment in his
morning report.
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DRILLING OPTIMIZATION
1.0
DRILL BITS
1.1 IADC Bit Classification
1.2 Bit Selection
1.3 PDC Bit Running Procedure
2.0
MOTORS & TURBINES
3.0
DRILL-OFF TESTS
4.0
HYDRAULICS
1.1 Hydrostatic Pressure
1.2 Frictional Pressure Determination
1.3 Optimization of Bit Hydraulics
1.4 Onsite Nozzle Selection
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DRILLING OPTIMIZATION
1.0
DRILL BITS
1.1
IADC Bit Classification
Roller cone drill bits are classified by a three-digit IADC code. The first
number is called the series. Series 1 through 3 is for milled tooth bits. Series
4 through 8 is for insert bits. The following table depicts what type of
formation each series is best suited to drill.
SERIES
1
2
3
4
5
6
7
8
FORMATIONS
Soft formations with low compressive strengths and high drillability.
Medium to medium hard formations with high compressive strength.
Hard semi-abrasive and abrasive formations.
Soft formations with low compressive strengths and high drillability.
Soft to medium formations with low compressive strength.
Medium hard formations with high compressive strength.
Hard semi-abrasive formations with high compressive strength.
Extremely hard & abrasive formations.
The second numeral in the bit IADC classification is the bit type, these
numbers range from 1 to 4 and sub-divide each series from soft to harder.
For example a 1-2 type bit is slightly softer than a 1-3 type bit.
The third and final number in the bit IADC classification is the feature. The
following table shows what each feature represents.
Features
1
2
3
4
5
6
7
8
9
Standard
roller
bearing.
Roller
bearingAir.
Roller
bearing,
gage
protected.
Sealed
roller
bearing.
Sealed roller
bearing,
gage
protected.
Sealed
friction
bearing
Sealed
friction
bearing,
gage
protected.
Directional
Other
Therefore, a bit with an IADC code of 5-3-7 is for a bit that will drill soft to
medium formations with low compressive strengths and has a sealed friction
bearing with gage protection.
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1.2
Bit Selection
The selection of the best available bit for a given job, like the selection of
drilling fluid or drilling cement composition, can only be determined by trial
and error. Fortunately in Saudi Aramco, there is sufficient offset information to
effectively select the proper bits types for given formations, see chart on the
following page for some generalized IADC codes for given formation types.
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The initial selection of bit type in a wildcat area can be made on the basis of
what is known about the formation characteristics and its drillability. The
drillability of a formation is its measure of how easy the formation is to drill. It
is inversely related to the compressive strength of the rock. Drillability tends
to decrease with depth in a given area. The abrasiveness of the formation is
the measure of how rapidly the teeth of a milled tooth bit will wear when
drilling the formation. Shown in the following table is a listing of bit types often
used to drill various formations.
IACD Bit
Classification
1-1
1-2
5-1
6-2
1-3
6-1
2-1
6-2
2-3
6-2
3-1
7-2
3-2
3-4
8-1
Formation Description
Soft formations having low compressive strength and high drillability (soft shales
and clays and soft limestone and unconsolidated formations, etc.)
Soft to medium formations or soft interspersed with harder streaks (firm,
unconsolidated or sandy shales, anhydrite, soft limestones, etc.)
Medium to medium hard formations (harder shales, sandy shales, shales
alternating with streaks of sand and limestone, etc.)
Medium hard abrasive to hard formations (high compressive strength rock,
dolomite, hard limestone, hard slaty shales, etc.)
Hard semi-abrasive formations (hard sandy or chert bearing limestone,
dolomite, granite, chert, etc.)
Hard abrasive formations (chert, quartzite, pyrite, granite, hard sandstone, etc.)
When using a rollercone bit:
•
Use the longest tooth size possible.
•
A small amount of tooth breakage is tolerable rather than selecting a
shorter tooth bit.
•
When enough weight cannot be applied economically to a milled tooth
bit to cause self-sharpening tooth rear, a longer tooth size should be
selected.
•
When the rate of tooth wear is much less than the rate of bearing wear,
select a longer tooth size, a better bearing design or apply more bit
weight.
•
When the rate of bearing wear is much less than the rate of tooth wear,
select a shorter tooth size, a more economical bearing design or apply
less bit weight.
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Since bit selection is done largely by trial and error, it is important to carefully
evaluate a dull bit when it is removed from the well cannot be over stressed.
PDC bits are becoming more and more utilized for deep drilling applications.
When a PDC bit is called for in a drilling program the following procedure
should be followed.
1.3
PDC Bit Running Procedure
A)
Step I – Preparing the Hole
Preparation to run a PDC bit begins with examination of the previous bit
in the hole. If the old bit has just a few lost or damaged cutters/inserts,
there should be no problem as they will probably have been broken up
and embedded in the hole wall, or washed out during hole cleaning.
More severe damage, or a grossly undergauge bit means that the hole
should be conditioned with a roller cone bit and a junk basket. It is
generally a good drilling practice to use a junk basket during the last run
before going into the hole with a PDC bit.
B)
C)
Step II – Preparing the PDC Bit
•
Carefully remove the bit from its box and place it on a piece of
plywood or a rubber mat. Never roll or stand a PDC bit directly on
steel decking, like the rig floor, as PDC cutters are brittle and
easily chipped.
•
The bit serial number should be recorded, together with the bit
type and diameter.
•
The bit should be closely examined for damage possibly caused
during transit or if it’s a re-run bit. The inside of the bit should also
be inspected at this stage, in case any debris, which might block a
nozzle, is left inside.
•
Check that correct size nozzles are already in place.
Step III – Breaking In the PDC Bit
•
The bit should be rotated at low speed with no more than 60 RPM
to avoid premature damage to cutters while creating the bottom
hole pattern.
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•
The bit should be slowly set on bottom with no more than 4,000
lbs. weight on bit to establish a bottom hole pattern. If the bit does
not drill off after a few minutes, then the weight should be
increased until it does. This weight should be maintained until the
bit has drilled at least its own length.
•
The weight on bit can then be increased (up to the recommended
maximum weight on bit) until the desired penetration rate is
reached, or until an increase in weight no longer improves the rate
of penetration.
As a general rule, the optimum weight necessary for a PDC bit is less
than one-half that required for a roller cone bit. In extremely soft or
plastic formation, even at the light weight on bit and slow rotary speed
applied to establish the bottom hole profile, the bit will drill off quickly,
making the first few feet in only a few minutes. In harder formations it
may take considerably longer to drill the first foot. Since only some of
the cutters will initially be in contact with the formation until the bit has
bedded in, it is crucial that weight not be added too quickly, otherwise
these cutters may be overloaded and fail.
Other Useful Notes
Making Connections
When making connections, full flow should be maintained as the kelly is
raised. After the connection has been made, the bit should be washed
back to bottom slowly at full flow rate. The bottom must be approached
with care. Dropping the kelly too rapidly and the sudden braking of the
string, can cause the bit to tag bottom violently and be damaged as the
drill pipe stretches.
Optimizing Drilling
Conducting a series of tests at various weights on bit and rotary speeds
is the most reliable method of assessing the optimum values to achieve
the most satisfactory rate of penetration. If a formation change occurs
when drilling a long interval, the penetration rate usually changes as
well. If the rate decreases, the formation is probably harder, in which
case the rotary speed should be reduced and more weight applied to
the bit. If this results in a severe rise in torque, the weight should be
reduced and rotary speed increased. In essence, optimization results
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from experimenting with the parameters available. Bits will often yield
dramatic rates of penetration in the right application without being run at
optimum drilling parameters. It must be remembered that optimizing the
parameters (and thereby increasing rate of penetration) as conditions
change, can result in high overall cost per foot savings achieved by the
bit.
2.0
MOTORS & TURBINES
The phrase “Performance drilling” is a term used throughout the industry to
describe a downhole drilling system that is used to increase ROP. It is commonly
used to refer to high performance positive displacement motors (PDM’s) and
turbines utilized for straight hole drilling.
High performance PDM’s are motors that have extended power sections. The
additional power sections offer significantly higher torque - while maintaining bit
rpm - than conventional motors. The main advantages to using these types of
motors for drilling straight holes are as follows:
A)
Increase in penetration rates with associated rig cost savings.
B)
Reduced casing and drillstring wear and fatigue from lower rotary ROP. This
helps lower overall maintenance costs for the equipment involved.
C)
Accurate bottom hole positioning and lower survey costs (when MWD is used
in conjunction with a performance motor).
D)
Availability of personnel and equipment in remote areas to carry out quick
and accurate geological and/or mechanical sidetracking operations.
2.1
Considerations
In order to maximize the penetration rate the drilling parameters used must
be analyzed and agreed upon prior to starting the job. The primary factors
that influence performance will be the type of motor, the bit and the
hydraulics. Based on availability the bit should be matched to the motor or
vice versa. Factors to consider are:
•
•
Bit Type – number of blades, cutters, type and size of cutters, nozzles
Motor type – maximum speed and torque for the required bit and hole
size
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•
•
Hydraulics – attention should be paid to hole cleaning, pressure drops
and motor performance
Rig Pumps and pressure ratings – the rig must be able to offer
consistently high flow rates in order to maximize the speed and torque
available from the motor.
If the above factors are not optimized for the job then the maximum benefit
may not be derived from using a performance motor. As with all drilling
operations it is imperative that comprehensive pre-job planning is done
involving the PDM company, the bit supplier, the operator’s drilling
engineers/foreman and the drilling contractor in order to ensure the highest
probability of success.
3.0
DRILL-OFF TESTS
Frequent changes in lithology with depth can make it difficult to maintain a optimum
weight on bit. The drill-off procedure is a good method in which to determine the
optimum bit weight to use when drilling through a given formation type. A drill off
test consists of applying a large amount of weight to the bit, then locking the brake
and timing each 4 thousand pound decrease in the weight at a constant RPM. The
times are then plotted on graph paper and the optimum weight on bit can be
determined.
The following is a recommended drill off test procedure followed by an example.
A)
Choose a depth to run the drill off test where a section of uniform lithology is
expected.
B)
While drilling increase the bit weight approximately 20% over the weight that
was being drilled used and lock the brake.
C)
While maintaining a constant rotary speed, record the time it takes each time
the bit drills off 4,000# of bit weight. If the weight indicator is fluctuating, use
the mid-point. Continue the test until at least 50% of that weight is drilled off.
D)
Make a plot of ∆t vs. W.
E)
If time permits repeat the test using a different rotary speed and compare the
results.
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Example of a drill off test analysis.
B it W e ig h t
(1 0 0 0 # )
76
72
68
64
60
56
52
48
44
40
36
T o ta l T im e
(s e c )
0
52
105
152
210
281
352
432
522
626
746
D e lta -t
52
53
47
56
63
71
80
90
104
120
130
110
90
70
50
30
72 68 64 60 56 52 48 44 40 36
Bit Weight
From this example the optimum weight on bit for this formation type would be 64,000#.
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4.0
HYDRAULICS
4.1
Hydrostatic Pressure
The hydrostatic pressure of the drilling fluid is an essential feature in
maintaining control of a well and preventing blowouts. It is defined as the
static pressure of a column of fluid. The hydrostatic pressure of a mud
column is a function of the mud weight and the true vertical depth of the well.
Remember that the true vertical depth is used and not the measured depth.
The formula to calculate hydrostatic pressure in the units common for Saudi
Aramco is:
PH, psi = (mud weight, pcf) x (depth, ft) /144, in2/ft2
Where:
PH = hydrostatic pressure, psi
Drilling operations often involve several fluid densities, pressures resulting
from fluid circulating and induced surface pressures during kick control
operations. For practicality these different pressures are put into a common
descriptive system called “equivalent mud weight” or EMW. This provides the
same pressures in a static system with no surface pressure.
EMW = (total pressures X 144) / true vertical depth
Where: EMW is equivalent mud weight in pcf
4.2
Frictional Pressure Determination
The determination of pressure losses in the circulating system has been an
objective for almost as long as rotary drilling has been in existence. Pumping
a drilling fluid requires overcoming frictional drag forces from fluid layers and
solids particles. The summation of pressure losses in the entire circulating
system is shown at the surface pressure gauge, normally located on the
standpipe. The summation of pressure losses is:
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Ps= Pse + Pdp + Pdc + Pbit + Pdca + Pdpa
Pse
Circulation System and Normal Flow Patterns
As indicated in the above diagram, the total pressure is a result of frictional
pressure losses from the surface equipment, the drillpipe, the drillcollars, the bit,
the drillcollar annulus, and the drillpipe annulus. The total pressure gives no
indication whether the flow pattern in the system is laminar or turbulent. The flow
patterns inside the drillstring are usually turbulent while the flow pattern in the
annulus can be either. The pressure drop in the bit results from fluid acceleration
and not solely frictional forces.
Equivalent circulating density (ECD) is the fluid pressure the bottom of the hole
experiences while the mud is being circulated and should be considered,
especially when the formation being drilled through allows only small mud weight
tolerances and mud weights are critical.
ECD = Mud Density +
(PDPA + PDCA )× 144
Depth
11 of 20
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June 2006
DRILLING PRACTICES
DRILLING OPTIMIZATION
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4.3
Optimization of Bit Hydraulics
4.3.1
Introduction
The design of a hydraulics program is based upon maximizing
bottomhole cleaning using the least horsepower. Methods of design
being used include hydraulic horsepower and jet impact force. The
use of hydraulic horsepower is associated with the use of smaller jet
bits. Little attention was directed towards fluid circulation programs
before the introduction of jet bits in 1948. A comparison comes to
mind of someone cleaning sand off the driveway with a garden hose.
By using his thumb at the end of the hose, in front of the stream of
water and creating a jetting stream, he can more effectively clean the
sand off the driveway than by not using his thumb. In affect as he
reduces the nozzle size so he can blast more sand away then by not
reducing it.
For many years engineers have known that hydraulics play an integral
roll in cleaning the face of the formation so that a bit can drill faster.
This first became evident when larger pumps were introduced. They
increased the penetration rates because more fluid was being
pumped through the bit, thereby cleaning more cuttings away from
beneath the bit. This same theory can be applied at the bottom of a
drill string with bit jet nozzles. The purpose of the jet nozzles is to
improve the cleaning action of the drilling fluid at the bottom of the
hole. Before jet bits were introduced, rock chips were not removed
efficiently and much of the bit life was consumed regrinding the rock
fragments. Jet nozzles help to rid the bottom of the hole of these
cutting more effectively. There are two hydraulic models that should
be followed in order to optimize bit hydraulic horsepower, they are
listed below. Neither model has a clear advantage over the other, the
model used depends on the preference of the company man on the
rig.
4.3.2
Jet Impact Force Model
Field studies have shown that cross flow beneath the face of the bit is
the most effective parameter in hole cleaning. Cross flow is maximum
when jet impact force is maximum. The pressure loss across the bit is
simply the difference between the standpipe pressure and the
circulating pressure. For maximum jet impact force the pressure loss
across the bit should approximate 48% of the available surface
pressure. In other words if the available pump pressure is 3000 psi,
12 of 20
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June 2006
DRILLING PRACTICES
DRILLING OPTIMIZATION
___________________________________________________________________________________________________________________________
for a jet impact force hydraulic model, size the jet nozzles to create a
1440 psi pressure drop across the bit at the required flow rate. This
hydraulic model is usually applied where there is a limited amount of
available pump horsepower or surface pressure. For example, maybe
the kelly hose is only rated to 3000 psi or the pumps can only deliver
a limited amount of horsepower. In any case, the hydraulic model to
be used would be the impact force model.
4.3.3
Hydraulic Horsepower Model
Optimum bit hydraulics is obtained when, for a given flow rate, the bit
hydraulic horsepower assumes a certain percentage of the available
surface horsepower. For the maximum hydraulic horsepower model
the pressure loss across the bit should approximate 65% of the total
available surface pressure. In other words if the available pump
pressure is 3000 psi, for a hydraulic horsepower hydraulic model, size
the jet nozzles to create a 1950 psi pressure drop across the bit at the
required flow rate. This hydraulic model is usually applied where there
is an unlimited amount of available pump horsepower or surface
pressure.
4.3.4
Nozzle Selection
Smaller nozzles are always obtained when the hydraulic horsepower
model is used, it gives larger values of Pbit than those given with the
impact force model. The following equations may be used to
determine total flow area and nozzle sizes:
AT (in2) = 0.00342
dN = 32
ρQ 2
P
bit
⎞
⎛ 4A T
⎟
⎜⎜
3π ⎟
⎠
⎝
Where: AT is total flow area in (in2) and dN is nozzle size in multiples of
1/32 in.
13 of 20
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DRILLING OPTIMIZATION
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Example:
Calculate the bit nozzle sizes required for the following set of
conditions:
Mud weight:
Pump rate:
75 pcf
300 gpm
Pbit:
1000 psi
Solution:
AT (in2) = 0.00342
dN = 32
(75 )300 2
(4(0.281))
3(3.14 )
1000
= 0.281 sq. in.
= 11.05
Therefore three 11/32’s will jet this bit up properly.
4.4
Onsite Nozzle Selection
The flow regime through a rig’s mud system is disturbed by discontinuities in
the flow path (tool joints, jars, crossover subs, safety valves, washouts, tight
holes, etc.) Sometimes the flow is laminar, sometimes it’s turbulent. Each drill
string has it’s own unique flow path. For this reason hydraulic programs
developed prior to the well being drilled frequently call for the wrong bit
nozzles.
As the well is drilled, pressure losses can be determined with an experiment
at the rig after each bit is dulled. This is accomplished by the following
procedure:
Standpipe pressure is measured and recorded at three different pump rates,
one rate can be the drilling rate. Standpipe pressure (Psurf) consists of two
parts: (1) the pressure drop across the bit (Pbit), and (2) the rest of the
pressure loss through the system (Pcirc). Pbit can be determined from any
hydraulics manual. Subtracting the known values of the pressure drop across
the bit from the standpipe pressure leaves the pressure drop through the
system.
If Pcirc values are plotted on a log-log graph as a function of flow rate, the
slope u can be measured from the graph. In the graph below, pressures
recorded by the driller are shown with squares. The pressure drop through
the bit, Pbit, is subtracted at each flow rate. In this example, the line drawn
14 of 20
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June 2006
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DRILLING OPTIMIZATION
___________________________________________________________________________________________________________________________
through these points has a slope (u) of 1.6, that is the system pressure varies
as the 1.6 power of the flow rate (instead of 1.82).
On the same graph with Pcirc, the maximum pressure (Pmax) and available
hydraulic horsepower (Phhp) line should be added. The intersection of these
two lines determines the critical flow rate Qcrit. With the value of u, calculate
u +1
u
Phhp and
Pmax and draw
u+2
u+2
these optimum lines on the graph. The intersection of the Pcirc line with one of
these lines specifies the optimum circulating rate and pressure drop across
the bit. See the example below.
Example:
Given the following standpipe pressures and flow rates, graph the data then
determine the optimum pressure drop across the bit.
Q, gpm
200
300
500
Psurf, psi
621
1,245
3,000
If the three nozzles in the bit were 16/32 in., the
pressure drop through the bit for 112 pcf mud
would be:
Flow Rate, gpm
200
300
500
Pbit, psi
160
360
1,000
If these values are subtracted from the
standpipe pressure recorded by the driller, the
pressure drop through-out the rest of the
system is obtained:
Flow Rate, gpm
200
300
500
Pcirc, psi
461
885
2,000
hhp=1071 hp
5000
Pmax
3000
Pbit
2000
Pressure drop
through the
system
Press, PSI
1000
800
600
400
300
Slope = 8/5
U = 1.6
200
100
100
200
300
400
Flow Rate, GPM
15 of 20
600
800
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DRILLING OPTIMIZATION
___________________________________________________________________________________________________________________________
The pressure drop accounts for all the hole discontinuities, changes in mud
rheology throughout the circulating system, changes and discontinuities in the
drillstring configuration, and all surface pressure losses.
These data are plotted in the figure above. Data also recorded by the driller
are also plotted but is not necessary to be plotted. Corresponding bit
pressure drops are subtracted from each point and a straight line is drawn
through the points (represented as circles in the above graph). Because the
configuration of the borehole and the drillstring currently being used is known,
pressure losses can be anticipated for any flow rate.
Unlimited surface pressure (or hydraulic horsepower limit) will be considered
in Case 1 and limited surface pressure in Case 2. To find the optimum
pressure at the bit, the following equations can be used:
Case 1
Pbit=
u +1
Phhp
u+2
= 0.772 Phhp
Case 2
Pbit opt =
u
Pmax
u+2
= 0.444 Pmax
For Case 2 the optimum pressure drop across the bit is 44.4% of the
maximum pressure instead of 47.6%, which would be the drop if a u value of
1.82 is used. If the maximum standpipe pressure is 3,300 psi then:
Pbit = (0.444) (3,300) = 1,465 psi
The pressure drop in the circulating system (Pcirc) should be 1835 psi.
Looking at the graph, a pressure drop of 1835 psi through the system
indicates that the flow rate must be 474 gpm.
Although 1,071 hhp is available, only a portion can be used because of the
maximum surface pressure limitation. Therefore using equation 28,
hhp = (3,300 psi) (474 gpm) / 1714 = 913 hp
For a bit pressure drop of 1465 psi, a flow rate of 474 gpm and with 112 pcf
mud, using:
16 of 20
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DRILLING OPTIMIZATION
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AT (in2) = 0.00342
ρQ 2
Pbit
AT (in2) = 0.448 in2
dN = 32
4A T
3π
dN = 13.96, or three 14’s.
Therefore the next bit will require three 14’s instead of the three 16’s that are
currently in the bit. When the surface pressure reads 3,300 psi, the flow rate
has to be 530 gpm through the 16/32 in. nozzles, instead of the 474 gpm
through the 14/32 in. nozzles.
Nozzle inside diameter tolerances are not very tight, therefore for the most
accurate results, the nozzles should be measured with a micrometer prior to
running in the well. At very high flow rates, a small difference in the diameter
could result in several hundred psi difference in pressure.
Field Implementation
Using this method in the field can best be accomplished by the engineer
providing the foreman with a graph having the limits already drawn. For
example, for a rig that has two 1,200-kW motors, each driving a triplex pump.
The maximum standpipe pressure permitted is 3,000 psi. Assume that the
driller has just drilled to a depth of 8294 ft with 74.8 pcf mud in the hole and is
ready to pull out for a bit trip. If the drilling engineer has been thoughtful
enough to provide a chart, the foreman’s next steps are easy.
First, the electrical power driving the pumps is translated to horsepower:
⎡
hp
⎤
= 1,609 hp
1,200kW ⎢
⎣ 0.7457kW ⎥⎦
Second, the efficiencies of the mechanical drive and the volumetric
displacement of the pump are used to reduce input power to output hydraulic
horsepower:
(1,609hp )(0.85 )(0.93 ) = 1,272 hhp
Third, the hydraulic horsepower is drawn on the log P-log Q graph (see figure
below). Arbitrary flow rates are selected and the associated pressures
calculated, providing the points to draw the chart.
17 of 20
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The maximum hydraulic horsepower curve is generated from equation 28:
PQ
= 1,272hhp
1,714
For example, if Q = 1000 gpm,
P=
(1,272hhp) (1,714)
= 2,180psi
1000
And at Q = 300 gpm,
P=
(1,272hhp) (1,714)
= 7,267psi
300
Maximum surface pressure was given as 3,000 psi, therefore the hhp line is
constructed on the graph. As a check Qcrit may be calculated then checked
on the graph.
Q
18 of 20
crit
=
(1,272hhp) (1,714)
3000psi
= 727gpm
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Minimum and maximum flow
rates could be included. These
values are usually arbitrary
guidelines set up by each
company. Actual minimum flow
rates to clean the hole must be
determined on site.
Suppose that just before the
driller pulls out of the hole, he
determines
the
standpipe
pressure at several pump rates
with jet nozzle sizes of one
14/32-in and two 15/32-in
nozzles in the bit. The rig is
equipped with Emsco-FA-1300
pumps with 6-1/2” liners. With
pump rates of 70, 90, and 100
spm, the standpipe pressures
were 1,180, 1,840, and 1,210
psi respectively. The driller’s
normal operating pump rate is
120 spm with 3,000 psi
standpipe
pressure.
He
determined from a hydraulics
book that:
Stroke rate, spm
Flow rate, gpm
Standpipe pressure, psi
Bit pressure, psi
Circulation pressure, psi
70
361
1,225
490
735
8000
7000
5000
Maximum Surf. Press.
3000
1,272 hhp
Line
2000
Press, PSI
1000
800
600
400
300
200
100
100
200
300
400
600 Qcrit 1000
Flow Rate, GPM
90
465
1,850
810
1,040
100
517
2,200
1,000
1,200
120
620
3,000
1,440
1,560
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DRILLING OPTIMIZATION
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The slope is found to be 1.4 after plotting Pcirc verses the flow rate.
⎡
⎤
⎞ P max indicates that the
Calculation of the optimum bit pressure loss ⎢⎛⎜
⎟
⎥
⎣⎝ u + 2 ⎠
⎦
u
maximum hydraulic impact will be achieved if the 1,235 psi drop occurs at the
bit. This leaves 1,765 psi for the pressure loss through the circulating system
(Pcirc), which can be obtained by pumping 680 gpm. With this flow rate, 680
gpm, and the 1,235 psi bit pressure drop, therefore:
AT (in2) = 0.00342
dN = 32
75 × 680 2
= 0.573
1235
4 × ( 0.573)
= 15.8
3 × 314
.
the nozzle sizes are determined to be three 16/32-in. nozzles.
8000
7000
5000
Maximum Surf. Press.
3000
1,272 hhp
Line
2000
Press, PSI
∆P circ opt
1000
7 in.
800
600
P circ
400
5 in.
Slope=7in/5in = 1.4
300
u
∆P
=
P
bit opt
u + 2 max
200
=
1. 4
3. 4
( 3000 psi ) = 1, 235 psi
∆P
= 1, 765 psi
circ
100
100
200
300
400
Flow Rate, GPM
20 of 20
600
1000
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SURFACE AND DOWNHOLE PLUGS
___________________________________________________________________________________________________________________________
SURFACE AND DOWNHOLE PLUGS
1.0
TYPES OF PLUGS
1.1 Back Pressure Valves
1.2 Polymer Plugs
1.3 Cement Plugs
1.4 BOP Test Plugs
1.5 Mechanical Downhole Plugs
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SURFACE AND DOWNHOLE PLUGS
___________________________________________________________________________________________________________________________
SURFACE AND DOWNHOLE PLUGS
1.0
TYPES OF PLUGS
Several types of plugs are used for many purposes in the Oil Industry. Saudi Aramco
Drilling and Workover commonly uses Back Pressure Valves and Two-way Check
Valves, Chemical Plugs, Balanced Cement Plugs, BOP Test Plugs and Mechanical
Downhole Plugs. These different plugs are used as safety barriers while installing, or
removing, well control and production equipment and as test plugs when pressure
testing equipment. When removing surface control equipment it must be replaced with
downhole isolation barriers. Plugs are the most commonly used isolation barrier.
Please refer to GI 1853.001, Isolation Barriers For Wells During Drilling and Workover
Operations (With and Without Rig) for the required number and type of plug to be used.
1.1
Back Pressure Valves
Back Pressure Valves are set in a special profile in the tubing hanger. They
are normally used while installing or removing production trees and BOP
equipment. Two way check valves can be installed in the same profile and
are used to test the equipment. A two way check valve shall only be used to
test equipment after it is installed, not during installation or removal
operations. This is because it is possible to pump kill weight fluids through a
back pressure valve but not through the two way check valve. More details
on these plugs and installation and removal procedures may be found in
Chapter 2-E, WELLHEAD, Section 4.0.
1.2
Polymer Plugs
Polymer plugs may be spaced across perforations and used as an additional
safety device when performing unusual well servicing. They are more
commonly used for temporarily or permanently healing lost circulation. More
details on these plugs may be found in Chapter 2-F, LOST CIRCULATION,
Section 5.0, Polymer Plugs. Whenever using polymer plugs it is important to
emphasize the need to (a) tailor the plug design for the well conditions, (b)
laboratory test the plug to fine-tune the polymer additive concentrations, and
(c) ensure satisfactory polymer plug performance.
1.3
Cement Plugs
Cement plugs may be spotted in casing or, in some cases tubing, and used
as an additional barrier during unusual well servicing operations. More
details on these plugs may be found in Chapter 2-F, LOST CIRCULATION,
Section 5.0, Cement Plugs.
1 of 5
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1.4
BOP Test Plugs
BOP Test plugs are designed to be installed in a casing head, casing spool or
tubing spool to provide a bottom seal while testing BOPE. They are designed
and built to fit one size head or spool made by one Manufacturer. For
example, if you have a Cameron 13-5/8” 3M casing head you must use a
Cameron 13-5/8” BOP test plug. If you have a Gray 13-5/8” 3M casing head
you must use a Gray 13-5/8” BOP test plug. These plugs may not be
interchanged. The preferred running procedure is to make up at least one
stand of drill pipe below the plug, preferably hevi-weight. The elastomer seal
on the O.D. of the plug should be visually inspected and a coat of grease or
pipe dope applied prior to running.
1.5
Mechanical Downhole Plugs
Downhole or “wireline” plugs are used on
a daily basis in Saudi Aramco operations.
These types of plugs, along with the back
pressure valve, are used as isolation
barriers after the completion string has
been run. The most commonly used
wireline plugs are the X locking mandrel
and the R locking mandrel. In order to
use these plugs there must be a mating X
or R landing nipple installed in the
completion string. Typically the X nipple
is installed in normal weight tubing strings
and the R nipple in heavy weight tubing
strings.
Figure 2J-1 shows the R and X models of
landing nipples and lock mandrels. The
nipples are selective nipples as they will
allow a plug to pass through them and it
can be set in a nipple below, or in the
selective nipple.
Figure 2J-2 shows XN and RN no-go
landing nipples and lock mandrels. These
nipples are termed no-go because they
have an internal profile that will not allow
the plug to pass below the nipple, and
thus it can only be set in that specific
nipple.
2 of 5
Figure 2J-1: Selective Nipples and Lock Mandrels
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Saudi Aramco uses the PX and PXN
plugs almost exclusively. These plugs
come equipped with a pressure
equalization valve and matching prong.
They are set in X, selective, and XN,
no-go, nipples.
These plugs are installed in two trips.
On the first trip the plug is ruin without
the prong. The prong is then inserted
on the second trip, sealing the
equalization ports and preventing sand
or fill from falling into the interior of the
plug.
The plugs are retrieved in two trips, the
prong on the first. This provides an
equalization path and prevents the plug
from being blown uphole.
IF it is desirable to make only one trip
XX or XXN plugs may be run. These
plugs are run or retrieved and the
equalizing ports opened or closed in
one trip.
All of these plugs may be run and
retrieved on coiled tubing.
This
method would be desirable in a
horizontal or highly deviated well.
Figures 2J-3 and 2J-4 are tables listing
the common sizes of landing nipples
and
lock
mandrels
available.
Remember to always double check the
size before attempting to run a plug.
Figure 2J-2: No-Go Nipples and Mandrels
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Figure 2J-3: X and XN Nipple and Mandrel Dimensions
X® and XN Landing Nipples and Lock Mandrels Specifications
For Standard Tubing Weights
X® Profile
XN Profile
Lock Mandrel ID
Packing Bore
ID
Drift
Packing Bore
No-Go ID
in.
mm
in.
mm
in.
mm
in.
mm
in.
mm
in.
mm
0.824
20.93
0.730
18.54
Available on Request
1.049
26.64
0.955
24.26
Tubing
Size
in.
mm
1.050 26.67
1.315 33.40
1.66 42.16
1.900 48.26
2.063 52.40
2.375 60.33
2.875 73.03
3.500 88.90
4.000
4.500
5.000
5.500
101.60
114.30
127.00
139.70
4 of 5
Weight
Ib/ft kg/m
1.20 1.79
1.80 2.68
2.30 3.43
2.40 3.57
2.40 3.57
2.76 4.11
2.90 4.32
3.25 4.84
4.60 6.85
4.70 7.00
6.40 9.53
6.50 9.68
9.30 13.85
10.20 15.34
11.00 16.38
12.75 18.99
13.00 19.36
17.00 25.32
1.38
35.05
1.660
42.16
1.29
32.66
1.250
31.75 1.250 31.75 1.135 28.83
1.610
40.89
1.751
0.620
15.75
1.516
38.51
1.500
38.10 1.500 38.10 1.448 36.78
0.750
19.05
44.48
1.657
42.09
1.625
41.28 1.625 41.28 1.536 39.01
1.995
50.67
1.901
48.29
1.875
47.63 1.875 47.63 1.791 45.49
1.000
25.40
2.441
6,200
2.347
59.61
2.313
58.75 2.313 58.75 2.205 56.01
1.380
35.05
2.992
2.922
3.476
3.958
4.494
4.892
76.00
74.22
88.29
100.53
114.14
124.26
2.867
2.797
3.351
3.833
4.369
4.767
72.82
71.04
85.10
97.36
110.97
121.08
2.813 71.45 2.813
2.750 69.85 2.750
3.313 84.15 3.313
3.813 96.85 3.813
4.313 109.55 4.313
4.562 115.87 4.562
1.750
44.45
2.120
53.85
2.620
66.55
3.120
79.25
71.45
69.85
84.15
96.85
109.55
115.87
2.666
2.635
3.135
3.725
3.987
4.455
67.72
66.93
79.63
94.62
101.27
113.16
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SURFACE AND DOWNHOLE PLUGS
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Size
in.
1.660
1.900
2.375
2.875
3.500
4.000
4.500
5.000
5.500
6.000
6.625
7.000
8.625
Landing Nipples And Lock Mandrels Selective By Running Tool
R® And RN® Landing Nipples And Lock Mandrels Specifications
For Heavy Tubing Weights
Tubing
Lock Mandrel ID
R® Profile
RN® Profile
Weight ID
Drift Packing Bore
Bore
ID
Ib/ft
in.
in.
in.
in.
in.
in.
3.02 1.278 1.184
1.125
1.125
1.012
on Req.
3.64 1.500 1.406
1.375
1.375
1.250
0.620
5.30 1.939 1.845
1.781
1.781
1.640
0.880
5.95 1.867 1.773
1.710
1.560
1.710
0.750
6.20 1.853 1.759
7.70 1.703 1.609
1.500
1.500
1.345
0.620
7.90 2.323 2.229
2.188
2.188
2.010
1.120
8.70 2.259 2.165
2.125
1.937
2.125
0.880
8.90 2.243 2.149
9.50 2.195 2.101
2.000
2.000
0.880
1.881
10.40 2.151 2.057
11.00 2.065 1.971
1.875
1.875
0.880
1.716
11.65 1.995 1.901
12.95 2.750 2.625
2.562
2.562
2.329
1.380
15.80 2.548 2.423
2.313
1.120
2.131
2.313
16.70 2.480 2.355
17.05 2.440 2.315
2.188
2.188
2.010
1.120
11.60 3.250 3.303
3.250
3.250
3.088
1.940
13.40 3.340 3.215
3.125
3.125
2.907
1.940
12.75 3.958 3.833
3.813
3.813
3.725
2.120
13.50 3.920 3.795
3.688
2.380
3.456
3.688
15.50 3.826 3.701
16.90 3.754 3.629
3.437
1.940
3.260
3.437
19.20 3.640 3.515
15.00 4.408 4.283
4.125
4.125
3.912
2.750
18.00 4.276 4.151
4.000
4.000
3.748
2.380
17.00 4.892 4.767
4.562
2.850
4.445
4.562
20.00 4.778 4.653
23.00 4.670 4.545
4.313
4.313
3.987
2.620
15.00 5.524 5.399
5.250
3.500
5.018
5.250
18.00 5.424 5.299
24.00 5.921 5.795
3.500
5.625
5.500
5.625
28.00 5.791 5.666
17.00 6.538 6.431
20.00 6.456 6.331
23.00 6.366 6.241
3.750
5.963
5.770
5.963
26.00 6.276 6.151
29.00 6.184 6.059
32.00 6.094 5.969
35.00 6.004 5.879
5.875
5.875
5.750
3.750
7.050
7.050
6.925
5.250
36.00 7.825 7.700
7.250
7.250
7.125
5.250
7.450
7.450
7.325
5.250
Figure 2J-4: R and RN Nipple and Mandrel Dimensions
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POSITIVE DISPLACEMENT MOTORS
1.0 INTRODUCTION
2.0 POSITIVE DISPLACEMENT MOTORS
2.1
2.2
PDM Operating Principles
Aramco Utilization
SAUDI ARAMCO
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POSITIVE DISPLACEMENT MOTORS
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POSITIVE DISPLACEMENT MOTORS
1.0
INTRODUCTION
Two of the most intriguing questions for drilling personnel are (1) what bit, bottom
hole assembly and rotational method (drilling system) is optimal for a given hole
section and (2) what are the optimal operating parameters for that system? For
Saudi Aramco drilling operations the short list of drilling systems include:
1)
2)
3)
4)
5)
Rotary and Rock Bit
Rotary and PDC
PDM and Rock Bit
PDM and PDC
Turbine and PDC
The purpose of this section and the following sections on Turbines and
Performance Drilling Systems Optimization is to present the essential operating
parameters and requirements which best utilize each drilling system.
2.0
POSITIVE DISPLACEMENT MOTORS
The Moineau Pump was patented
in 1926 by the French Engineer
Rene Moineau. The Moineau pump
or more commonly called the
progressing cavity pump gained
wide scale utilization in artificial lift
applications for shallow to medium
depth oil and water wells. It is also
used for surface transfer of solids
laden fluids. The progressing cavity
pumps were found capable of
handling, high viscosity, solids and
sand laden fluids more effectively
than conventional oilfield rod
pumping
units
and
Electric
Submergible Pumps (ESP).
A
Progressing Cavity pumping system
is shown in Fig 2K-1.
Figure 2K-1 Progressive Cavity Pumping System
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The progressive cavity pumps work by turning a single external-helix steel rotor
inside a double internal helix elastomeric stator. The rotary action of the steel rotor
forms cavities that progress upward from the bottom of the hole through the pump
and tubing to the surface.
The Positive Displacement Motor, (PDM), which was commercially introduced in
1966 by Smith Tool Co. as the "Dynadrill" motor, works on the reverse application
on the Moineau pump principle. Instead of turning a rotor inside a stator assembly
from the surface to pump fluid through the tubing up-hole, fluid is pumped from the
surface into the Drillstring to turn a rotor inside a stator assembly down-hole. The
PDM rotor is attached to a transmission and drive shaft assembly that in turn
impart rotational motion to the drill bit.
PDM's were field tested in California in 1962 as part of a directional drilling system.
The application of the PDM and bent-sub assembly provided the first practical
capability for developing offshore California fields from onshore. PDM usage
quickly spread to the Gulf of Mexico where they were used for directional
applications from offshore drilling rigs. PDM's continued to evolve over the next 30
years with the development of Tandem, Extended Power Section and Articulated
motors into the steerable systems we know today.
2.1
Principles of Operation
In a positive displacement motor, pressurized circulating fluid is pumped into
a progressing axial cavity formed between a helically lobed metallic rotor and
a helically lobed elastomeric stator.
The force of the pressurized circulating fluid pumped into the cavity between
the rotor and the stator cause the rotor to turn inside the stator. The action of
the rotor and stator converts the hydraulic energy of the circulating fluid to
mechanical energy (rotation) which is transferred to the drill bit via a
transmission and drive shaft assembly.
Modification of lobe numbers and geometry at the design stage provides for
variation of motor input and output characteristics to accommodate various
drilling requirements.
PDM's consist of six main components: (1) Dump Sub (2) Power Unit (Rotor
& Stator), (3) Bent Housing, (4) Transmission Unit, (5) Bearing Section
Assembly and (6) Tubular Housings and Stabilizers as shown in Fig 2K-2.
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Figure 2K-2 - Positive Displacement Motor (5/6 Lobe Configuration with
fixed bent housing)
Dump Sub
The geometry of the rotor/stator power unit prevents fluid flow between the
Drillstring and annulus during tripping operations. A dump sub can be
incorporated above the power unit in the motor assembly to allow the
Drillstring to fill when tripping in the hole and empty when tripping out of the
hole, thereby avoiding wet trips. The dump sub also permits low rate
circulation if required.
The dump sub contains a valve, which is ported to allow fluid flow between
the Drillstring and annulus. The dump valve assembly is of a sliding piston
and spring design, with all parts manufactured from high quality steels. When
circulation rates are low or when there is no circulation rate for the motor, the
piston moves down, closing the bypass ports. Drilling fluid is then directed
through the motor section. When circulation stops, the bypass piston is
released and the bypass ports reopen. Most multi-lobe motors 3-3/8" and
larger are equipped with hollow rotors, thus lessening the requirement for the
dump sub.
Figure 2K-3 - Dump Sub Assembly
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For performance drilling in larger diameter hole sections, adding a rotor
nozzle allows increasing the total flow rate to clean the hole and remove
cuttings. Nozzled rotors cause more fluid to be circulated around the bearing
assembly and less directly through the rotor/stator cavity, thereby reducing
rotational speed. This decrease in bit speed while maintaining high circulation
rate is necessary for special applications such as spudding, under-reaming or
hole opening in large hole sizes.
A simple hydraulics calculation is used to determine the size of the rotor
nozzle required.
RTFA=
Q2 x MW 0.5
P x 10,858 ..........................................................................Eq. 2K-1
Where: RTFA = total flow area for Rotor Nozzle (nozzle size, sq. in.)
Q = amount of flow to bypass (gpm)
MW = mud weight (lb/gal)
P = expected differential drilling pressure + friction pressure (psi)
Friction pressure is generally 125 psi for
motors and 150 psi for 3.5" and smaller motors.
4.75"
and
larger
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Figure 2K-3 - Nozzled Rotor
Power Section
In the power section of a PDM, a rotor/stator pair convert the hydraulic
energy of the pressurized circulating fluid to mechanical energy in the rotating
shaft. In addition, the action of the circulating fluid imparts hydraulic
downthrust on the rotor.
Like the Progressive Cavity Pumps, PDM's can accommodate various
circulating fluids, including oil-based muds; water based muds, water, air and
foam while producing the output characteristics required to achieve
successful drilling operations.
However, high fluid corrosivity and
abrasiveness tend to accelerate stator wear.
The rotor and stator lobe profiles are similar; with the steel rotor having one
less lobe than the elastomeric stator. Motors are generally available in 1:2,
3:4, 4:5, 5:6, 7:8 and 9:10 configurations, as depicted in Fig 2K-4.
Figure 2K-4 - Common Rotor/Stator Configurations
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Figure 2K-5 – 4-3/4, 6-3/4, 8 and 9-5/8” PDM Rotors prior to installation
In most cases, the higher the number of lobes, the higher the torque output of
the motor and the slower the speed.
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Power units are generally categorized with respect to the number of lobes
and effective stages. One power unit stage is represented by the linear
distance of a full " wrap" of the stator helix, as shown in Fig 2K-6.
Figure 2K-6 - Spiral Stage Length
The difference between the number of lobes on the rotor and the number of
lobes in the stator results in an eccentricity between the axis of rotation of the
rotor and the axis of the stator.
The rotor/stator lobes and helix angles are designed such that the rotor/stator
pair seal at discrete intervals. This results in the creation of axial fluid
chambers or cavities, which are filled by the pressurized circulating fluid.
The action of the pressurized circulating fluid causes the rotor to rotate and
precess within the stator. The lobe geometry and amount of eccentric rotor
movement is designed to minimize contact pressure, sliding friction, abrasion
and vibration thus reducing rotor and stator wear.
The movement of the rotor inside the stator is called nutation. For each
nutation cycle made by the rotor inside the stator the rotor turns/ratchets the
distance of one lobe width. The rotor must nutate for each lobe in the stator
to complete one revolution of the bit box.
For example, a motor with a 5:6 rotor/stator lobe configuration and a speed of
100 rpm at the bit box will have a nutation speed of 500 cycles per minute.
The elastomeric stator is injection molded with detailed attention given to
elastomer composition consistency, bond integrity and lobe profile accuracy.
The stator is molded directly to the power unit housing.
The metallic rotor is precision machined to close axial and radial tolerances
and can be coated with chromium or ceramics to maximize wear and
corrosion resistance. Most rotors used in Saudi Aramco operations are
coated with a thin, typically 0.01" layer of hardened chromium to provide a
smooth outer surface which minimizes wear and abrasion to the elastomeric
stator. However, corrosive drilling fluids may cause pitting of the chrome
layer as shown in Figure 2K-11. This type of damage actually accelerates
stator wear. If drilling fluid properties cannot be altered, then tungsten
carbide rotors may yield longer stator life.
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Within the specified motor operating ranges, bit rotation speed is directly
proportional to the circulating fluid flow rate between the rotor and stator.
Above the maximum specified operating differential pressure, fluid leakage
occurs between the rotor and stator seals and bit rotation speed decreases.
Excessive fluid leakage results in "stalling", as the rotor stops rotating within
the stator.
Similarly, within the specified motor operating ranges, motor output torque is
directly proportional to the differential pressure developed across the rotor
and stator. If the motor is operated above the maximum specified torque
production values, there can be a tendency for accelerated rotor/stator wear
and stalling may occur.
The power developed by the rotor and stator is directly proportional to both
rotational speed and torque. Motor horsepower and related values of
rotational speed and torque should be fully evaluated with respect to specific
drilling applications.
Adjustable and fixed Bent Tubular Housings
PDM's can be configured with adjustable bend, fixed bend, straight, or
eccentric housings for a full range of build rates. An Adjustable bent housing
with a setting range of from 0 to 3° is shown in Fig 2K-7. When using an
adjustable bent housing the desired setting can be set on the rig floor. A
rough estimate of the build rate achieved with a particular bent housing
setting can be obtained using the following equation:
Build Rate, deg./100 ft = 200 x Bent Housing Setting, deg. ..........Eq.2K-2
Distance from bit to Motor top, ft.
Equation 2K-2 assumes ideal bottom hole assembly behavior in gauge hole.
The harder the formation, the closer field performance approaches ideal BHA
behavior, as long as an acceptable ROP can be achieved. Further,
achievable build rates with a given bent housing setting typically decrease
with increased washout and softer formations.
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Figure 2K-7 - Adjustable Bent Housing
Transmission Unit
The transmission unit eliminates all rotor eccentric motion and the effects of
fixed or adjustable bent housings while transmitting torque and downthrust to
the drive shaft. The drive shaft is held in place concentrically by the bearing
assembly.
The transmission unit must also allow the correct axial
relationship of the rotor to the stator to ensure efficient rotor to stator sealing
and minimize rotor and stator wear.
A variety of constant velocity transmission unit designs are employed,
providing maximum transmission efficiency for differing rotor/stator
configurations.
Transmission units are of multi-element design consisting of a central shaft
connected at either end with universal couplings. The couplings contain
many specialized components housed in an oil-filled environment.
Component design and environment are selected to promote efficiency,
reliability and longevity.
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Figure 2K-8 - Transmission Unit
Bearing Section
The bearing assembly consists of multiple thrust bearing cartridges, radial
bearings, a flow restrictor and a drive shaft.
The thrust bearings support the downthrust of the rotor and the reactive
upward loading from the applied weight on bit. For larger diameter motors
the thrust bearings are of multi-stack ball and track design. Small diameter
motors utilize carbide friction bearings. Metallic and non-metallic radial
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bearings are employed above and below the thrust bearings to absorb lateral
side loading of the drive shaft. Side loading of the drive shaft can be
significant in steerable and correction run applications. The radial bearing
materials are selected and manufactured to provide reliable operation. The
bearings are normally repacked in the service companies shop after each
motor run as shown in Figure 2K-9.
Figure 2K-9 - Repacking of Bearing Assembly after PDM run
The bearing assembly is cooled and lubricated by approximately 5-8% of the
circulating fluid flow; however this value can be altered through the use of
nozzled rotors as previously mentioned.
The drive shaft transmits both axial and torsional loading to the bit. The drive
shaft is a forged component, which has a threaded connection at the bottom
end to facilitate connection to the drill bit. The drive shaft is the only external
rotating component. Fluid is supplied to the drill bit through the center of the
drive shaft.
All bearing assemblies are designed such that the drive shaft and bearings
can not strip out of the bearing housing in the event of the Drillstring
becoming stuck and the maximum downhole overpull for a particular motor
exceeded.
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Performance Motors
Performance or "extended power section motors" have power head sections
with from 1.25 to 2.0 times the number of stages of standard PDM's. These
motors have improved torque output compared to standard motors, without
the long length of Tandem Power Head Motors. The maximum bend on
some extended power section motors is only 1.83° because the larger
diameter shaft required for the high torque leaves less clearance in the
transmission section. Bend settings greater than 1.83° would cause the
transmission in the motor to rub against the inner diameter of the adjustable
bent housing.
Tandem Motors
Tandem motors utilize two standard power sections joined by a transmission
unit, effectively doubling the number of stages compared to the standard
PDM. By doubling the number of stages - the tandem power head motor,
increases torque output, maintains a higher bit speed over a wider range of
operating differential pressures and extends bit motor life. However due to
their longer length, the tandem motors are more difficult to steer and require
higher standpipe pressures to operate.
Figure 2K-10 - Dual Rotor configuration on Tandem PDM
PDM Operating Characteristics
The effectiveness of a PDM in a specific operating environment can be
related to its Mean Time Between Failure (MTBF) and Mean Time Between
Maintenance (MTBM). Operators can lower their cost by implementing subtle
changes in drilling fluid properties and operating practices to improve these
micrometers of PDM performance.
Drilling Fluid Properties
Chlorides
Chlorides in mud can severely corrode the chrome plating on standard rotors.
As a result of corrosion, the rough edges left on the rotor lobes damage the
stator by cutting the top off the elastomer in the stator/lobe profile. Corrosion
damage to a chrome-plated rotor from a 6-5/8" motor is shown in Fig 2K-11.
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Figure 2K-11 - Corrosion Damage to Chrome Plated Rotor, Saudi Arabia
Lost Circulation Material
Lost circulation material can cause two problems when pumped through a
motor. The material can plug off inside the motor, usually at the dump valve
if one is used at the top of the output shaft or the radial bearing, and it can
cause stator wear. However, LCM can be used with most PDM's if certain
precautions are followed.
¾ Add the LCM evenly - avoid pumping a large slug of material.
¾ Minimize the use of hard, sharp-edged materials such as nut plug, coarse
mica and calcium carbonate chips because they can cause stator wear by
abrasion.
Corrosion Inhibitors
The Napha base of many pipe corrosion inhibitors can cause excessive
swelling of the elastomeric stator. Particularly when added to the mud
system in slugs.
Salt Saturated Muds
Severe corrosion problems have occurred in Salt Saturated Muds, apparently
as a result of galvanic action between the dissimilar metals of the motor, drill
collars and the conductive drilling mud. Sacrificial anodes have been found
to work well in the motors, when galvanic corrosion is a problem.
Oil Based Muds & Water Based Muds with Diesel Added
Stators are occasionally subjected to chemical attack by aromatic
hydrocarbons in the diesel phase of oil mud systems. Diesel fuels are
typically "winterized" by the addition of aromatic compounds to lower the
temperature at which the fuel gels. The aniline point of a diesel fuel-the
temperature at which aniline becomes soluble in the diesel - is an inversely
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related indicator of aromatic content. Fuels with aniline points less than 155°
F are potentially detrimental to PDM stators.
Limit Surface Rotary Speed
Rotating motors at surface speeds above 80 rpm can damage the elastomer
in the stator. The larger the bend setting the more susceptible motors are to
damage.
Motor Failure Modes
The elastomeric lining of the stator tube is usually the element that fails first in
the power section. The central causes of rubber failure in a stator are
chunking, debond and junk damage.
Chunking
Chunking (or chunk out) describes a stator in which the rubber across the top
of the lobes has apparently ripped away. Chunking occurs when the strength
of the friction force between the rotor lobe and the stator lobe exceeds the
strength of the rubber in the stator. The magnitude of the friction force
between the rotor and the stator is affected by the lubricity of the mud,
interference fit between the rotor and stator, nutation speed and pressure
drop. Most stator failures result from chunking for various reasons.
De-Bonding
Two bonding agents are used in stators. One-agent bonds to the steel tube,
the other agent bonds to the stator elastomer, and both agents bond to one
another. Debond is defined as the failure of any one, two or all three bonds
in the stator:
Steel tube to bonding agent
Bonding agent to bonding agent
Bonding agent to elastomer
Stators failing from debond typically shed large sheets of loose elastomer.
These sheets of rubber usually have a smooth back surface where the stator
was molded against the steel tube. Motor failures from debonding are
relatively rare.
Junk Damage
Junk damage is caused by pumping "junk" through the motor. The stator will
have sharp cuts along a spiral path, and the rotor may also have damage
along the same path.
It is difficult to prevent debond failures, which fortunately are rare. Measures
can be taken to prevent chunking failures and junk damage. The most
obvious prevention technique is to prevent junk damage by ensuring that junk
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can't get into the mud system or Drillstring. Chunking prevention is a
combination of techniques involving the rotor/stator fit, bottom hole
temperature, drilling fluid selection, proper operation (use of performance
curves), lost circulation material usage, nozzled rotors, dogleg severity and
stator age tracking.
Figure 2K-12 - Removal of worn Chromed PDM Rotor and Installation of New one
Figure 2K-13 – Chrome & Tungsten Carbide rotors from 2-7/8” Short Radius PDM's
2.2 Saudi Aramco Utilization of Positive Displacement Motors
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Saudi Aramco began using PDM's in the early 1970's. They purchased about 40
PDM's of various sizes and configurations and serviced them out of the Toolhouse. The PDM's were used mainly for Top-Hole drilling. Aramco continued
running and servicing their own PDM's until about 1994, when it was no longer
deemed economically advantageous. All PDM's currently utilized by Aramco fall
under the Directional Drilling Contracts. The Anadrill and Sperry-Sun PDM's
currently used for directional and performance drilling are shown in Table 2K-1.
More detailed information on motor specifications and performance can be
obtained from PDM Service Company Handbooks. They have specification sheets
for each of their motors which detail the motor dimensions, fishing limitations and
maximum operating parameters. The motor handbooks also include nomographs
from which predicted rotational speed, output horsepower and torque can be
obtained from the actual Motor pressure differential (On-bottom pressure - off
bottom pressure) at given flow rates. Example Motor specification sheets for
Anadrill and Sperry-Sun PDM's are shown in Fig. 2K-13 and 2K-14 respectively.
Figure 2K-13 - Anadrill Specification Sheet for 6-3/4" 4/5 lobe Standard PDM
Figure 2K-14 - Sperry Sun 9-5/8” O.D. ¾ Lobe Extended Power Section PDM
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+0.
Table 2K-1 - Commonly used PDM's in Saudi Aramco Drilling Operations
POSITIVE DISPLACEMENT MOTORS CURRENTLY USED IN SAUDI ARAMCO OPERATIONS
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MODEL
(N0)
SIZE
LOBE
FLOW RATE
STAGES
OD, IN. COFIG
(NO)
RPM
HOLE SIZE RUNS/
GPM
RANGE
INCHES
YEAR
SS287B
2-7/8
5/6
3.3
20-100
120-600
3-3/4-4-1/4
12
SS287L
2-7/8
5/6
3.3
20-100
120-600
3-3/4-4-1/4
6
MAJOR
APPLICATION
SHORT RADIUS BUILD SECT. 60-130 deg/100'
SHORT RADIUS LATERAL SECTION
KICK OFF BUILD & TANGENT SECTION
A475M
4-3/4
4/5
3.5
100-250
105-262
5-7/8-7
49
A475XP
4-3/4
4/5
6.0
100-250
105-262
5-7/8-7
0
SS475B
4-3/4
4/5
3.5
100-250
105-262
5-7/8-6-1/8
12
SS475M
4-3/4
4/5
3.5
100-250
105-262
5-7/8-7-7/8
4
DEVIATED AND HORIZONTAL WELLS
SS475M
4-3/4
4/5
3.5
100-250
105-262
5-7/8-6-1/8
6
SHORT RADIUS LATERAL SECTION
SS475XP
4-3/4
4/5
6.3
100-250
105-262
5-7/8-7-7/8
4
DEVIATED AND HORIZONTAL WELLS
A475M
4-3/4
7/8
2.2
100-250
54-140
5-7/8-7
0
KICK OFF BUILD & TANGENT SECTION
A475XP
4-3/4
7/8
3.8
100-250
54-140
5-7/8-7
1
PERFORMANCE RUNS IN TANGENT SECTION
SS475M
4-3/4
7/8
2.2
100-250
56-140
5-7/8-7-7/8
55
DEVIATED AND HORIZONTAL WELLS
A675M
6-3/4
4/5
4.8
300-700
150-300
8-3/8-9-7/8
89
KICK-OFF, BUILD & TANGENT
A675XP
6-3/4
4/5
7.0
300-700
150-300
8-3/8-9-7/8
44
PERFORMANCE RUNS & TANGENT SECTION
SS675M
6-3/4
4/5
4.8
300-600
150-300
8-3/8-8-1/2
2
DEVIATED AND HORIZONTAL DRILLING
SS675XP
6-3/4
4/5
7.0
300-600
150-300
8-3/8-8-1/2
2
VERTICAL/DEVIATED/HORIZONTAL DRILLING
SS675XP
6-3/4
6/7
5.0
300-600
87-173
8-1/2-9-7/8
12
A675M
6-3/4
7/8
3.0
300-700
86-165
8-3/8-9-7/8
0
KICK-OFF BUILD AND TANGENT
A675XP
6-3/4
7/8
5.0
300-700
86-165
8-3/8-9-7/8
0
PERFORMANCE RUNS & TANGENT SECTION
SS675M
6-3/4
7/8
4.8
300-600
86-172
8-3/8-8-1/2
65
DEVIATED AND HORIZONTAL DRILLING
PERFORMANCE RUNS & TANGENT SECTION
SHORT RADUIS W/60-120 deg/100' BUR
KHUFF PDC APPLICATIONS
A800M
8
4/5
3.6
300-1100
75-225
9-7/8-14-3/4
22
KICK-OFF, BUILD & TANGENT
A800XP
8
4/5
5.3
300-1100
75-225
9-7/8-14-3/4
15
TANGENT AND PERFORMANCE
SS800XP
8
4/5
5.3
300-900
75-225
9-5/8-14-1/2
2
VERTICAL/DEVIATED/HORIZONTAL DRILLING
SS800XP
8
6/7
4.0
300-900
50-150
9-5/8-14-1/2
6
KHUFF 12" SECTION W/PDC & INSERT BITS
A800M
8
7/8
3.0
300-1100
48-145
9-7/8-14-3/4
0
KICK-OFF, BUILD & TANGENT
SS800M
8
7/8
3.0
300-900
48-144
9-5/8-14-1/2
32
DEVIATED AND HORIZONTAL
SS962XP
9-5/8
3/4
6.0
600-1200
132-264
12-26
8
VERTICAL/DEVIATED/HORIZONTAL
SS962M
9-5/8
5/6
3.0
600-1200
67-134
12-26
6
DEVIATED AND HORIZONTAL
A962M
9-5/8
5/6
3.0
600-1500
67-134
12-1/4-26
19
A962XP
9-5/8
5/6
4.0
600-1500
67-134
12-1/4-26
7
KICK-OFF, BUILD AND TANGENT
PERFORMANCE RUNS & TANGENT SECTION
CODE: A = ANADRILL; SS=SPERRY SUN; M=STD. POWER SECT.; XP=EXTENDED POWER SECT.; B=BUILD SECT.; L=LATERAL SECT.
The PDM Performance curves are typically used by entering the base of the graphs at
the X axis with the observed or predicted PDM pressure differential; proceeding up the
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POSITIVE DISPLACEMENT MOTORS
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graph vertically until the applicable flow rate or torque line is intersected and proceeding
horizontally to read its value on the Y axis.
Example Problem 2K-1:
Predict the Rotational Speed, Torque, and Horsepower
developed for a Sperry-Sun 4-3/4" 4/5 lobe, 3.5 stage PDM when operated at 420 psi
motor differential pressure and cirulation rate of 175 gpm from the applicable
performance specfication sheet.
Figure 2K-15 - Performance Graph for Sperry-Sun 4-3/4" - 4/5 Lobe - 3.5 Stage
PDM
From the chart above it can be seen that Shaft Rotational Speed = 170 rpm,
Horsepower = 25 Hp and Torque output = 690 ft-lb.
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TURBINES
1.0 CONVENTIONAL DOWNHOLE TURBINES
1.1
1.2
1.3
1.4
2.0
Principles of Operation
Turbine Components
Saudi Aramco Utilization
Operating Guidelines
LOW SPEED-HIGH TORQUE TURBINES
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TURBINES
1.0
CONVENTIONAL DOWNHOLE TURBINES
The first known turbines were "water wheels" used by the ancient Greeks more
than 2000 years ago. Turbines are currently used for a wide range of industrial
applications, including hydroelectric, steam, gas, fuel oil and nuclear power
generation; compression, pumping, propelling systems and high efficiency engines.
Turbines were developed and trial tested for downhole drilling applications in the
former Soviet Union (FSU) in 1934. By 1949 "Turbodrills" as they began to be
called, were receiving wide-scale utilization in the FSU. They found limited
success elsewhere until a successful application was achieved in Southern France
in 1959. Most of the turbine runs during this period were made utilizing non sealed
bearing two or three cone rock bits, in spite of the roller cone bits inherent
limitations for bearing life and the turbines inability to support the required bit
weight to obtain optimal penetration rates.
With the development of diamond and PDC bits in the 1960's and 70's Turbine
usage became increasingly popular in the US Gulf Coast, Africa, Asia, South
America, parts of Europe, the North Sea and several Middle Eastern countries
including Syria, Egypt, Bahrain, UAE and Qatar.
Many of the newer applications utilizing natural diamond and TSP diamond bits
either surface set or impregnated were in hard to very hard formations. The advent
of PDC bits extended the range of Turbine drilling into softer formations. By nature
of their cutting structure drag bits remove a comparatively small amount of rock per
revolution compared to tricone bits. For a given weight on bit more revolutions per
minute equates directly to more rock removed and faster ROP. The characteristics
of the Turbodrill; high torque output and rotational speeds from 300-1100 rpm
make possible substantially higher, and sometimes two-fold increases in
penetration rates compared to those previously achieved with rotary drilling.
However, in some areas Turbodrills were found advantageous in softer rock such
as in Qatar, where Turbodrills were used exclusively to drill 17-1/2" surface hole
sections from 1979 to 1995. These surface holes were previously plagued by
sulfide stress cracking of the Drillstring causing numerous twist-offs when
Drillstring rotational speeds exceeded 50 rpm adjacent to H2S laden formations.
By drilling the surface holes with turbines, the surface rotary speed could be limited
to about 40 rpm while downhole bit speeds exceeding 800 rpm were achieved.
This resulted in fast surface hole drilling without the previously high incidence of
twist-off.
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There was however, a high risk of bearing failure and cone loss from the nonsealed bearing bits being used. Accordingly, stipulations were set that on bottom
rotating time with non-sealed bearing bits run on turbine not exceed 12 hours.
Nonetheless, tangible drilling cost reductions were made for the surface hole
sections using turbines. However, In 1995, they began using PDM's to drill the
surface hole, since the PDM's served the function of limiting surface rotary speed
and provided slower downhole bit speeds, in the 200 rpm range, which were more
compatible with the sealed bearing motor bits which had become available.
Steerable Turbodrills gained global application in the tangent sections of deviated
and horizontal wells. Unfortunately, as more applications were found, the PDM
emerged as a fierce competitor for vertical and directional applications as well.
Turbodrills continued to hold a significant penetration rate advantage over PDM's
do to the higher rotational speeds achievable, which frequently equated to an
economic advantage when diamond or PDC bit drilling prevailed.
A major disadvantage of the Turbodrill is the high surface pump pressures and flow
rates required to operate them. Where as a 9-1/2" PDM develops a 500 psi
pressure drop circulating 75 pcf water base mud at 500 gpm, a 9-1/2", three power
section turbine develops a 1315 psi pressure drop.
Typically two 1600 hp mud
pumps in good mechanical working order are required for Turbodrilling. Moreover,
downhole torque and bit speed can be monitored at the surface with PDM's, since
with PDM's downhole torque is directly proportional to differential operating
pressure and bit speed is proportional to flow rate. Conversely, in Turbines, the
rotational speed of the drive shaft, is dependent not only on the flow rate of the
drilling fluid but also on the formation, bit configuration and bit weight, i.e., the
torque developed at the rock face.
Since exact knowledge of formation
characteristics and bit configuration effects cannot be discerned accurately, the
exact rotational speed at which a turbodrill is operating at any given juncture is
generally unknown, unless a surface readout tachometer is used. However, in
circumstances where bit speeds from 300 to 1100 rpm are required to maximize
penetration rates, the turbine remains the only field proven tool available.
1.1
Principles of Operation
Turbodrills are "dynamic motors". They are driven by a continuous flow of
fluid pumped through numerous rotor/stator stages. The hydraulic power of
the fluid under pressure (kinetic energy of the water, drilling mud, oil, etc.,)
which is flowing through the motor is converted into mechanical power
(rotational motion) by the drive stages.
For turbines to function properly the fluid must attack the "driving blades"
(rotors) at precise angles, this is accomplished by the "distribution units"
(stators). The flow leaving the rotor is parallel to the axis of the stators.
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Rotors and stators are "symmetrical"; they resemble an object and its mirror
image. The rotor/stator pair has a "degree of reaction". Approximately 50%
of the fluid flow leaving the rotor is parallel to the axis. Numerous rotor/stator
stages are required to develop the needed downhole torque. For instance, a
9-1/2" T3 (three power section) turbine is composed of 276 individual
rotor/stator stages. The Neyrfor 9-1/2" turbines contain 92 stages per power
section.
Turbines are completely modular in that one, two or three power sections can
be made up on and run on a bearing/drive shaft assembly, dependent on the
required torque output. The power section accounts for most of the turbines
length. A single turbine drive stage is depicted in Fig 2K-1.
Fig 2K-1 - Turbine Rotor/Stator Drive Stage
While drilling, a dynamic balance exists between the torque created by the
pressure drop of the flow passing through the rotors and the resisting torque
that opposes it. This balance is disturbed when one or more of the three
parameters, flow rate, pressure or resisting torque, varies which results in a
change in rotational speed.
Turbine Operational Characteristics
Rotating speed of the Rotor and in turn the drive shaft is directly proportional
to the flow rate:
S ≈ K1Q ............................................Eq. 2L-1
Where:
S = Rotating speed of rotor, RPM
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K= Calculated constant for blade characteristics
Q= Mud flow supplied to the Turbodrill
The mechanical characteristics of each turbodrill are measured at the
nominal flow rate and from it calculated for other flow values. In practice and
for a given flow the actual speed depends on the torque developed at the
rock face by the bit.
The drive torque is proportional to the mud flow rate squared, the specific
gravity and to the radius of the blading discs.
T ≈ K2 R Q2 d .........................................Eq. 2L-2
Where:
T = Torque delivered by the turbodrill
R= Average radius of blading disc and
d= mud specific gravity
The drive torque of a complete turbodrill is directly proportional to the number
of drive stages. In practice, and for a given flow rate, the drive torque varies
from zero with the turbodrill and bit off bottom (Runaway speed) to a
maximum value when the turbodrill stalls.
Delivered Power
The power delivered by the turbodrill is equal to the torque times the rotating
speed. Therefore, the power of the turbodrill, P is proportional to the cube of
the flow rate:
P ≈ K3 R Q3 d .....................................Eq. 2L-3
For the nominal flow, the maximum delivered power is the nominal power.
The corresponding torque and rotating speed are the nominal values. For a
given flow rate the maximum power is obtained when rotating speed is one
half of the runaway value. At this point the available torque is about half of
the torque produced at the stalling point. The optimum turbodrilling
conditions are close to this point and should generate maximum penetration
rates.
Fig 2L-2 - Typical Characteristic curves for Neyrfor Turbodrills
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Efficiency
The efficiency of the turbodrill is defined as, "mechanical power delivered by
turbodrill divided by given hydraulic power to the turbodrill. Dependent on the
type of blades used in a turbodrill, friction in the bearings, drillstring rpm, mud
flow rate, wear on the bearings and mud rheological properties, actual
turbodrill efficiencies usually range between 55 and 60%.
Pressure drop
The pressure drop through the turbine is proportional to the square of the
mud discharge, to the density of the mud and to the number of drive stages.
The actual rotating speed of the turbodrill has a negligible effect on pressure
drop across the turbodrill.
1.1 Turbine Components
All Conventional Turbodrills possess the following essential components:
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•
•
•
•
•
•
One housing (with a top connection for coupling to the drill string).
One shaft (with a bottom connection for coupling to the bit).
A stack of turbine stages, the rotors are locked on the shaft, the stators
on the body.
A set of radial bearings guiding the rotor assembly inside the stator
assembly.
A set of double-acting axial thrust bearings.
A lower bearing section to divert the fluid inside the bottom shaft and
through the bit.
Contemporary Turbodrills are multi-sectioned with the motor section(s)
connected directly above the bearing section, they are equipped with:
•
•
•
•
•
•
•
A system of shaft couplings for rapid connection of Turbodrill elements.
Stabilization with rig replaceable integrated spiraled blade stabilizers.
The "steerable" Turbodrills have additional features:
An articulated shaft either flexible (titanium) or fitted with universal joints.
A bent housing (fixed or rig floor adjustable).
A balance drum device to compensate for hydraulic thrust.
Drive stages with a greater "coefficient of circulation", i.e., efficiency
shifted toward lower speed.
A Neyrfor SBS Turbine is shown in Fig 2L-2. The SBS series have fixed bent
housing settings from 1/2 to 1-1/4°. Build rates of up to 2.5°/100' are
achievable in the 9-1/2" tool and up to 12°/100' in the 3-3/8" tool, with
tolerable dog-leg severities of 5°/100' & 17°/100' respectively.
Figure 2L-2 SBS - Turbodrill with Fixed Bent Housing
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Figure 2L-3 - Turbodrill Balance Drum Assembly
Figure 2L-4 - Turbodrill Motor Section Construction
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Figure 2L-5 - Turbodrill Bearing Section Construction
Saudi Aramco Utilization
Approximately 30 Neyrfor Turbine runs have been made in Saudi Arabia over the last
three years. All of the runs have been with either two or three power section straight
hole turbodrills. The turbines are completely modular, in that either one, two or three
power sections can be run dependent on the available mud pump capability and
downhole torque output requirement. Table 2L-1 reflects current Neyrfor Turbine usage
for Saudi Aramco.
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Table 2L-1 - General Specifications for Neyrfor Turbodrills Used in Saudi Aramco
TURBINE
TYPE
9-1/2" T3
SECTIONS
(No.)
3
STAGES
(No.)
276
HOLE
SIZE, IN
12-16
FLOW
(GPM)
525-750
SPEED
(RPM)
550-800
9-1/2 T2
2
184
12-16
550-550
500-600
6-5/8" T2
2
172
400-445
800-1050
4-3/4 T2
2
199
7-5/89-7/8
5-5/89-7/8
170-195
1100-1300
WHERE
USED
ALL
FIELDS
HIGH MW
RUNS/YR
ALL
FIELDS
SLIM
HOLE
4-5
4-5
1
1
Table 2L-2 Typical Bottom Hole Assemblies for Neyrfor Turbodrills
5-7/8" HOLE SECTION
8-3/8" HOLE SECTION
12" HOLE SECTION
BIT
SAFTEY SUB
TURBODRILL
CIRCULATING SUB
FLOAT
(12) 4-3/4" DRILL COLLARS
JARS
(2) 4-3/4" DRILL COLLARS
(6) HWDP (OPTIONAL)
BIT
SAFETY SUB
TURBODRILL
CIRCULATING SUB
CROSSOVER FLOAT (NEYRFOR)
(12) 6-1/4" DRILL COLLARS
JARS
(2) 6-1/4" DRILL COLLARS
CROSSOVER
(9) HWDP
BIT
SAFETY SUB
TURBODRILL
CIRCULATING SUB
CROSSOVER
FLOAT
(9) 8-1/4" DRILL COLLARS
JARS
(2) 8-1/4" DRILL COLLARS
CROSSOVER
(9) HWDP
Fig 2L-6 - Operating Specs for 9-1/2" Neyrfor Turbodrill with three power sections
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Figure 2L-7 - SBS Turbine Length Vs. Two Power Section Straight Hole Turbine
Length
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Figure 2L-8 - Steerable Turbodrill Operating Characteristics
1.2 Operating Guidelines
Pre-run Considerations
To avoid reaming when running in the hole, the rotary run just prior to the
turbodrill run should be made with string stabilizers similar to those to be
used with the turbodrill.
A junk sub should be run in the string prior to running the turbodrill and
diamond or PDC bit to prevent junk from damaging the diamond bit cutters.
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Proceed carefully when running into open hole, especially for the first
turbodrill run.
When reaming, the weight on the bit is low, providing less compensation of
the hydraulic thrust through the turbodrill. A lower flow rate, (25-50% of
normal) allowing adequate power to the bit but reduced hydraulic thrust, is
therefore recommended while reaming to avoid premature thrust bearing
wear.
Stabilizers and the thrust bearing section should be inspected between
turbodrill runs. They may need replacing before running back in hole.
Make up of Turbodrill Sections
The steerable turbodrills are composed of only one section which includes all
the motor blading disks and thrust bearings. The straight hole turbodrills are
composed of one bearing section and two or three motor sections.
Turbodrills arrive on location in separate sections. They are made up on the
rig floor under the supervision of a Turbodrilling Specialist who makes up the
required stabilizers; usually one stabilizer per turbine section. The motor
section stabilizers can be interchanged on the rig floor. The bearing section
stabilizer is mounted in the service companies workshop.
Wear Measurements
Before every run, the turbodrill should be checked as follows:
•
With the turbodrill hanging free above the rotary table, the measurement
of the clearance Ch1 minus the clearance Ch0 taken prior to turbodrill run,
gives the wear of bearings in the hydraulic thrust position. A specified
length, based on turbodrill size and model, should not be exceeded.
• With the turbodrill set onto the rotary table, under its own weight, the
difference between the clearance Cm1 thus measured and the clearance
Cm0 measured prior to the turbodrill run, gives the wear of bearings in the
mechanical thrust position.
Since typically, the turbodrill is running in the hydraulic thrust position, the wear is
noticeable as shown in Fig 2L-9.
Figure 2L-9 - Thrust Bearing Check Measurements for Neyrfor Turbodrills
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By-passing the Turbodrill
In order to be able to circulate LCM or cement slurry without plugging the turbodrill, a
circulating sub above the motor section can be run. However, very fine LCM mixed in
the mud can be pumped through the turbodrill, if the concentration is not too high. A
Neyrfor circulating sub is shown in Fig - 2L-10.
Figure – 2L-10 - Neyrfor Circulating Sub
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Use of Drill Pipe Screen
To avoid any plugging of the turbodrill by large particles or junk in the mud, a drillpipe
screen is placed in the box connection of the first joint below the kelly. At each
connection, the screen is replaced at this position. Normally drillpipe filters are provided
by the turbine service company to suit the type of pipe in current use. The center of the
screen can be removed with a small wire line overshot; to allow the running of a free
point indicator or other wireline tools if required.
Figure 2L-11 - Neyrfor Drillpipe Screen
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Mud Properties - Mass Flow
The mud flow through the turbine blades is turbulent. Thus, for water based
muds it may be assumed in practice that the flow through the turbodrill and bit
is independent of viscosity. The plastic viscosity of oil based drilling fluids is
considerably higher and experimental pressure drops show an increase of
about 15%. It is difficult to express the increase in exact physical terms owing
to the complexity of the flow.
Number of Drive Stages
Power and drive torque are directly proportional to the number of drive
stages. Turbodrills should be sized based on the existing mud pump and
surface circulating equipment capabilities and projected bit and circulating
system pressure losses.
Rotational Speed
The blades of the turbine are designed so that the velocity triangle is optimal,
i.e.; the nominal flow rate corresponds to a nominal speed of rotation at which
the power is maximum - nominal power. In practice, the nominal speed is
usually only reached for a given value of the reactive torque exerted by the
formation on the bit.
In other words, the speed of rotation depends not only upon the mass flow of
the mud but also on:
¾
¾
¾
The formation
The bit configuration
The weight on bit
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As factors (a) and (b) cannot be controlled, the exact speed at which a
turbodrill is drilling if often unknown unless a surface reading tachometer is
used.
During circulation, the formation and bit don't provide any resisting torque and
the turbodrill speeds up to its runaway speed, (i.e., the speed at which power
and effective drive torque are zero). Runaway speeds lie between 1000 and
2000 rpm depending on the model of turbodrill.
During drilling, an increase in the weight on bit causes the turbodrill to stall,
the power to drop back to zero, and the effective torque to rise to its
maximum value. The highest penetration rates are usually obtained at
speeds between 400-1000 rpm corresponding to maximum turbodrill power.
Mud Pressure
The pressure drop corresponding to the energy driving the turbine is
proportional to the square of the mud flow rate, to the density of the mud and
to the number of drive stages. Projected pressure drops for several water
and oil base drilling fluid weights are given on the respective Neyrfor data
sheets.
Drilling Fluids
Rotary drilling fluids may be used with turbodrills provided:
¾ The fluid consists of neither lost circulation materials or undesirable
plugging materials.
¾ Sand content as measured with a standard centrifuge is less than 1%.
¾ Drillstring filters are used.
Most drilling fluids are suitable for turbodrilling including, water base, polymer, oil
base and emulsion muds. Crude aromatic series petroleum tends to attack
synthetic rubber in the thrust bearing section more than other fluids. However
the newer Neyrfor turbines are an all-metal design and consequently not
adversely affected by aromatics.
Bit Weight
The rotational speed of the turbodrill diminishes as the weight on bit increases.
As weight on bit increases to a certain point, the turbine will eventually stall.
However, permissible WOB increases with the hydraulic power available.
The drill collars used to apply weight to the bit are generally the same as those
used in rotary drilling. However, the greater rotational speed of turbodrill bits
enables a smaller weight to be applied even though penetration rates are higher.
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As a result fewer drill collars are required with turbodrills than for rotary drilling or
drilling with PDM's.
Drillstring Rotation
The drillstring is rotated by the rotary table or top drive to eliminate axial drag
between the drillstring and the hole wall. This allows the required drill collar
weight to be transmitted to the bit. Rotation of the drillstring, which prevents
sudden variations in torque from being applied to the rotary table or top drive, is
indispensable whenever the turbodrill is stabilized.
Stabilization
Turbodrills may be equipped with stabilizers for both vertical and deviated
drilling.
Jars
It is advisable to place a jar in the drillstring for holes in which sticking tends to be
a problem.
Bit Pressure Drop
When drilling with a turbine, the minimum bit pressure drops in terms of HSI for
the specific bit and formation type are usually used. An increase in bit pressure
drop lowers the power input to the turbodrill for a given surface pressure and also
causes an increase in the quantity of fluid passing through the turbodrills lower
bearing section, thus increasing the volume of mud passing across the face of
the bit.
In hard formations, the pressure drop should normally be as low as possible. In
soft rock, (e.g., marl and clay) it should be high enough to permit satisfactory
removal of cuttings.
Figure 2K-12 - Recommended Rig make-up Torque for Neyrfor Turbodrills
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2.0 LOW-SPEED HIGH TORQUE TURBINES
To meet the increasingly stringent demands of current directional, horizontal and
performance drilling applications, Tiebo-Tiefborservice, a German directional drilling
company in conjunction with the Russian VNIIBT Perm institute jointly developed a
Low-Speed High-Torque Turbodrill. A gear reduction section located immediatly
below the power section of the turbine, is incorporated to decrease shaft rotational
speed and increase the torque output. The contention being that these features will
optimize drilling performance in numerous applications for diamond and PDC bits.
A series of 9-1/2" Low-Speed, High-Torque, Gear Reduction Turbines (LSHT) runs
were made with PDC bits in 12" intermediate and production hole sections to
appraise the LSHT's applicability in Saudi Aramco's Khuff drilling program.
Outstanding penetration rates and minimal footage cost had previously been
achieved with conventinal turbodrills and PDC bits, albeit with a high probability of
bit sticking. The bit sticking phenomena is envisaged related to the high downhole
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rotational speeds, up to 1100 rpm, with which conventional turbodrills operate. The
problem has been partially alleviated by running a safety sub immediately above the
bit and utilizing more wear resistant stabilizers on the turbine housing to avoid
drilling a spiral hole.
The gear reduction section of the 9-1/2" Tiebo Turbine has a gear ratio of 3.05 to 1
which reduces the output shaft's speed while increasing its torque. The reduced bit
speed delivered by the LHST turbodrill and its greater available torque has greatly
reduced the occurrence of bit stall-out and bit sticking in the runs made.
The observed operating characteristics of the LSHT Turbine indicate it is
competitive with conventional positive displacement motors. The LSHT turbines
were typically operated at 200-250 rpm and delivered 4000 ft-lb of torque. It was
hoped that they would offer more reliable operation at the elevated downhole
temperatures encountered in deep Khuff wells than conventional turbodrills and
PDM's. A recurring twist-off/in hole failure problem in the LSHT turbodrill housing
near the top of the gear reduction section has temporarily interrupted their use. The
interrelationships between bit torque, flow rate, power output, penetration rate, bit
weight, bit speed, pump pressure and bit hydraulics are similar to those of
conventional turbines.
Although Tiebo provides conventional two and three power section Turbodrills and
Gear reduction turbines in several sizes. Saudi Aramco's test trial was limited to the
9-1/2" 1TR-240, a one-power section LSHT turbodrill as shown in Fig 2L-13. The
LSHT Turbodrill consists of three main sections, which are the Power Section, Gear
Reduction Section and Bearing Section. From the power section the energy is
transferred through the gear reduction section to the drive shaft.
Figure 2L-13 - Tiebo Low-Speed High Torque Turbine
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Both the bearing and gear reduction sections operate in a sealed, pressure
compensated oil bath. The gear reduction section is equipped with thrust
bearings to absorb the hydraulic loading from the power section.
Figure 2K-14 - Tiebo LSHT Upper Turbine Section Assembly
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Figure 2K-15 - Available Tiebo Turbine Blade Types
i. S: increasing pressure-losses with increasing torque
ii. B: decreasing pressure-losses with increasing torque
iii.P: blade form like type B with a special flange at the exit of flow pressing stages
against each other, so that fluid losses decrease, decreasing pressure-losses with
increasing torque.
Figure 2K-17 - Performance Curves for Tiebo "1 TR-240-S" LSHT Turbine
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Figure 2K-18 - Tiebo "1 TR-240S" Performance Data at various Mud Weights
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PERFORMANCE DRILLING SYSTEMS OPTIMIZATION
1.0 TURBINE SELECTION AND OPTIMIZATON
1.1
Turbine Selection - Analysis of Existing Circulating System
1.2 Optimization of Selected Turbine Performance
2.0 POSITIVE DISPLACEMENT MOTOR SELECTION AND OPTIMIZATION
3.0 PERFORMANCE DRILL BIT AVAILABILITY AND ANALYSIS
3.1
3.2
3.3
4.0
Performance Drill Bit Availability
Breakeven Analysis
Expected Value Cost Analysis
PERFORMANCE DRILLING SYSTEMS OPTIMIZATION
4.1
Development of Minimum Cost Drilling Plan
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PERFORMANCE DRILLING SYSTEMS OPTIMIZATION
1.0
TURBINE SELECTION AND OPTIMIZATION
The purpose of this section is to provide methodology for the analysis, selection
and optimization of Performance Drilling Systems. Those systems include; Turbine
and PDC, PDM & PDC, PDM & TCI, Rotary & PDC and Rotary & TCI.
1.1
Turbine Selection - Analysis of Existing Circulating System
A thorough analysis of the existing rig pump capability, circulating system and
expected downhole pressure losses should be made prior to selecting a
turbine to be run. The results of the analysis may show that a turbine run is
unfeasible, due to the lack of available pump power. If sufficient rig pump
power is available then the turbine can be sized, selected and the flow rate
and bit nozzle configuration modified to optimize performance. The final
consideration is then the economics in terms of overall cost per foot as
compared to the other available drilling systems.
The first step in selecting a Turbine is to analyze the existing circulating
system excluding the turbine as follows:
1. Compute the component pressure losses at several flow rates, such as
100, 200, 300, 400, 500 and 600 gpm. Add the component losses to
determine the total standpipe pressure for each rate.
2. Plot the standpipe pressure vs. flow rate. Mark a horizontal line at the
maximum recommended standpipe pressure.
3. Determine the remaining available standpipe pressure that could be used
to power the turbine at each flow rate.
4. Compute the available hydraulic horsepower at each flow rate, and plot
on the same graph, available power is equal to available pressure times
gallons per minute divided by 1714.
5. Locate the maximum available power on the curve, and note the flow rate
at which it occurs. This is the flow rate at which the Turbine should be sized.
The corresponding available pressure is the pressure drop for which the
turbine should be sized. It may not agree with the flow rate and pressure at
which a turbine is designed to operate, in which case the turbine is unsuitable
for the system and a different turbine, PDM or rotary run must be considered.
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6. From the graph of Power vs. Flow rate, define the optimal flow rate. This
is the flow rate at which the most hydraulic horsepower is delivered to a
downhole motor or turbine for conversion to mechanical horsepower in its
drive shaft.
Example Problem 2M-1 - Size and optimize performance for a Turbodrill, to drill an
open hole section from 10,500 to 12,500' with a 12" PDC bit based on the following
pertinent data:
Drillpipe: 5" 19.5 ppf Grade E
Heviwate: 450' of 5" OD x 3" ID
Upper Drill Collar Section: 180' of 8.5" OD x 2.81" ID
Lower Drill Collar Section: 120' of 9.5" OD x 3.00" ID
Mud Weight: 95 pcf;
PV: 22 YP:28 lbf/100 sq.ft. Bit TFA=0.90 in.
Surface equipment case #3; equiv. to 816' of 5" Drill Pipe
Mud Pumps: Two Gardner-Denver PZ-11's with 7" liners. Maximum Pressure is 3458
psi @ 130 spm & 5.5 gal/stk. Assume mud pump efficiency of 95% equal to 5.23 gal/stk
& Maximum Pump Pressure of 3400 psi. If the available 6-1/2" liners were used the
pump would be rated to 4006 psi @ 130 spm & 4.7 gal/stk; and 4702 psi with 6" liners @
130 spm & 4.0 gal/stk.
System Pressure Loss Calculations
Acceptable accuracy can be obtained in this case by assuming turbulent flow down the
drill-bore and laminar flow up the annulus at the near optimum circulation rates. This
allows system pressure losses to be calculated quickly in a straightforward manner with
hand/calculator calculations as follows:
Drillbore
Assume turbulent flow through the drillpipe, heviwate and drill collars. From the Drilling
Practices Manual the equation for turbulent flow in the drillstring is given:
Pt = 7.7(10-5) ρ0.8 Q1.8 PV0.2 lf ................................................Eq. 2M-1
Di4.8
Where:
Pt = Pressure Loss inside pipe, psi
ρ = Mud density, lb/gal (divide pcf by 7.48 to get lb/gal)
Q = Circulation rate, gpm
PV= Plastic viscosity, cp
lf = Length of pipe, ft
Di = Inside diameter of pipe, in
For 12,235' of 5" drillpipe, (4.23 in. ID) we have the following:
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Pt = 7.7(10-5) (95/7.48)0.8 1001.8 220.2 12,235 =
4.234.8
53,166.35 = 52.39 psi
1,014.92
For 465' of 5" OD x 3" ID Heviwate Drillpipe:
Pt = 7.7(10-5) (95/7.48)0.8 1001.8 220.2 450 =
34.8
1955.44 = 10.02 psi
195.07
For 180' of 8" OD x 2.81" ID Drill Collars:
Pt = 7.7(10-5) (95/7.48)0.8 1001.8 220.2 180 =
2.814.8
728.18 = 5.11 psi
142.49
For 120' of 9.5" OD x 3" ID Drill Collars:
Pt = 7.7(10-5) (95/7.48)0.8 1001.8 220.2 120 = 521.46 = 2.67 psi
3.04.8
195.07
Total Drillbore Pressure Losses are calculated:
Pressure Loss in Drillpipe............................53.39 psi
Pressure Loss in Heviwate DP....................10.02 psi.
Pressure Loss in Upper DC Section .............5.11 psi.
Pressure Loss in Lower DC Section .............2.67 psi.
Total Drill Bore Pressure Losses:............71.19 psi
Surface Equipment
Since the surface equipment case is #3, the surface losses are equivalent to
those produced by 816' of 5" OD x 4.23" ID drillpipe:
Pt = 7.7(10-5) (95/7.48)0.8 1001.8 220.2 816 =
4.234.8
3545.87 = 3.49 psi
1014.92
Laminar Flow is assumed in the annulus, and due to the wellbore geometry,
divided into 5 sections. From the Drilling Practices Manual, the power law
fluid pressure loss equation for laminar annulus flow is:
Pla =
2.4v
2n + 1
Dh-Dop
3n
N
Klf
300(Dh-Dop) ........................Eq. 2M-2
Where:
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Pla = Pressure Loss in Laminar flow, psi.
v = average annular velocity, ft/sec
Dh= Diameter of hole or casing, in.
Do= Drill String OD, in.
lf = length of annulus under consideration
Mud Rheological Properties need only be calculated once:
θ300 = PV + YP = 22 + 28 = 50
θ600 = θ300 + PV = 50 + 22 = 72
n = 3.32 log θ300/θ600 = 3.32 log (50/72) = 0.526
K = θ300/(511n) = 50/(5110.526)= 1.88
Where:
n = slope of the viscometer data on log paper
K= intercept of viscometer data on log paper
θ= viscometer reading, lbf/100 sq. ft
Section # 1: Drillpipe inside cased hole. For the 10,500' section of 5" drillpipe
inside 13-3/8" casing.
Annular velocity should be calculated for each hole section:
v = 24.5 Q/(Dh2-Dop2) = 24.5(100)/(12.3472-52)= 19.22 fps
Pla =
2.4(19.22)
12.347-5
2(0.526) + 1
3(0.526)
0.526
1.88 (10,500)
300 (12.347-5)
= 3.0177 x 8.956 = 27.03 psi
Section # 2;
(1735'):
Drillpipe in the 12" open hole section from 10,500 to 12,235'
v = 24.5 Q/(Dh2-Dop2) = 24.5(100)/(12 2-52)= 20.59 fps
Pla =
2.4(20.59)
12-5
2(0.526) + 1
3(0.526)
0.526
1.88 (1735)
300 (12-5)
= (3.2096 x 1.55) 0.526 = 4.97 psi
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Section # 3: For the 450' section of 5" OD x 3" ID Heviwate DP in the 12"
open hole section from 12,235 to 12,685':
v = 24.5 Q/(Dh2-Dop2) = 24.5(100)/(12 2-52)= 20.59 fps
Pla =
2.4(20.59)
12-5
2(0.526) + 1
3(0.526)
0.526
1.88 (450)
300 (12-5)
= (3.2096 x 0.4086) = 1.29 psi
Section # 4: 180' section of 8.5" OD x 2.81" ID Drill Collars in the 12" open
hole section from 12,685 to 12,865':
v = 24.5Q/(Dh2-Dop2) = 24.5(100)/(12 2-8.52)= 34.15 fps
Pla =
2.4(34.15)
12-8.5
2(0.526) + 1
3(0.526)
0.526
1.88 (180)
300 (12-8.5)
= (6.03 x 0.3229) = 1.94 psi
Section # 5: 120' section of 9.5" OD x 3.00" ID Drill Collars in the 12" open
hole section from 12,865 to 12985':
v = 24.5Q/(Dh2-Dop2) = 24.5(100)/(12 2-9.52)= 45.58 fps
Pla =
2.4(45.58)
12-9.5
2(0.526) + 1
3(0.526)
0.526
1.88 (120)
300 (12-9.5)
= (8.3778 x 0.3008) = 2.52 psi
Total Annular Pressure drop = 27.03 + 4.97 +1.29 +1.94 + 2.52 = 37.75 psi
Bit Nozzle Pressure Losses
From the Applied Drilling Engineering textbook, pressure losses through the
bit nozzles may be calculated as follows:
Pb =
8.311 x 10-5ρ Q2
Cd2 At2
...........................................................Eq. 2M-3
Where:
Pb = pressure loss through bit nozzles, psi
Cd = nozzle discharge coefficient, (0.95 for conventional nozzles)
ρ = mud density, ppg
Q = circulation rate, gpm
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Pb =
0.00008311 (95/7.48) 1002
(0.95)2 (0.9)2
= 14.44 psi
Total System Pressure Losses (excluding Turbine) are summed as follows:
Surface Pressure Losses................................. 3.49 psi
Drillbore Pressure Losses................................ 71.19 psi
Bit Nozzle Pressure Losses............................ 14.44 psi
Annulus Pressure Losses................................. 37.75 psi
Total System Pressure Losses Without Turbine=127 psi
Available pressure for the Turbine is calculated:
Available Pressure = Maximum Standpipe pressure - System Pressure Loss
= 3400 psi - 127 psi = 3273 psi.
Available Pump Horsepower = (Available Pressure x Flow Rate)/1714
= (3273 x 100)/1714 = 191 Hhp.
The calculations are repeated for 200, 300, 400, 500, and 600 gpm, resulting
in the following tabulated data:
Table 2M-1 - Available Pressure and Horsepower for a Turbine
Circulating
System
Component
Surface
Drillbore
Bit
Annulus
Total
Standpipe
Available
Pressure
for Turb.
Available
Hhp for
Turbine
Pressure
Loss
@100 gpm
Pressure
Loss @
200 gpm
Pressure
Loss @
300 gpm
Pressure
Loss @
400 gpm
Pressure
Loss @
500 gpm
Pressure
Loss @
600 gpm
3
71
14
38
126
12
246
57
54
370
25
510
129
67
732
42
856
229
78
1206
63
1279
358
88
1789
88
1775
516
97
2476
3274
3030
2668
2194
1611
924
191
354
467
512
470
323
The analysis indicates the optimum flow rate for the system is 400 gpm at
which the maximum available power (512 Hhp) would be available for the
turbine with available pressure drop of 2194 psi. A plot of the data is shown in
Fig 2M-1.
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Figure 2M-1 - Plot of Available Power Vs. Flow Rate
Available Power, Hhp
Available Power Vs. Flow Rate
600
500
467
400
512
470
354
323
300
200
191
100
54
0
0
0
100 200 300 400 500 600 700 800
Flow Rate, gpm
Operating requirements for Neyrfor and Tiebo Turbines are listed in Table
2M-2 for 9-1/2 to 9-5/8" tools capable of drilling 12" hole.
Table 2M-2 - Available Turbines for Example Problem 2M-1.
Turbine
Model
9-1/2" SBS
w/one power
section
9-1/2" FBS
w/one power
sect.
9-1/2" T2
w/two power
sections
9-1/2" T3
w/three
power sect.
Tiebo 1TR240-S, one
power sect.
Required
flow Rate,
gpm
450-725
Turbodrill
Pressure
Drop, psi
976-2204
Shaft
Speed,
RPM
300-800
Nominal
Power
Output, Hp
269
Nominal
Torque, ftlb
3676
500-700
2048-3019
600-1200
512
5000
500-650
1175-1980
520-900
379
7960
500-800
1700-2450
520-800
568
9370
476-793
653-1813
272-453
216
3250
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Of the available turbines, all require a flow rate greater than the optimal flow
rate of 400 gpm for the system. Since the Gardner Denver PZ-11 mud
pumps can handle up to 4702 psi with 6" liners, run the calculations again
with a maximum stand pipe pressure of 4000 psi and see if a higher
circulation rate can be obtained which produces peak Hhp.
At 4000-psi standpipe pressure the optimum flow rate is 450 gpm which
produces 661 Hhp and leaves 2516 psi available for the pressure drop across
the turbine. With two mud pumps, a circulation rate of 1040 gpm is
achievable, which well exceeds our requirement.
Typically only 55 to 60% of the hydraulic energy of the mud flow is converted
to mechanical energy in the turbine. For this case the Mechanical energy
produced in the turbine from the mud flow is; 661 Hhp x 0.55 = 364 Hp.
A flow rate of 450 gpm meets the minimum requirements for the one stage 91/2" Neyrfor SBS Turbine with one power section utilizing mixed blades. The
circulating system is capable of generating 364 Hp in the turbine, which
exceeds the SBS Turbine's Nominal horsepower output of 279 Hp. Note that
this is the only available turbine in which the flow rate, available pressure
drop and nominal horsepower requirements are met by the existing
circulating system. Accordingly, it is selected.
1.2 Optimizing Performance of Selected Turbine
Although the rest of the circulating system will tolerate a higher pressure drop
across the bit, which would be effected by smaller jets, the turbine
specifications limit the pressure drop across the bit to a maximum of 450 psi.
The nozzle total flow area (TFA) which generates a 450 psi pressure drop
can be calculated after the flow rate for the selected turbine is optimized.
At the optimum system circulating rate of 450 gpm the following pressure
losses are effected:
Surface.....................................................................52 psi
Drillbore pressure losses......................................1058 psi
Bit Nozzle Pressure Loss..................................... 450 psi
Annulus................................................................ 83 psi
Total System Pressure loss excluding Turbine = 1643 psi
This leaves (4000-1643)= 2357 psi; to operate the turbine when only 976 psi
is required. Review of the governing Turbine performance equations shows
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that rotational speed is directly proportional to flow rate, torque is proportional
to flow rate squared and power is proportional to flow rate cubed.
S ≈ K1Q ....................................................................Eq. 2M-4
T ≈ K2 R Q2 d ............................................................Eq. 2M-5
P ≈ K3 R Q3 d ............................................................Eq. 2M-6
Where:
S = Rotating speed of rotor
K= Calculated constant for blade characteristics
Q= Mud flow supplied to the turbodrill
T = Torque delivered by the turbodrill
R= Average radius of blading disc
d= Mud specific gravity
P = Power delivered by the turbodrill
Note that in all cases increasing flow rate serves to increase turbine
parameters of performance. With the selected turbine, flow rate will be
maximized within the constraints of maximum standpipe pressure and
parasitic pressure losses in the existing circulating system.
The Optimum flow rate for the existing system can be obtained by plotting the
required pressure drop across the turbine and the pressure available for the
turbine Vs. flow rate. The intersection of the two curves denotes the optimum
flow rate for the system. Pressure drops across the turbine are taken directly
from the specification sheet for the 9-1/2" SBS Turbine with mixed blades
shown in Figure 2M-4. The System pressure losses used to calculate the
available pressure loss for the turbine assume a bit pressure loss of 450 psi.
The tabulated data and resulting plot are shown in Table 2M-3 and Fig 2M-2.
Table 2M-3 - Tabulated Pressure Loss Data for Example Problem 2M-1
Flow Rate
gpm
450
500
550
600
650
700
Surf, DB &
Ann PL,
psi
1193
1430
1686
1960
2254
2564
Bit Nozzle
PL, psi
450
450
450
450
450
450
System
PL exclud.
Turbine
1643
1880
2136
2410
2704
3014
Maximum
Standpipe
Press, psi
4000
4000
4000
4000
4000
4000
Available
Press for
Turb. psi
2357
2120
1864
1590
1296
986
Required
Turbine
Press.,psi
976
1167
1373
1593
1827
2075
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Figure 2M-2 - Cross-plot of Required and Available Pressure Vs. Flow
rate to Obtain Optimum flow rate for Turbine Run
Required and Available Pressure
Vs. Flow rate for a Turbine
Pressure, psi
2900
2400
Available Pressure for
Turbine
1900
Required Turbine Pressure
1400
900
400
400
500
600
700
Flow Rate, gpm
Intersection of
curves
denotes optimum
Flow Rate of
600 gpm
With the planned (optimum) flow rate of 600 gpm known, the bit nozzles can
now be sized to effect a 450 psi pressure drop at the bit using the following
equation from the Applied Drilling Engineering Textbook.
At =
8.311 x 10-5ρ Q2
Cd2 Pb
0.5
............................................................Eq. 2M-7
where:
At = Total nozzle flow area, sq. in.
Q= Flow rate, gpm
Cd= Nozzle discharge factor
Pb= Bit pressure drop, psi
ρ = Mud density, ppg
At =
.00008311 (95/7.48) 6002
0.952 450
0.5
= 0.9673 sq. in.
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The 12" PDC bit utilizes six nozzles, so from the Nozzle Selection Chart in
Fig. 2M-5, the closest TFA is 1.035 sq. in. for (six)15/32" nozzles. A slightly
larger, as opposed to slightly smaller TFA was selected to avoid exceeding
the maximum allowed bit pressure drop of 450 psi for the turbine.
With the slightly larger TFA the pressure drop at the bit is recalculated:
Pb =
0.00008311 (95/7.48) 6002
(0.95)2 (1.035)
= 407 psi
The HSI is checked to assure the minimum value of 1.0 Hhp/sq. in. is
achieved.
Bit Hhp = (Pb Q)/1714
Bit HSI = Bit Hhp/(Bit diameter2 ∏/4)
Bit Hhp = (407 x 600)/1714 = 142.47 Hhp
Bit HSI = 142.47/(144 x 0.7854) = 1.26 Hhp/in2
This value is acceptable, being slightly higher than the required 1.0 Hhp/in2.
Most importantly, it is the best achievable with the given constraints on bit
pressure drop.
As a final check, system pressure losses are summed to arrive at the final
circulating pressure at the end of the planned section; 12,500':
Surface..............................................................88 psi
Drillbore pressure losses...............................1775 psi
Bit................................................................... 407 psi
Turbine......................................................... 1593 psi
Annulus......................................................... 97 psi
Total System Pressure/Standpipe Pressure = 3960 psi
The Hydraulic horsepower developed by the circulating system is:
Hhp = 1593 x 600/1714 = 558 Hhp
Mechanical Horsepower developed by the Turbine = 558 x 0.55 = 307 Hp
Accordingly the 9-1/2" SBS, (one power section) turbine with mixed blades is
run at 600 gpm with (6) 15/32" jets. Expected pump pressure is + 3960 psi.
The calculation procedure for optimizing flow rate is readily adaptable to
Excel spreadsheets as shown in Figure 2M-3.
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Figure 2M-3 – Spreadsheet for Turbine Flow rate Optimization
Fig 2M-4 - Neyrfor Specification Sheet for 9-1/2” SBS with mixed blades
Figure 2M-4 - Specification Sheet for Neyrfor 9-1/2" T-2 Turbine with
mixed blades
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Table 2M-5 - Nozzle Selection Chart, TFA's are in sq. inches.
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Size
(inches)
7/32
8/32
9/32
10/32
11/32
12/32
13/32
14/32
15/32
16/32
18/32
20/32
22/32
24/32
1
Jet
0.038
0.049
0.062
0.077
0.093
0.110
0.130
0.150
0.173
0.196
0.249
0.307
0.371
0.442
2
Jets
0.075
0.098
0.124
0.153
0.186
0.221
0.259
0.301
0.345
0.393
0.497
0.614
0.742
0.884
3
Jets
0.113
0.147
0.186
0.230
0.278
0.331
0.389
0.451
0.518
0.589
0.746
0.920
1.114
1.325
4
Jets
0.150
0.196
0.249
0.307
0.371
0.442
0.518
0.601
0.690
0.785
0.994
1.227
1.485
1.767
5
Jets
0.188
0.245
0.311
0.383
0.464
0.552
0.648
0.752
0.863
0.982
1.243
1.534
1.856
2.209
6
Jets
0.225
0.295
0.373
0.460
0.557
0.663
0.778
0.902
1.035
1.178
1.491
1.841
2.227
2.651
7
Jets
0.263
0.344
0.435
0.537
0.650
0.773
0.907
1.052
1.208
1.374
1.740
2.148
2.599
3.093
8
Jets
0.301
0.393
0.497
0.614
0.742
0.884
1.037
1.203
1.381
1.571
1.988
2.454
2.970
3.534
9
Jets
0.338
0.442
0.559
0.690
0.835
0.994
1.167
1.353
1.553
1.767
2.237
2.761
3.341
3.976
10
Jets
0.376
0.491
0.621
0.767
0.928
1.104
1.296
1.503
1.726
1.963
2.485
3.068
3.712
4.418
Figure 2M-5 - Ring out possibly caused by inadequate hydraulics and
high rotational speed on a 9-1/2” Turbine run in 12” hole (left). Right,
outside cutter wear due to high rotational speed and inadequate
hydraulics to cool the outside cutters on the 17” PDC run on a PDM.
Once Turbine performance has been established in a homogeneous formation under a
given set of operating conditions, new parameters can be estimated for a new set of
operating conditions as shown in Example Problem 2M-2.
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Example Problem 2M-2: Estimate the change in Turbine operating parameters effected
by simultaneously increasing mud weight from 75 to 100 pcf and decreasing flow rate
from 634 to 528 gpm.
2.0
POSITIVE DISPLACEMENT MOTOR SELECTION AND OPTIMIZATION
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Since Positive Displacement Motor pressure drops are typically only a fraction of those
developed by turbodrills, their selection and optimization of operating parameters is by
comparison significantly less complicated.
PDM's require more bit weight to drill effectively than do turbine assemblies due to their
slower rotational speeds. The wide range of rotor/stator lobe configurations, standard,
extended and tandem power sections and resulting range of rotational speed and torque
ratings does however, render their selection rather challenging.
Hydraulics calculations can generally be performed for PDM's by bit supplier hydraulics
programs. This is usually accomplished by adding the PDM and if present MWD
pressure losses to the drill-bore pressure losses. The system is then optimized for
Hydraulic Horsepower (65% system pressure losses at the bit) or Impact force (48% of
system pressure losses at the bit) in conventional fashion as described in Chapter 2-I.
However, with a motor in the hole these values are rarely achieved. Most motors have a
bit pressure drop restriction of from 1000-1200 psi, which precludes conventional
hydraulics optimization with standpipe pressures above 2500 psi.
Typically, 10-40% system pressure losses at the bit are achievable and run with good
results on PDM drilling assemblies. In many cases hydraulics are planned to achieve a
minimum HSI, generally 2.5 Hhp/sq.in. of bit diameter for Tri-Cone bits and an HSI of 1.0
Hhp/sq. in. or greater for PDC bits. It is also important to maintain as high a flow rate as
possible when drilling with a motor in order to cool the TCI and PDC cutters, to avoid
heat checking and premature failure.
Major considerations in PDM selection are:
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
Rotational Speed at which PDM will operate
Pressure Drop across Motor
Hydraulics which can be generated at the rock face with the motor in the hole
Time that the PDM can stay in the hole without a high probability of failure
Directional capability
Torque and power output of the motor
Economics of running a motor as opposed to turbine or rotary
Type of Bit to be run
Downhole Temperature Effect on motor elastomers
Drilling fluid type, weight and additives
In lieu of the preceding considerations, the data from example problem 2M-1 will be
used to select and optimize performance for a Positive Displacement Motor.
Example Problem 2M-3 Select and optimize performance for a Positive Displacement
Motor from Table 2K-1, to drill an open hole section from 10,500 to 12,500' with a 12"
Matrix body PDC bit, based on the following pertinent data:
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Drillpipe: 5" 19.5 ppf Grade E
Heviwate: 450' of 5" OD x 3" ID
Drill Collar Section: 360' of 8.5" OD x 2.81" ID
Mud Weight: 95 pcf;
PV: 22 YP:28 lbf/100 sq.ft. Bit Type: 12" M-432 PDC with 6
nozzles
Surface equipment case #3; equiv. to 816' of 5" Drill Pipe
Required Downhole Rotational Speed: 250 rpm
Required HSI: 1.0 Hhp/sq. in.
Required Operating Torque: 4000 ft-lb
Required Weight on Bit: 15-35,000 lb
Mud Pumps: Two Gardner-Denver PZ-11's with 6" liners rated to 4702 psi with 6" liners
@ 130 spm & 4.0 gal/stk.
Bit Weight requirement:
The BHA is checked to see if its weight is adequate to supply the needed weight when
buoyancy and a 20% safety factor are applied.
Air Weight of 8.5" drill collars = 360 x 172 ppf = 61,920 lb
Buoyancy Factor, Bf = 1-(MW/65.44)
Where MW = Mud Weight, lb/gal
65.44 = Weight of 1 gallon of steel
Bf = 1- (95/7.48)/65.44=0.806
Available bit weight, Abw is calculated;
Abw = (Cw x Bf x 1-SF)
Where Cw=Calculated Air Weight of Drill Collars, lb.
SF=Safety Factor, fraction
Abw= (61,920 x 0.806 x 0.8) = 39,926 lb., which is a little more than required but
nonetheless acceptable to avoid breaking a 90' stand.
Minimum required flow rate to adequately cool the cutters for a PDC bit, Qpdc can be
estimated as follows from Lapeyrouse;
Qpdc = 13 x Db1.5 ......................................................................................Eq. 2M-8
Where Db = Bit diameter in inches
Qpdc = 13 x 121.5 = 540 gpm
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Assume a minimum flow rate of 550 gpm. Select a motor that will develop 200 rpm and
generate the needed torque, 4000 ft-lb. The latter assumes the surface rotary will be
turned at 50 rpm.
Both 8" and 9-5/8" motors are available but none of the 8" motors develop the required
torque at the estimated 400 psi motor differential pressure. The only PDM available
which can meet all requirements is the 9-5/8" SS-962XP, which has a 3/4 lobe
configuration with extended power section, as shown in Fig 2K-14. However this PDM
requires a flow rate of at least 600 gpm. Estimated shaft speed for the PDM operated at
600 gpm = 600 gpm x 0.22 rev/gal = 132 rpm. At this circulation rate the motor should
develop about 4250 ft-lb of torque. To achieve the desired 200 rpm the circulation rate
would have to be increased to 200/.22= 909 gpm. This is too high, so plan to circulate at
700 gpm and make up the difference with surface rotary. At 700 gpm; shaft speed = 700
x 0.22 = 154 rpm.
Required Surface RPM= Required Bit Speed-PDM Speed = 250-154 = 96 rpm.
At a flow rate of 700 gpm the Selected PDM should produce 154 rpm, 120 Hp and 4250
ft-lb of torque. The hydraulics program should be run to ensure the system is functional
and the planned HSI of 1.0 Hhp/sq. in. is achievable.
The Reed Hydraulics program is run with a forced flow rate of 700 gpm. By trial and
error through manipulation of the maximum allowable pump pressure an acceptable
solution is achieved. By increasing the allowable pump pressure to 3630 psi an HSI of
1.076 Hhp/sq. in. achieved with a flow rate of 700 gpm and TFA of 1.387 inches, as
shown in Fig 2M-7. The Reed Hydraulics program makes calculations for the end of the
bit run which in this case was 12,500'.
In practice, the flow rate for this problem would have been limited to about 650 gpm.
The key to success in performance drilling is to avoid letting any one parameter, HSI,
Flow Rate, Torque etc., control the system and cause it to fail due to minimization of
similarly important parameters. Moderation and flexibility are central to the functionality
of most performance drilling systems.
Figure 2M-7 - Reed Hydraulics Program Output for Example Problem 2M-3
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2M-3
3.0
PERFORMANCE DRILL BIT AVAILABILITY AND SELECTION
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A wide variety of approved performance drill bits are currently available at Saudi
Aramco, as a result of successful implementation of the Test Trial and approval
system. The purpose of this section is to show what performance bits are
available and provide tools to aid in their selection.
3.1
Performance Drill Bit Availability
Table 2M-5 list all of Saudi Aramco's currently approved performance drill bits.
Table 2M-5 - Saudi Aramco Approved, PDC and Diamond Drill Bits
SUPPLIER
SIZE
TYPE
IADC CODE
REMARKS
Hughes
Hughes
Hughes
Hughes
Hughes
Hughes
Security
Security
Security
Security
Hughes
Hughes
Hughes
Hughes
Hughes
Hughes
Hycalog
Hycalog
Geodiamond
Security
Security
Security
Hycalog
Hughes
Hughes
Geodiamond
3-3/4
5-7/8
5-7/8
5-7/8
5-7/8
5-7/8
5-7/8
8-3/8
8-3/8
8-3/8
8-3/8
8-3/8
8-3/8
8-3/8
8-3/8
8-3/8
8-3/8
8-3/8
8-3/8
12
12
12
12
12
12
17
S-226
D-411ST
R-60ST
S-279G
S-248
G-486G
FM-2563
FM-2841
FM-2941
LX-19HSB
AG-437
AG-547
S-279G
S-725G
R-60ST
D-411ST
DS-107D
DS-43ST
MGR-32PX
FM-2863
FM-2844
FM-2943
DS-66
AG-437
AG-547
M29-PX
M-723
ST
ST
M-841
M-723
M-433
M-323
M-432
M-433
M-312
M-432
M-432
M-841
M-723
ST
ST
S432
ST
M-433
M-424
M-233
M-333
M-432
M-432
M-432
M-432
Ballaset
Natural Diam.
Side-Track
Impregnated
Ballaset
13 mm PDC
13 mm PDC
13 mm PDC
13 mm PDC
19 mm PDC
13 mm PDC
19 mm PDC
Impregnated
Ballaset
Sidetrack PDC
Sidetrack Dia.
PDC
PDC
ARCS PDC
13 mm PDC
13/19 mm PDC
13 mm PDC
13 mm PDC
13 mm PDC
19 mm PDC
13/16 mm PDC
3.2
Breakeven Analysis
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Bit breakeven analysis gives a general indication of the required rotating time
and footage for a bit of a different price to equal the performance, in terms of cost
per foot of a reference bit run. The standard procedure assumes that the new bit
being evaluated drills at the same overall average penetration rate as the
reference bit for the breakeven time calculated. With the aforementioned
constraints, breakeven time, T2, can be calculated:
T2 = B2 + R(t)
C1 (F/T)-R
.......................................................................Eq. 2M-8
Where:
T2 = Breakeven time, hrs
B2 = Cost of new bit, $
R = Rig cost, $/hr
t = Trip time, hrs,
C1 = Reference bit cost, $
F/T = Original ROP, ft/hr
Example Problem 2M-4: Calculate the breakeven rotating time and footage for a
12" IADC Code 517 sealed bearing TCI bit which cost $9650 compared to the
lower priced ($2450) non-sealed bearing reference bit, normally used to drill the
section. Pertinent data is as follows:
Previous bit rotating time = 35 hrs
Footage drilled = 1175 ft
Rig operating cost = $37,500/day
Round trip time = 12 hrs
Reference bit footage cost, C1 is calculated with the conventional footage cost
equation:
C1 =B + R (T + t)
F
T2 =
= 2450 + (37,500/24) (35 + 12)
1175
9650 + (37,500/24) 12
= 28,400
64.59 (1175/35) - 1562.50
605.79
= $64.59/ft
= 46.88 hrs
Breakeven footage = Breakeven hours x Reference bit ROP
= 46.88 x (33.57) = 1574 ft
Frequently, we need to know what penetration rate is required for a performance
drilling system such as a Turbine/PDC assembly, to match the cost per foot of a
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conventional drilling system, such as rock bit and rotary. To account for the
increased operating cost of the motor or turbine and the fact that their charges
are only incurred while drilling and circulating, the procedure shown in Example
Problem 2M-5 can be used to calculate the breakeven ROP.
Example Problem 2M-5: Offset drilling data indicates a Turbine/PDC
performance drilling system can reduce drilling cost from that achieved with a
conventional Rotary/PDC assembly which averaged 9.0 fph. The contention is
based on the higher ROP's achievable with the high rotational speeds of the
turbine. What penetration rate is required by the more expensive Turbine/PDC
system to achieve breakeven cost per foot based on the following:
12" PDC cost = $60,000 Turbine Charges (Only on rotating time) = $250.00/hr
Rotary/PDC bit run data:
Bit Cost = $55,000
Rig Cost = $25,000/day
Footage Drilled = 1035'
Average ROP = 9.0 fph
Trip time=12 hrs
Rotating time = 115 hrs
First calculate the previous bits footage cost, C1:
C1 = 55,000 + (25,000/24) (115 + 12) = $180.96/ft
1035
Since the turbine charges are only incurred while rotating, its cost must be
calculated as follows:
C2 = [B2 + (Ct x T2)] + R (T2 + t) .........................................Eq. 2M-9
F2
Where: Ct= Rental Cost for turbine or motor, $/hr
F2= Footage drilled by the second bit, ft
T2= Rotating time for second bit, hrs
Setting the turbine footage cost equal to the reference bit runs footage cost and
solving for T2, turbine rotating time, yields the following equation:
T2 = (C1 x F) - [B2 + (t x R)] = (180.96 x 1035) - [60,000 + (12 x 1041.66)]
R + Ct
(1041.66 + 250)
= 88.87 hrs
Breakeven ROP = Footage/Breakeven Hrs = F/T2 = 1035/88.87 = 11.65 fph
This is the minimum ROP at which the Turbine/PDC assembly would match the
reference bits footage cost. Anything faster would result in lower footage cost.
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3.3
Expected Value Cost Analysis
The expected value technique is often used to arrive at a justifiable economic
decision based on historical cost of events and the probability of their
occurrence.
The basic expected value equations are as follows:
EV = C1P1 + C2P2 ..............................................................................Eq. 2M-10
P1 + P2 = 1 .........................................................................................Eq. 2M-11
Where:
P1 = Probability of the first event occurring
P2 = Probability of the second event occurring
C1 = Cost of the first event
C2 = Cost of the second event
Expected value footage cost, Evf can be calculated by letting Cg equal the
calculated cost of a bit run without severe hole problems, i.e., twist offs, stuck
pipe, side-tracking etc., and letting Pg equal its probability of occurrence. Fg
represents the footage drilled on the trouble free run.
Cb represents the mean cost of bit runs in which severe hole problems occurred
and Pb represents the probability of a bad bit run occurring.
From the review of recent historical drilling data the probability of a bad bit run
occurring, Pb can be calculated along with the mean cost of the occurrence. Fb
represents the mean footage drilled on problematic bit runs. Expected value
footage cost, Evf, can then be calculated as:
Evf = Cg Pg + Cb Pb
Fg
Fb
...................................................Eq. 2M-12
An expanded version of the conventional drilling footage cost equation should be
used to calculate footage cost for all runs. The footage cost equation should use
actual trip time to account for excessive reaming observed with some PDC/PDM
or PDC/turbine assemblies. It should also take into account any trouble time
experienced with a given bit run.
Cpf = (Bc + Mc +Tc + Cc + Fc) + Rc(Tt + Wt + Rt +St + Ct) ............Eq. 2M-13
F
Where:
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Cpf =actual cost per foot, $
Bc = bit cost, $
Mc = drilling fluid cost for the interval, $
Cc = rotating and circulating cost for the PDM or Turbine, $
Tc = cost of tools or repairs to tools, $
Fc = fishing or any related trouble cost, $
Rc = rig operating cost, $/hr
Rt = bit rotating time, hrs
Tt = round trip time, hrs
Wt = time for wiper trips required to drill ahead, hrs
St = directional survey time, hrs
Ct = connection time, hrs
F = Footage drilled,
Example Problem 2M-6: Calculate and compare the actual footage cost for PDM/PDC
and Turbine/PDC performance drilling systems based on the following:
PDM/PDC Drilling Assembly:
Drilled 1400' in 104 hrs. Bit Cost; $55,000, Mud cost = $11,400, PDM cost = 104 hrs x
$250/hr = $26,000, Trip time = 13 hrs, Rig cost = $30,000/day, one wiper trip had to be
made which consumed 6 hrs.
Turbine/PDC Drilling Assembly:
Drilled 1624' in 97 hrs. Bit Cost; $55,000, Mud cost = $13,750, FBS Turbine cost = 97 x
$350 per hour = $33,950, Trip time = 13 hrs, Rig cost = $30,000/day, no wiper trips were
made.
For the PDM/PDC run of 1400':
Cpf = (55,000 +11,400 + 0 +26,000) + [(1250(13 +6 +104 +0 + 2.9)] = $178.41/ft
1400
For the Turbine/PDC run of 1624':
Cpf = (55,000 +13,750 + 0 + 33,950) + [(1250(13 + 0 + 97+0 + 0)] = $147.91/ft
1624
The Turbine/PDC assembly offers the lowest actual cost for the two runs evaluated.
Example Problem 2M-7: Three performance drilling systems have recently been used
to drill the massive Cotton Valley Formation.
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Seven runs have been made with a Turbine/PDC bit assembly. The best run to date has
been with the Turbine/PDC assembly for a startling $145.35/ft. Average cpf for all of the
good runs was $187.50/ft. Bit sticking problems were encountered on two of the runs,
with average footage cost of $795.00/ft.
Five PDM/PDC runs have been made, with motor failure occurring on one well. Average
cpf for the good runs was $259.23/ft and $358.67/ft on the well where stuck pipe was
incurred and had to be worked free.
Two Rotary/TCI bit runs have been made with average cost of $290.00/ft and no major
problems.
Which performance drilling system will offer the lowest expected value footage cost?
Turbine/PDC
Pg = 5/7 = 0.714
Pb= 2/7 = 0.286
EVcpf = (0.714 x $187.50) + (0.286 x $795.00) = $ 361.25/ft
PDM/PDC
Pg = 4/5 = 0.8
Pb= 1-0.8 = 0.2
EVcpf = (0.8 x $259.23) + (0.2 x $358.67) = $ 279.12/ft
Rotary/TCI
Pg = 2/2 = 1.0
Pb= 1-1 = 0
EVcpf = (1.0 x $290.00) + (0 x 0) = $ 290.00/ft
The PDC run on a PDM offers the lowest expected value cost per foot of $279.12/ft.
4.0
PERFORMANCE DRILLING SYSTEM OPTIMIZATION
4.1
Development of the Minimum Cost Drilling Plan
A tremendous amount a drilling data is generated by Saudi Aramco Drilling
operations. Approximately 2000 bit runs are made each year. The M-204
Database, Spreadsheet Programs and graphical analysis techniques can be
availed to access, interpret and optimize bit and drilling system performance on a
broad, representative and meaningful scale.
Example Problem 2M-8: Fabricate a minimum cost bit program for HWYH-958,
a K-2 Vertical Jauf Well to be drilled to 15,150' utilizing all relevant available data:
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Step One:
Use the M-204 data base Well Search Option to review all the wells drilled to at
least 12,000' in a 20 km radius around HWYH-958.
Step Two:
Print out bit records from the well search, for the wells which have been drilled
within the last three years.
Step Three:
Enter the bit records into an Excel Spreadsheet Program. The data needed from
the bit records for this analysis are Well number, Bit Run Number, Bit size, type,
manufacturer, IADC Code, bit cost, depth in, depth out, remarks, rotating time,
circulation rate, pump pressure, mud weight, nozzle sizes, PV, YP, rotational
mode, cost of motor or turbine if used, dull grading, pertinent remarks, bit weight
and rotary speed.
The spreadsheet should be set up to calculate, drilling cost per foot, footage,
ROP, mean drilling depth, bit Hhp/sq. in., bit pressure loss, hydraulic impact
force, jet velocity and WR product. Separate spreadsheets should be made for
each hole size, such as 22, 17, 12, 8-3/8 and 5-7/8" hole.
Figure 2M-7 - Excel Spreadsheet used to analyze offset bit run data
Step Four:
Once the data has been input into the spreadsheets, it can be manipulated to
statistically and graphically analyze the data. The sort data function can be
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availed to sort the bit runs by cost per foot, (ascending) such that the best bit
runs in each section appear at the top of the spreadsheet as shown, in Fig 2M-7.
For a quick look at bit and drilling system performance, calculated cost per foot
should be plotted against mean drilling depth as shown in Fig 2M-8 for 12" bit
runs in the HWYH-958 Area. The Excel chart options function can be used to
perform linear, logarithmic, polynomial, power, moving average or exponential
curve fits of the data, generate equations for the line, along with correlation
coefficients to check the goodness of fit. The equation which best fits the data
can be used as a benchmark for footage cost vs. depth for the given hole size
and area.
Figure 2M-8 - Plot of Cost per foot Vs. Mean Drilling Depth for 12" bit runs
S-86F
M-84F
M-89F
HP-62A
AG-547
M-84F
Step Five:
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Circle the bits that offered the lowest cost per foot at each depth. Connect the
points. The line drew represents the unrefined minimum cost bit program for the
given hole section.
Step Six:
Pencil in the estimated formation tops. Draw vertical lines representing each on
the graph. Investigate all available aspects of the selected minimum cost bit runs
with the daily drilling reports and bit records. Avail compressive strength charts
to aid in determining exactly where specific bit runs should be made. Formulate
and refine the minimum cost bit plan from casing point to casing point.
Step Seven
Repeat the procedure in Step Six for each hole size. Use the detailed run
information from the actual bit records and morning reports to "emulate the
operating parameters" such as bit weight, rotary speed and hydraulics; under
which highly successful bit runs were made. Use scatter plots of various drilling
parameters such as per cent pressure loss at the bit vs. ROP and Weight on Bit
vs. ROP, to further refine the program.
Step Eight
Compile the data in the form of a minimum cost bit program and include it in the
drilling program, as shown in Figure 2M-9.
Step Nine
When the bits are run, run drill-off test, as detailed in section 2-I, to confirm that
the weight and speed being used is optimum. If the formation is too
heterogeneous to get a competent drill-off test, a prior low-cost bit run of the
same type can be emulated, and should yield very similar results. Alternatively,
iso-cost graphs, contoured from plots of Rotary Speed vs. Bit Weight as shown in
Fig. 2M-11 can be used to select the optimum weight and speed.
Step Ten
As the bit run is being made, a plot of rotating time Vs. Cost per foot should be
maintained as shown in Figure 2M-12. When footage cost reach a minimum,
then start to increase, in the absence of an acute changes in formation drillability,
the bit should be pulled. The latter will yield minimum footage cost.
Fig 2M-9 - Example Minimum Cost Drilling Program with Optimum Bit
Weights, Rotary Speeds and Hydraulics
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Fig 2M-11 - Iso-cost graph to determine optimum Weight & Rotary Speed
C ost P er F oot
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Figure 2M-12 - Plot of Cost per foot vs. Rotating time for Berri - 402
C o s t p e r F o o t V s . R o ta tin g T im e - B e r r i-4 0 2
9 -1 /2 " T e ib o T u r b in e R u n in 1 2 " H o le
Drilling Cost, $/Ft
3000
2500
2000
1500
1000
500
0
0
20
40
60
80
R o ta tin g T im e , H o u r s
100
120
Figure 2M-13 - Cost per foot vs. per cent pressure loss at bit
% Pressure Loss
$ /F t v s . %
P re s s u re L o s s @
B it
1 0 0 .0
y =
8 0 .0
-0 . 1 0 0 6 x + 4 4 . 6 5 3
R 2 = 0 .0 2 8 6
6 0 .0
4 0 .0
2 0 .0
0 .0
0
20
40
60
80
$ / ft
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INTRODUCTION TO DRILLING FLUIDS
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INTRODUCTION TO DRILLING FLUIDS
1.0
FUNCTION OF DRILLING FLUIDS
1.1 Hydrostatic Pressure
1.2 Cuttings Transport
1.3 Filtration Control
1.4 Mechanical Stabilization
1.4.1 Shale Instability
1.4.2 Chemical Inhibition
2.0
PROPERTIES OF DRILLING FLUIDS
2.1 Density
2.2 Rheological Properties
2.3 Filter Cake Quality
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INTRODUCTION TO DRILLING FLUIDS
Drilling operations success depends significantly on the performance of the fluid being
circulated down the rotating drill pipe, through the bit, and up the annular space between
the pipe and the formation. The drilling fluid design, formulation and reactions with the
subsurface formation are crucial. “Drilling mud” is a more widely accepted name for
drilling fluids prepared by mixing water with natural formation clays or commercial
bentonite. “Drill-in fluids” are special drilling fluids formulated without bentonite, barite
and other insoluble materials. The absence of barite helps to ensure that the Drill-in
fluids are less damaging to the pay zone natural permeability. A large number of the
formation damage mechanisms can arise from the interaction between the reservoir rock
minerals and the induced fluids. Drilling fluids have solid and liquid components. There
is no such thing as a universal “non-damaging” drilling fluid. Each reservoir to be
drilled should be taken on a case by case basis and the least impairing “Drill-in fluid”
formulation can be selected. Laboratory methods of examining the residual damage
caused by the different fluid formulations are available and should be carried out prior to
actually drilling the well.
1.0
FUNCTION OF DRILLING FLUIDS
Drilling muds have many functions in the drilling operations. At any one time in the
operation, one function may be more important than the other functions for that
drilled interval, which is why a mud program is essential in well planning.
Drilling Muds should provide:
•
•
•
•
•
•
•
Control of subsurface pressures to overcome gas, oil, and water flows.
Removal and suspension of drilled cuttings and weighting material.
Proper borehole stability.
Reliable geological and reservoir rock information.
Lubrication and cooling of the bit and drill string.
Minimum formation damage.
Corrosion control.
Some publications may list ten to fifteen different functions of a drilling fluid. Many
of these are variations of the same function. This section will discuss:
•
•
•
•
Generating hydrostatic pressure downhole.
Removing cuttings a head of the bit and transporting them to the surface.
Controlling invasion of filtrate into the formation.
Stabilizing the formation mechanically and chemically.
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1.1
Hydrostatic Pressure
Filling a hole with a fluid will inevitably generate a hydrostatic head or
pressure as illustrated in Figure 3A-1. This is calculated by the use of the
following equation:
Hydrostatic Head
HH (psi)
or HH (psi)
=
=
(Conversion Constant)
0.0695
0.052
X
X
X
(Mud Density)
MW (lb/cu.ft.)
MW (lb/gal)
X
X
X
True Vertical Depth
TVD (feet)
TVD (feet)
Downhole pressure needs to be controlled for two reasons:
•
•
The drilled rock must be supported and stabilized.
The pressure of gases and fluids in the rock must be exceeded so they
do not enter the wellbore. This is particularly important for safety.
As the mud density supports the rock, excessive downhole pressure can also
damage it by “fracturing” it in the manner that a hose pipe can be split by too
high a pressure.
A key to a successful operation is the knowledge of the formation stresses,
formation strength, and pore pressures, so that the correct mud weight and
casing depths can be selected. Hopefully, the casing depths will isolate
problem sections.
The pressure applied by the mud column will depend on whether the mud is
static or being pumped.
Drill Pipe
Drilling Fluid
Cement
Casing
Hydrostatic Head
Casing shoe
Drill Collars
Drill Bit
Water Flow
High Pore Pressure
Figure 3A-1- Hydrostatic Head
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The additional pressure used to overcome frictional losses and viscosity
effects generates additional pressure, and the sum is referred to as
Equivalent Circulating Density (ECD).
ECD = Hydrostatic Head + ∆P
1.2
Cuttings Transport
One of the most important functions of the drilling fluid is to efficiently remove
the freshly drilled rock fragments from around the bit and transport them to
the surface, where they can be discarded. The ability to achieve this
objective is dependent on the annular velocity and the properties of the
fluid. The speed at which the fluid is pumped up the annulus should be
greater than the slip velocity [the rate at which the cuttings will settle through
the moving fluid]. Annular velocities between 100 and 200 ft/min are
frequently used. The density of the fluid has a buoyant effect on the cutting
particle so that an increase in density will increase the fluid carrying capacity.
Also, the viscosity related characteristics considerably influence the fluid
carrying capacity.
Drilling progress can only be made if the cuttings are removed from the
wellbore and separated and discarded at the surface. Cuttings removal
involves four steps:
•
Removing the cuttings away from the area of the bit where the cuttings
are generated
•
Transporting the cuttings to the surface in the annular space between
the drill pipe and the wall of the hole
•
Suspending the cuttings at the surface to allow separation
•
Suspending the cuttings in the hole when the pump is off
Moving cuttings away from the bit is controlled by the pump rate and bit
hydraulics. The mud properties can only improve the mud lifting capability
and ensure cuttings and solids suspension. Enough volumetric flow is
needed to sweep the bit and move the cuttings out of the hole. Figure 3A-2
shows a typical chip removal from the face of the bit.
Fast drilling rates can overload the volumetric flow past the face of the bit,
resulting in re-grinding the chips cut by the bit. High drill rates, especially at
shallow depths, can load up the annulus, resulting in excessive hydrostatic
head. Annular flow rate, therefore, is critical for proper hole cleaning.
Transporting the cuttings up the annulus is also dependent on having the
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proper rheological properties (viscosity) as well as flow rate.
regime, turbulence or laminar, is important for good hole cleaning.
The flow
In high angle and horizontal wells, maintaining both drilled cuttings and
weight material in suspension requires progressive gel strengths and high
"low-shear rate viscosity".
Wall cake
Drill Pipe
Cuttings
Drill Bit
Bit Jet
Bit Teeth
Figure 3A-2- Chip removal from the face of the bit.
Drilling fluids should have the ability to form a reversible gel structure when
circulation is stopped (Thixotropic properties), so that the cuttings and
weighting material remain suspended. Upon resumption of circulation the
fluids revert to there initial flow properties.
1.3
Filtration Control
The fluid loss properties of mud may effect the penetration rate, hole
instability, formation damage, and differential sticking.
The total amount of fluid lost to the formation is dependent upon:
•
•
•
•
•
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Pressure difference between mud column and pore pressure (∆P)
Base fluid viscosity
Formation permeability
Filter cake permeability
Temperature
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Mud filtration is even more critical when drilling depleted zones and higher
permeability formations.
Fluid invasion can also occur in fractured
formations, especially if the mud hydrostatic head is significantly higher than
the formation pressure.
Filtrate invasion into producing zones is one of the leading causes of
formation damage, resulting in reduced production. Not only the amount of
filtrate but the type is important. For this reason, an inhibitive fluid may be
used. Brine-based muds are often used to minimize damage.
The filter cake quality is essential in maintaining good fluid loss control. Poor
filter cakes and high fluid losses can lead to excess drag and differential
sticking. Figure 3A-3 shows the formation of the filter cake. The basis of
good filtration control in high temperature water-based muds is to have the
optimum concentration of high quality bentonite particles. Bentonite forms a
tight, low-permeability thin filter cake. High temperature fluid loss control
additives must be used to reach very low fluid loss levels. Also at high
temperatures, further additives may be needed to overcome temperature
degradation. If high concentration of poor quality bentonite is used in a high
temperature well, excessive mud thickening will develop, which can cause
dramatic increase in the surge pressures while moving the drill string in and
out of the hole. In gas wells, this causes well control problems and blowouts.
Mud Pressure
Pm
Drill solids
Mud Filtrate
Pore Fluid
Pressure PO
Pressure Forcing
Fluid into Formation
∆P= Pm - Po
Bentonite
Particle
Figure-3A-3 Formation of the wall cake
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1.4
Mechanical Stabilization
1.4.1
Shale instability takes many forms and can result in a variety of
problems while drilling. These problems range from minor delays and
increased daily costs to stuck pipe and lost wellbores. The following
list contains some of the more common problems experienced:
•
Fill and bridges: Mud solids and cuttings settled on bottom
after trips or connections are called fill. Bridges are tight spots
encountered higher up the hole on trips. These problems result
in expensive reaming operations, mud treatment, and possibly
excessive bit wear or damage. You must be certain that this
problem is not caused by lack of proper hole cleaning, either
from poor rheology or low pump output.
•
Ineffective hole cleaning:
Additional formation cavings
entering the wellbore due to the rock failure and collaps may
overload the capacity of the annular circulating flow rate to carry
all the rock fragments out of the wellbore.
•
Stuck pipe : Probably the most costly result of hole instability is
a stuck pipe. If the pipe is stuck, it will, at the least, take some rig
time to correct and, at worst, result in the hole being lost.
•
Increased hole volume: Severely washed-out holes may result
in higher mud costs, increased cement requirements, and poor
cement jobs.
•
Logging difficulties: Washed-out hole, fill and bridges can
seriously interfere with getting good electric logs and sidewall
cores.
Wellbore Drilling Terms
Through the years, various terms have been used to describe
the problems associated with wellbore instability while drilling.
Different parts of the world use different words to describe the
same phenomena. The following are some of the terms and
their usual interpretation.
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Sloughing, Running, Heaving: These words describe the
general condition of excess pieces of formation showing up on
the shale shaker. They are usually associated with hard
dewatered shales.
Mud Making Shales, Gumbo, Bentonitic Swelling, Plastic
Flow: These conditions usually refer to drilling through
formations high in bentonite or other swelling clay content such
as recent volcanic sediments. These clays may disperse into
the mud or extrude into the wellbore. Plastic flow also is
encountered when drilling massive salt sections.
Fractured Shales: This term is usually applied to tectonically
stressed areas (mountainous) with known highly faulted or
highly dipped formations.
Pressured Shales, Gas-bearing Sands: These terms are
applied when excess shale volume is experienced along with
gas intrusions. It is usually caused by insufficient mud weight.
•
Sloughing: Sloughing consists of unconsolidated, weak,
or loose formation that may fall into the wellbore due to the
geological nature of the formation. Sloughing usually
occurs at shallow depths. The hole may or may not be
enlarged, since weak formations will flow and fill in the
areas being washed away.
•
Induced sloughing: This refers to formation that falls into
the wellbore as a result of water-wetting clays or washing
out cementitious materials (salts, etc.).
Dissolving
cementitious materials usually occurs at shallow depths
and results in a washed-out hole. Water wetting and clay
swelling may occur at greater depths when hydratable
clays are present.
•
Heaving: This formation instability is caused by formation
pressures higher than the hydrostatic head from the mud.
Hydratable clays in the formation may aggravate this
condition. The pieces of heaving shale crossing the
shaker are usually square or rectangular and vary in size
from cuttings size to several inches. Often the pieces have
rounded edges. This indicates that the piece is slipping
and tumbling in the annulus, causing the edges to wear.
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•
Spalling: Spalling or splintering occurs when pressures in
the formation cause the hole to close radially. This can
occur at any depth and typically is found in highly
tectonically stressed areas. Plastic flow of massive salt
sections is a special case of this phenomena. Splintered
shale pieces are usually long and narrow with sharp edges
and points. Many times they are slightly curved, showing
the shape of the wellbore.
The most common cause of unstable formations is mechanical
instability resulting from the imbalance of formation stresses. The
stress balances created in the earth over millions of years is disrupted
when a hole is drilled into it. These internal formation stresses have
to be rebalanced or the wellbore will collapse. Most formations have
enough strength that they do not immediately collapse. Given
sufficient time, however, most formations will eventually start
collapsing. There is a time-value associated with hole instability
based on the geology of the formation, the mud density, and the type
of mud in the hole.
The subsurface stresses being applied are:
•
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Overburden pressure, S: The overburden pressure is the
pressure exerted by the weight of the earth's rocks above the
element. The overburden pressure depends upon the mineral
make-up of the rocks and, in general, can be assumed to be
about 1.0 psi/ft. It is not linear, however, because the formation
density tends to increase with depth as a result of compaction
and reduction in porosity.
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Surface
Column of
Pore Fluid
S
Overburden Pressure
(Mass of overlying Formation rocks
& Pore Fluids)
σ
Matrix or intergranular stress
between grain boundaries
S = PO + σ
PO
Pore Fluid Under Pressure
Figure 3A-4- Origin of Stress in Subsurface Rocks
•
Pore pressure, Po: The pore pressure is the fluid pressure
within the pore spaces of the formation helping to support the
overburden pressure. If the fluids in the pore spaces are
interconnected and have not been trapped, the pore pressure is
equivalent to the hydrostatic head of the water column above the
formation element shown in Figure 3A-4. Pore fluids are
predominantly salt water, so the pore pressure in normally
pressured formations is taken to be a column of water with
seawater salinity. This is equal to a gradient of about 0.046
psi/ft. On a graph, the pressure gradient is approximately a
straight line although the temperature gradient will influence the
density.
•
Matrix stress, σ: The matrix stress is the portion of the
overburden pressure that is supported by the physical structure
of the formation. It can be resolved into three components that
are perpendicular to one another (one vertical stress and two
horizontal ones). In most cases, only the overall matrix stress
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can be examined since the three components must be
measured in situ. (Approximations of the three principal stresses
have been done in the past from log and seismic-derived data).
The total matrix stress for normally pressured formations is
about 0.054 psi/ft.
•
Wellbore stress: The drilling of a hole in the stressed rock
generates a new higher stress field or “hoop stress”, which is
related to the stresses at right angles to the wellbore. These
stresses decay to the initial stress as you move away from the
wellbore. Filling the hole with mud exerts a pressure (Pm) that
reduces the tangential stress.
The drilling technique uses the minimal mud weight to balance
additional weight to the pore pressure and then to reduce the rock
stress to a level where it is stable. No attempt is made to balance the
stress perfectly, as the higher mud weight will slow down the rate of
penetration.
This technique puts the rocks under stress and leads to failure.
Subsequent reaction of rocks with the drilling fluid is often enough to
stress the rocks to a point where they fail. The adsorption of water
takes some time and contributes to the time dependency of the
stability of rocks.
Formations that contain high levels of the clay mineral montmorillonite
will retain the water while under the overburden pressure. This
means that the pore fluids will bear a disproportionately high amount
of the overburden pressure. Also, the matrix stress will be low. The
mud weight will have to be increased to hold back the formation.
Tectonically stressed areas pose a special problem since these
formations have been fractured and folded. Fractures may allow the
penetration of whole fluid that can transmit pressures into the
formation, causing it to weaken and fall in. Also, when folded
formations are drilled, part of the wellbore face may be highly
compressed while another part may be in tension. It is nearly
impossible to calculate the relative principal stresses in this case, but
there is usually one that will approach zero. Mud weights higher than
indicated by pore pressure analysis (gas pressure) are usually
needed to stabilize the formation in this situation. The amount of mud
weight needed should be determined in the field only on a case-bycase basis.
Whenever the stresses at right angles to the wellbore are not equal,
the wellbore will fail in the direction of least stress and produce an
oval or elliptically shaped hole.
This situation will often be
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encountered when drilling deviated holes because the vertical stress
tends to be larger than the horizontal stress. Tectonically stressed
areas may also show the same phenomena. Directional drilling in an
oval hole is difficult, but this problem cannot be overcome.
The following factors are involved in shale instability from
physical causes:
• Density: The proper density is the most important factor in shale
stability.
• Erosion: Proper hydraulics, annular and bit, must be maintained
in formations prone to instability. Once instability started, by erosion
or other factors, it can be difficult to stop.
• Pressure surges/swabs: Excessive surges and swabs when
tripping or running pipe can initiate instability. Rocks are much
weaker in tension so they are prone to fracture, which can occur when
running pipe too fast into the hole. The fractured rock is more likely to
produce problems later on.
• Direct contact: Minimize pipe whip by maintaining the proper
pipe tension and rotation.
• Fluid invasion: In fractured formations, whole mud can invade
and cause instability. In some cases, high fluid losses can also help
weaken a formation.
1.4.2
Chemical Inhibition
The consolidation process and the overburden pressure force water
out of the shales. Relief of the confining force and re-exposure to
water causes the water to adsorb very strongly onto the clay surfaces.
The following changes also occur.
Stress increases around the wellbore.
•
The shale swells and weakens.
•
Lubrication is provided for slippage planes.
•
Plastic shales deform into wellbore, giving tight hole conditions.
•
Harder shales generate cavings.
•
Time related instability occurs as water migrates into rock
•
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A)
These changes in rock properties inevitably result in many
problems, including:
•
•
•
•
•
•
•
•
•
•
•
B)
Poor directional control
Washed out hole
More solids to be removed at surface
Reaming
Stuck pipe due to hole collapse
Bit balling
Additional solids into the mud
Hole failure
Poor hole cleaning in washed out sections
Tight hole
Dispersion of solids into mud
The magnitude of this problem depends on:
•
•
Type of formation: Shales with montmorillonite or mixed
layer clays are more susceptible to dispersion, swelling,
and bit balling.
Type of drilling fluid: Fresh water is most reactive
A lot of effort has gone into designing mud systems with “inhibition” or
increased ability to minimize the reaction between the mud and the
shales. The approach is to change the exchangeable cation or to
expel water from the clay surface.
•
•
•
•
•
•
Exchange sodium ion for calcium
Exchange sodium and calcium for potassium
Exchange sodium and calcium for low molecular weight cationic
polymers
Adsorb high molecular weight polymers such as (PHPA) to coat
the clay surfaces and displace water
Add polyglycerol to displace water
Plug fractures with asphalt and gilsonite
Specific mud formulations and additives are discussed in the Waterbased Drilling Fluids section 3-B.
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Formulating the drilling fluid with oil can eliminate the problem with the
reaction of the shale with water. The adsorption forces are so well
developed that high levels of salt have to be dissolved in the water,
which is present as an emulsion, to prevent the shale from hydrating.
Oil-based Drilling Fluids formulation and application will be discussed
in a separate section 3-B
C)
The following field practices are used to minimize problems
from unstable formations:
•
Density control: Maintain the proper density.
If in
mountainous areas, more mud weight may be needed than
indicated by gas pore pressures. Surges and swabs must
be avoided in formations susceptible to falling in. Keeping
the wellbore full of fluid on trips is also good practice for
wellbore stability as well as blowout protection.
•
Rheology: Adequate hole cleaning is needed to remove
any formation pieces falling into the hole and to
differentiate between unstable formations and a hole
cleaning problem.
Turbulence may wash out
unconsolidated and weak formations. Turbulence may
also aggravate a formation in which hydratable shales
have started falling into the wellbore.
•
Fluid loss: The API fluid loss by itself is not an indication
of relative formation protection. The level of fluid loss
control must be based on field experience for each
individual drilling area.
•
Hole deviation: In high angle wellbores, and fractured
formations with deviation problems, extra care must be
taken to protect against unstable formations.
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2.0
MAIN PROPERTIES OF DRILLING FLUIDS
Mud engineers use standardized tests to measure the physical and chemical
properties of the drilling fluid. The well site data generated determine if the mud is
functioning properly.
The American Petroleum Institute's Drilling Fluids
Standardization Committee administers these test procedures (API Committee 3,
subcommittee 13).
This section discusses the following common properties and how these properties
relate to the mud performance:
•
•
•
•
Density
Rheological properties
Filter cake quality
Inhibition
2.1
Density is the weight of a given volume of fluid. It can have units of:
A)
B)
C)
D)
Pounds per cubic foot, lb/ft3
Pounds per gallon, lb/gal
Kilograms per cubic meter, kg/m3
Grams per cubic centimeter, g/cm3
3
Mud Density lb/ft lb/gal
0
0
37.4
5
Air
Mist
Foam
Oil
62.4 Water
Oil/Water Emulsion
74.8
10
Salt saturated
56–62 lb/ft3
3
CaCO3
CaCl2 87 lb/ ft
110 lb/ft3
112.2
15
149.6
20
74.8 lb/ft3
Barite (BaSO4 )
Iron Oxide
187.0
Fe2O3
Galena (PbS)
156 lb/ft3
25
194 lb/ft3
224.4
30
>220 lb/ft3
Figure 3A-5 The range of mud weights that can be achieved using various types
of weighting materials (salts, calcium carbonate, barite, iron oxide, and galena).
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2.2
Rheological Properties: Rheology is the study of the viscosity
characteristics of a mud. Viscosity (the internal resistance of a fluid to flow) is
a measure of thickness or thinness. On a drilling rig, the viscosity is
measured in several different ways, including:
•
•
•
•
Funnel viscosity: Used for quick and easy indications of viscosity
changes
Plastic viscosity: Related to the solids content of the mud
Yield point: Related to the chemical forces acting on the mud solids
Gel strengths: Related to suspension and time-based thickening
tendencies
Rig personnel can measure the funnel viscosity of the mud, but the mud
engineer using a viscometer must measure the other viscosity properties.
2.3
Filter Cake Quality: Control of mud filtrate loss is directly related to the filter
cake quality. The factors that affect cake quality are:
•
•
•
•
Particle size distribution
Long-chain polymers
Compressibility
State of flocculation of the mud
To get a filter cake with low permeability, mud solids particle size distribution
from submicron to multimicron is needed. Of all the particles in a mud, the
flat, platelike bentonitic particles form the most smooth, even, and least
permeable bridging material. Drilled solids normally change this distribution to
larger, more permeable cakes. Commercial bentonite and long-chain
polymers help in making a tougher and thinner wall cake.
Filter cakes from drilling fluids have a wide range of compressibility. The
nature and size of the solid particles in the cake determine the amount of
compression. Filter cakes that are highly compressible will be compacted as
the differential pressure goes up. This gives a lower permeability and reduced
filtrate volume into the formation. Incompressible cakes will not compact, and
the filtrate into the formation will increase in direct proportion to the differential
pressure. Bentonite forms the most compressible cake, compared to cakes
with drilled solids and barite. Therefore, in addition to the total solids content
of the mud, the solids content of the mud should be analyzed for high and low
gravity solids and bentonite content. The barite content is set by the mud
weight being used. Adequate bentonite content should be maintained and
the drilled solids content should be minimized to obtain a compressible filter
cake
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The compressibility of the cake can be measured in the field. Simply use a
High Temperature / High Pressure (HTHP) filter press at two pressures, the
higher twice the pressure of the lower. A slight increase, or lowering of the
filtrate at the higher pressure, indicates a compressible cake.
Flocculated solids in a mud result in thick, weak filter cakes. Salts or
saltwater, cement contamination, cause flocculation. In addition, higher
temperatures cause clays to flocculate. Polymeric dispersants are used to
deflocculate the mud system. The submicron sizes created by many of these
chemical thinners give low API fluid loss values. A build-up of these particles,
however, tends to reduce drilling rates.
Note: Drilling fluid properties such as density, viscosity, solids content and
fluid loss can influence the rate of penetration. Drilling fluid transmits
hydraulic horsepower to the bit and should have minimum suspended
solids to achieve maximum drilling rate.
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TYPES OF DRILLING FLUIDS
1.0
INTRODUCTION
1.1 Base Fluids
1.1.1 Air
1.1.2 Water
1.1.3 Oil
1.2 Common Additives
1.2.1 Weight Contol Additives
1.2.2 Clay
1.2.3 Polymers
2.0
WATER–BASED DRILLING FLUIDS
2.1 Overview
2.2 Bentonite Mud
2.3 Lime-Treated Mud
2.4 Summary
3.0
OIL-BASED DRILLING FLUIDS
3.1 Balanced Activity
3.2 Rite Site Procedures
3.3 System Problems/Solutions
3.4 Advantages/Disadvantages
3.5 Summary
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1.0
INTRODUCTION
Drilling muds are composed of a base fluid and additives. The additives perform certain
functions or adjust one or more of the mud’s properties.
Common Base Fluids:
Air, Water, and Oil.
Common Additives:
Weight Control Additives (barite, calcium carbonate…etc),
Viscosifiers (bentonite, polymers…etc),
Deflocculants or Thinners (fluid loss/filter cake controllers).
1.1
Base Fluids
1.1.1
Air
Air is used to lower the hydrostatic head to drill depleted and underpressured formations. Fast drilling rates can be maintained with ultralow densities. High volume air compressors are needed to maintain
the volumetric flow required for cleaning the hole.
If water is encountered in formations being drilled with air, the fluid
must be converted to mist by adding surfactants. Water flows are
best handled by converting the fluid to foam with foaming agents and
a stabilizer. Foam stabilizers are usually drilling fluid polymers such
as xanthan gum or hydroxyethyl cellulose (HEC). Air is not currently
used in Saudi Aramco's fields, but nitrogen is frequently used in well
completion operations.
1.1.2
Water
By far, most of the muds in the world use water as the base fluid.
Usually it is fresh water, but brackish and salt waters are often used
for supply or economic reasons. A chloride content of about 5000
ppm is the upper limit for mud to be considered fresh water mud. The
hydration and dispersion of bentonite is inhibited above that chloride
level, therfore freshwater should be made available to prehydrate
bentonite. In Shaybah field, over saturated brine "Sabkha water" was
used as the make up water for a polymer system instead of bentonite
to drill the water supply wells.
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Dissolved chemicals can modify the properties of water.
• Salt: Sometimes the available supply of water for making a drilling
fluid is not fresh water. In offshore drilling, for example, you may have
to use seawater. At other times you may want to add soluble salts,
such as sodium chloride (NaCl), potassium chloride (KCl), or calcium
In addition to these chloride salts, drilling
chloride (CaCl2).
carbonates or sulfates (gypsum or anhydrite) can add soluble ions to
the water phase. In some cases, these soluble materials cause mud
instability and are considered as contaminants.
• Alkali: The pH of the mud systems is usually run in the alkaline
range by the addition of alkali materials. Lime [calcium hydroxide or
Ca(OH)2] and caustic soda [sodium hydroxide or NaOH] are the most
commonly used alkalis. Caustic potash [potassium hydroxide or KOH]
is used in KCl inhibitive muds. Lime is used in CaCl2 brine-based
fluids and in oil-based muds.
• Polymers: Several water-soluble polymers are used to change
the properties of water and suspended solids. They can be used to
derive the essential properties of viscosity, viscosity reduction, and
fluid loss control.
• Surfactants: Surfactants change the wettability of water and
solids through adsorption. They are used to prevent foaming or to
emulsify oil. Other surfactants will adsorb onto steel and act as
lubricants.
1.1.3
Oil
Oil is used as the continuous phase in invert emulsions or oil-based
drilling fluids. Considerations of safety, low viscosity, and availability
has made diesel oil the most common base oil. Where environmental
concerns are high, special oils such as the SAFRA OIL have been
prepared through the removal of aromatic fractions.
Other
environmentally acceptable oils are mineral oils and esters/ethers.
These oils are very expensive and require expensive modifications of
the drilling rigs, new handling and recovery procedures, and special
transportation and storage facilities.
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Oil soluble and oil dispersible components are essential chemicals
used to stabilize the water or brine-in-oil emulsions. The emulsified
water adds to the viscous properties of the mud and the fluid loss
control properties.
1.2
Common Additives
1.2.1
Weight Control Additives (High Density Solids)
The most common weight material for drilling fluids is barite (BaSO4).
It has a relatively high density, is not abrasive, and is available.
Ground marble fine (CaCO3,CaMgCO3) processed as weighting
material has an average particle size of 10 microns.
Ground Marble Physical & Chemical Constants
(CaCO3,CaMgCO3)
Hardness, Moh's Scale:
Specific Gravity, gm/cc:
Bulk density, lb/ft3 :
Total carbonates (Ca, Mg):
Impurities:
(A12O3, Fe2O3, SiO2, Mn)
3.0
2.7 - 2.78
168.3
98.0 % Minimum
2.0 % Maximum
Weighting materials characteristics, and maximum practical density
achievable by each for a drilling fluid. High concentrations of
weighting material in a mud system have a significant influence on the
properties of the muds, and is a major cost element.
Material
Specific
Gravity
Characteristics
Maximum Mud
Density lb/ft3
Barite
4.2 -4.3
Cheap, non-abrasive, available
156
Marble fine
2.7 - 2.8
Inexpensive, acid soluble
110
Hematite
5.0 - 5.05
Available, abrasive, fewer fine
particles in the mud
190
Illmenite
4.6 - 5.1
Less available
190
Galena
7.4 - 7.7
Expensive, not readily available
220
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Saudi Aramco’s Lab R&D Center routinely monitors barite quality.
X-ray fluorescence analysis:
Barite, barium sulfate(BaSO4)
90%wt., Minimum
Specific gravity:
4.20 gm/cc, Minimum
Water soluble alkaline earth metals:
Calcium
250 mg/kg, Maximum
3000 mg/l, Maximum
Soluble carbonates
Soluble sulfides
100 mg/l, Maximum
Clay contamination: CEC(MBT) 0.50 meq/100g, Maximum
Cement contamination: pH after aging
10, Maximum
Particle size:
Residue greater than 75 microns
Particles l e s s than 6 microns
Abrasion and performance index:
3%wt. Maximum
25%wt. Maximum
Equivalent to or less than the API test calibration barite
1.2.2
Clay
The primary viscosifier for water-based muds is sodium bentonite.
SaudiAramco's specifications for bentonite were developed for nontreated, good commercial quality. The specifications make certain that
high yielding sodium montmorillonite clay is provided. A derivative of
bentonite is used in oil-based muds for viscosity control. Bentonite
reacted with cationic surfactants so that it can disperse in oil
(becomes organophilic clay).
Saudi Aramco’s Lab R&D Center routinely monitors bentonite quality:
Yield, bbls/short ton
90
Moisture content, % by weight
13
Yield point / plastic viscosity ratio
1.5
Dispersed plastic viscosity, cp
10
Dispersed filtrate, API ml/30 min.
12.5
pH,
9
Methylen blue capacity, meq/100gm
65
Residue on 200 mesh (wet), % by weight 2.5
Residue on 100 mesh (dry), % by weight 2
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Minimum
Maximum
Maximum
Minimum
Maximum
Maximum
Minimum
Maximum
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Clay Dispersion and Aggregation
A unique feature of the clays is their sheet-like structure that
resembles a book. Dispersion describes a process in which the
number of particles is increased by breaking off sheets of clay from
the book.
High shear mixing, perhaps at high clay solids content, tears the
sheets apart. Chemical conditions that encourage hydration of the
sheets are fresh water, sodium-based systems, and high pH
conditions. Often, a combination of both mechanical and chemical
forces is used to disperse bentonite. Time and temperature are
additional factors.
Aggregation describes a process when the number of particles
decreases.
An example of this is face-to-face flocculation.
Aggregation is the result of chemical changes such as conversion of
sodium montmorillonite to calcium montmorillonite or the addition of
sodium chloride to a fresh-water dispersion of sodium montmorillonite.
Clay Flocculation and Deflocculation
The terms flocculation and deflocculation refer to the energy of
interaction of particles rather than the number.
Flocculation
describes the situation when the particles are attracted to each other.
Deflocculation describes the situation where the net forces are
repulsive.
The major attractive forces are short-range electrostatic forces called
Van der Waals forces. These short-range forces are important in
holding sheets of clay crystals together. The forces are weak and only
operate over short distances. However, they can be significant for
relatively large surfaces such as clay platelets. These forces are
independent of salt content and pH.
The attraction between clay platelets can also be increased by
polyvalent cations such as calcium or aluminum. The cations cannot
associate with more than one charge on a single sheet. If the ions
carry more than one charge, they will form a bridge between the
particles, increasing the level of structure. Edge-to-edge and edge-toface associations may be formed quickly. Face-to-face association
will be a more stable form of association but will take time and may
require higher levels of calcium.
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Long chain polymers may also form bridges between the clay
platelets. This increases the degree of interaction between the clay
platelets, resulting in higher viscosity.
Ca
Polymer
Flocculation of clays by
calcium (from the lime) and
long chain polymer
Clay particles
Repulsive Forces
Forces repelling two clay crystals apart are due to the fact that they
are both negatively charged, rather in the way the north poles of a
magnet repel each other. The repulsion force will be increased if the
negative character of the clays is increased. The force gets bigger as
the particles are brought closer together. The negative charge can be
increased by raising the pH or by adsorption of low molecular weight
polymers.
The charges on broken edges of clays are influenced by the pH. The
clays are more negative at higher pH values. Thus high pH conditions
will encourage dispersion of clays. Caustic addition to the make-up
water is essential to ensure the maximum yield of bentonite.
Alternatively, lower pH conditions create less dispersive or more
inhibitive conditions.
The negative charges of the particle and, hence, the repulsion can be
increased by the adsorption of negatively charged, low molecular
weight molecules or polymers. These negatively charged molecules
are termed “deflocculants” as they increase the repulsive forces
between the particles. The decrease in interparticle forces will also
decrease the viscosity so these molecules are also called thinners.
This repulsion energy, however, can be reduced through the addition
of salt. The charges are “shielded” by the salt, and the particles can
come closer together before they repel each other.
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Net Forces between Particles
The overall reaction will be the summation of the attractive and
repulsive forces. The situation is quite complicated because of the
large number of factors involved. They are summarized in the
following table.
Summary of Conditions That Lead to Flocculation or Deflocculation
Environment
Flocculated
Deflocculated
Salt Concentration
Over 2000 mg/l
Below 200 mg/l
Fast at 20,000 mg/l
pH
Below 6
Above 9
Cation
Calcium and Aluminum
Sodium
Polymer
High molecular weight
cationic, anionic, non-ionic
Low molecular weight,
anionic.
This close look at the forces that bring particles together or cause
them to repel each other gives an explanation to many important
features of bentonite-based muds.
¾ Sodium bentonite (as a mud additive or a drilled rock mineral)
will swell and disperse in fresh water with a “cloud” of closely
associated water around the clay sheets. The large surface
area and the large volume of tied-up water generate the
viscous properties.
¾ Addition of salt to sodium bentonite causes the clay to
flocculate and so prevents dispersion and development of
viscosity. Bentonite should be mixed in fresh water with up to
about 0.035% sodium chloride (200 mg/l chlorides). At higher
levels, the dispersion is hindered, and the viscosity is
decreased.
¾ Seawater with about 10 lb/bbl (3%) sodium chloride totally
prevents the hydration of bentonite.
This result
demonstrates the use of high salt levels as the basis of
the design of inhibitive drilling fluids.
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¾ Sodium bentonite muds are sensitive to contaminants, such as
cement and anhydrite (calcium sulfate), that dissolve in water
to release the calcium ion. The calcium ion exchanges with the
sodium ion and initially causes rapid flocculation and
thickening of the mud. Given time, the calcium exchange
continues, and the clay platelets rearrange to form face-to-face
aggregates. This arrangement reduces the surface area and
number of particles so the viscosity decreases.
¾ Calcium contaminated muds can be converted back to the
sodium form by treatment with sodium carbonate or
bicarbonate or converted to a calcium mud.
¾ Calcium muds provide a level of increased borehole
stability or inhibition through conversion to the low level
of swelling systems.
They are also resistant to
contaminants.
1.2.3
Polymers
Many of the “specialty” products used in formulating water-based
muds can be described as “water soluble polymers”, a special group
of chemicals that owe their properties to their relatively large size.
Through their association with water and with the small colloidal clay
particles, relatively small quantities of material can significantly alter
the physical properties of the mud. These include viscosity, fluid loss,
and inhibitive character.
The large size of the molecule makes the polymers difficult to define
with absolute precision, but enough is known to characterize them
and describe them in general terms. There is also a very close
relationship between the structure and performance of the polymer.
Sufficient detail of the structure can be given; however, to explain how
they perform and show the relationship between structure and their
influence on mud properties. This understanding will allow for a better
appreciation of their application and limitations.
General Structure
Polymers are made by chemically joining simple molecules
(monomers) to form a chain. The “join” is in the form of a chemical
bond. The chemical character of the monomer and the number of
units joined will also be important characteristics of the polymer.
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The polymers used in drilling muds come in two groups: natural and
synthetic. Natural polymers are derived from nature where the
monomer is a sugar-like molecule. These molecules tend to be large
and have a complicated structure and are generally described as
polysaccharides. The linkage is susceptible to both being broken
down at temperatures above 300°F and biological degradation.
In synthetic polymers, the monomer group is a small molecule based
on different vinyl monomers. The molecules are built up from a small
molecule to a larger one. A range of structures is possible through
the use of different monomers. The bond between the monomer units
is a carbon-carbon bond that is stable to higher temperatures than the
polysaccharide polymers. They are also resistant to biological
degradation.
Molecular Weight
Polymer molecules are quite large. This property makes them
special. Their size approaches the size of the clay sheets. The
molecular weight or size of the molecule is related to the number of
the monomer groups joined together. The number of units ranges
from about 25 to hundreds of thousands.
Molecular weight, obviously a very important feature of the polymer,
influence properties and the way the polymer reacts in the mud
system. For example, very high molecular weight molecules are
longer than the clay particles. They can bridge or bond more than
one particle to another one. This reaction increases the bonding
between the particles so it would be classified as flocculation. Shorter
molecules will not be able to bridge between the platelets. If the
molecules are negatively charged, then their adsorption on the clay
will make the clay more negative. Thus, the repulsion between the
molecules increases, or the system deflocculates.
Chemical Character
The chemical character of the polymer will be due to the chemical
character of the individual monomer groups on the chain. The groups
may have all the same character or more than one. Three categories
of groups may be in the chain.
• Non-ionized groups such as hydroxide (–OH) or amide
(–C=O•NH2)
• Negatively charged or anionic groups such as carboxylic acid
(–C=O•O-Na+)
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•
Positively charged groups such as quaternary nitrogen
(–N+(CH3)3Cl-)
For example; the structure of a synthetic polymer “polyacrylate”, has
only anionic or negatively charged groups, and the Partially
Hydrolyzed Polyacrylamide (PHPA), has both negative and non-ionic
groups.
Shape of polymers in Solution
The polymers are made soluble in water through association of water
with the polymer. The polymer has a structure or shape in solution.
The shape depends on the polymer and the degree of flexibility and
rotation of the bonds. Another factor that is important in charged
molecules is the interaction between the charged groups.
In fresh water, the groups repel each other. This causes the polymer
to be extended in a “rigid rod”-like structure. If salt is added, the
electrostatic repulsion is reduced, and the polymer starts to curl up on
itself. This action reduces the size of the molecule. A reduction of
viscosity is normally observed. Polyacrylate, has a flexible structure,
and will change with salt content.
The cellulose derivative CMC (carboxy methyl cellulose) is negatively
charged and will also curl up in salt. This obviously limits its
application. A similar derivative, with a higher level of negative
charges and sold as PAC (polyanionic cellulose), increases the
solubility in water and reduces the effect of salt on the viscosity.
One polymer, Xanthan gum (XC-Polymer) is stable to salt because
the polymer twists into a double helix shape. This gives the molecule
some rigidity, and the viscosity of the polymer is resistant to the
effects of salt.
Non-ionic polymers will not be subjected to this effect and will be used
in brine systems. As solutions of salt will be found in some drilling
situations, the response of the system to salt will be a factor to
consider
The initial slow response to a change in properties as the
concentration of the polymer is increased is often observed in drilling
mud formulation. Care must be taken not to overdose the polymer
when making additions if the initial change in properties is slow.
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The viscosity will also decrease rapidly if the polymer is removed from
solution, by adsorption onto solids, for example.
Similarly, if
mechanical degradation or microbial action decreases the molecular
weight, a relatively large decrease in viscosity will also occur.
Mixing different polymer types may increase polymer-polymer
interaction. The resulting viscosity may be greater than the sum of
the viscosities of the two systems. This “synergistic” effect is
observed for a number of polymer systems, notably guar gum and
xanthan gum.
Any factor that causes the polymer molecule to shrink or coil up also
reduces the viscosity of that solution. The shape of a polymer
molecule containing ionized groups (such as CMC and partially
hydrolyzed polyacrylate) changes in size from a rigid rod to a
collapsed coil in higher concentrations of salt. This reduction in size
also reduces the viscosity.
Not all polymers exhibit viscous properties that are salt sensitive.
Non-ionic polymers such as hydroxyethyl cellulose (HEC) or guar gum
do not exhibit these effects. Neither does xanthan gum, due to its
unique molecular structure.
Polymers may also react with solids, such as bentonite or fine drilled
solids, to increase the viscosity by increasing the clay-clay
interactions. High molecular weight polymers have the physical size
approaching that of the clay particles themselves. Therefore, they
can form a bridge between particles by adsorbing onto more than one
clay particle. Only low concentrations of polymer are required.
Polymers Used in Drilling Muds
Polymers are identified by such features as charge character,
molecular weight, and shape of the solution in water. How a polymer
is used is related to its properties.
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The following table summarizes the polymers used in formulating drilling fluids.
Organic Polymers Used in Water-based Drilling Muds
Polymer
Chemical Character
Functions
Carboxymethyl Cellulose
(CMC)
High Viscosity CMC
Cellulose derivative linear No gels or viscosity at low
polymer. Anionic COO-groups. shear rates
High molecular weight
Low Viscosity CMC
Different degrees of purity
Fluid loss control
Polyanionic Cellulose (PAC)
Cellulose derivative similar to
CMC but with more anionic
groups. Always sold in pure,
salt-free form
Better stability than CMC
towards calcium salt and
temperature. Viscosifier, and
fluid loss control agent
High Viscosity PAC
High Viscosity PAC
Hydroxy Ethyl Cellulose
(HEC)
Polysaccharide,
polymer.
Non-ionic
group, High MW
linear Viscosifier,
particularly
for
ether brines. No gels or viscosity at
low shear rates
Carboxy Methyl, Hydroxy
Ethyl, Cellulose (CMHEC)
Cellulose derivative with non- Fluid loss and viscosity,
ionic and anionic groups
particularly at high temperature
and high calcium
Guar Gum
Polysaccharide.
(natural plant gums)
Branched High MW
Non-Fermenting Potato
Starch
Polysaccharide,
Highly Fluid loss in salt solutions
branched. Normally non-ionic
or anionic
Xanthan Gum [XC-Polymer]
(fermentation products)
Branched
complex Viscosifier, particularly in salt
polysaccharide. High MW
water and brines and where
suspension properties are
required
Polyacrylate
Low molecular weight
Thinner, Deflocculant
(Polymer of acrylic acid)
High molecular weight
Flocculant , Bentonite extender
High MW Synthetic
Polymer
Co-polymer of acrylic acid and Flocculant & Shale stabilizer
acrylamide
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Viscosifier Cross linked
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2.0
WATER-BASED DRILLING FLUIDS
This section will describe the formulation, application, advantages, and
disadvantages of water-based drilling fluids in general terms and for specific muds.
2.1. Bentonite Mud
Drilling fluids used to spud and drill the upper hole sections are typically
formulated with fresh or brackish water. They often get many of their
properties from dispersed drilled solids and bentonite flocculated with lime.
These systems would not normally be weighted to above 68 lb/ft3. In
Shaybah field, up to 75 pcf is needed for controlling the UER high-pressure
water zone.
The flow properties are maintained with water and lime as a flocculant after
prehydrating and dispersing the bentonite in freshwater. The fluid loss is
controlled by the addition of bentonite and modified potato starch. A typical
spud mud formulation for surface hole is as follows:
A Typical Formulation of a Fresh-Water Bentonite Drilling Mud
Constituent
Fresh water
Amount
1 bbl
Soda ash (reduce total hardness to 200mg/l)
0.25 – 1.00 lb
Bentonite (allow hydration time)
15 - 30 lbs
Lime (for pH, and flocculation)
0.25 - 1 lb
Or Caustic soda (for pH, and dispersion)
1
Modified Potato Starch (for filtrate and filter cake control)
0.25 - 1 lb
2
HEC (for additional viscosity at low temperature polymer)
Barite or CaCO3 (for density)
1.
2.
2 - 4 lbs
1 - 2 lbs
As required
To reduce the filtration rate and wall cake thickness when needed for
temperatures below 220ºF.
To stabilize the viscosity, specially when the prehydrated bentonite
is added to brackish water, seawater, or saturated brines
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Within the limitations of the system, treatments are straightforward and may
be summarized as follows.
•
Solids: Excessive concentrations of solids can produce unacceptable
high densities, high viscosity and gel strengths. This can lead to an
excessive consumption of chemicals. The mechanical solids removal
equipment and dilution are used to minimize the undesired solids content
in the mud.
•
Viscosity: The plastic viscosity is decreased by water additions and
increased by bentonite and solids. The yield point and gel strengths are
decreased by the addition of water and / or deflocculant and increased by
bentonite or polymers.
•
Fluid Loss Control: Often properly hydrated and dispersed bentonite
alone will give a fluid loss rate in the region of 12 ml/30 min API. If lower
levels are required, use modified starch.
The following trends should be analyzed when running bentonite muds:
•
•
•
•
•
•
•
•
•
•
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Mud weight or solids tend to increase rapidly.
pH 9 -11 requires continual addition of lime or caustic soda.
Water loss may deteriorate due to drilled solids contamination.
Gel strengths becomes low and causes poor cuttings suspension.
Carrying capacity and lifting is not sufficient at YP less than 10 lb/100 ft2.
Alkalinity is maintained with lime to remove any CO2 contamination.
Excessive dilution increases consumption of chemicals, such as barites.
The uninhibited nature can promote the hydration, or swelling, of water
sensitive shales. This may cause heaving or sloughing conditions, balling
of the bit or the formation of “mud rings”. Dispersion of the clays can lead
to severe hole erosion, which will produce problems in directional drilling
and cementing of casing.
The uninhibited nature may disperse or mobilize clays in sandstone
reservoirs, impairing the production of oil or gas.
Drilling rates are slow due to high solids in hard rock formations.
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2.2
Lime Treated Muds
Calcium ions can inhibit hydratable formation clays in the Wasia section by
exchanging with the sodium ions in the formation clays. This produces a
hydrated but nonexpanding complex with a much reduced volume of
entrained water. The calcium ion competes very effectively for sodium. It
only has to be present in relatively low concentrations of 500 to 2000 mg/l
calcium ion. An advantage of this type of mud is the stability to calcium in the
form of anhydrite and cement.
The calcium is maintained in solution by either adding lime or gypsum. Since
these salts have only a limited solubility in water, they may be maintained in
excess to replace the calcium ion as it is used up in the exchange process.
Lime muds are available in three concentrations:
•
•
•
Low-lime, low-alkalinity muds are used for higher temperature
applications and high mud weight. (Filtrate alkalinity, 0.8 to 2.0 ml /
Excess lime, 0.2 to 1.0 lb/bbl)
Medium-lime, most commonly used. (F. alk., 2 to 5 ml / Ex. lime 2 to 4
lb/bbl)
High-lime, most inhibitive. (F. alk., 4 to 8 ml / Ex. lime, 4 to 10 lb/bbl)
Calcium Hydroxide is only partially soluble. The dissociation of lime
is decreased by the addition of sodium hydroxide, and the level of
calcium ions can be adjusted. The level of alkalinity is measured by
acid titration of the filtrate.
Potassium Lime Muds: Potassium lime muds use KCl and
potassium hydroxide instead of sodium hydroxide for pH. This
provides additional inhibition from the potassium ion. The mud is
referred to as the KLM system and should be formulated without
bentonite or clay dispersants. Caustic soda, soda ash, sodium
bicarbonate, and lignosulfonate should not be used in this system.
This system is used for drilling the water sensitive sections of the
Central Area and the pre-Khuff formations in the deep exploration
wells.
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Basic Formulation of a Potassium-Lime (KLM) Drilling Fluid
Freshwater
1 bbl
Defoamer (non-toxic)
0.01 gal
Xanthan gum (XC-Polymer)
0.5 – 1 lb
Modified Starch
2 – 4 lbs
Potassium Chloride (KCl)
12 – 15 lbs
Potassium Hydroxide (KOH)
0.5 – 1 lb
Lime Ca(OH)2
0.5 - 1 lb
CaCO3 “Fine” (for filter cake build up)
5 – 10 lbs
CaCO3 “Fine” (for density up to 100 pcf)
As required
The low-lime mud systems are less susceptible to high temperature
solidification because of its low clay content (4 – 8 lb/bbl) and low
alkalinity. If its alkalinity is kept low, the mud can tolerate high
temperatures and high calcium, which is usually encountered while
drilling the Jilh formation. Sodium sulfite is added to remove the
oxygen and minimize the polymers oxidation. When the static bottom
hole temperatuer reaches 280ºF, the starch is phased out and
polyanionic cellulose (Drispac or PAC) is used instead. However, the
mud usually require the addition of high temperature deflocculant
such as ThermaThin, and high temperature filtrate control polymer
such as ThermaCheck to control the fluid loss and cake thickness.
Surfactants, effective in high calcium mud, are also used for
stabilizing the drilled clay aggregates and prevent their dispersion in
the mud system.
The low-lime muds are the most practical and economical mud to
use when large sections of gypsum or massive anhydrite are to be
drilled, and formation salt water flow with acidic gases are
encountered. These areas generally require low weight mud systems
with no chemical treatment and low solids concentrations. High, flat
gel strengths may exist, but being fragile gels, they are generally not
too objectionable. If the gel strengths become excessive, regular
chemical treatment with deflocculant will restore it to normal.
The carbonate sections (limestone and dolomite) drilled in Saudi
Aramco’s fields have high carbon dioxide (CO2) and Hydrogen sulfide
(H2S). The lime treated mud proved to be the most effective and
economical system to use in this environment.
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2.4
Advantages
¾ Easy to prepare and maintain.
¾ Low cost inhibitive system for reactive, water-sensitive shale formations.
¾ Calcium inhibitive system for high temperatures.
¾ Tolerant to contamination from salt, anhydrite, cement, and carbon
dioxide.
¾ Stable, low viscosity at high mud weights and high solid levels.
¾ High resistivity for good log results.
¾ Good cement bonding logs.
3.0
OIL-BASED DRILLING FLUID
Oil-based drilling fluids best meet the design requirements of a mud, mainly
because they will not react with rock. The hole will only be subjected to the
mechanical stresses for stability. Also, the cuttings are stable when they come to
the surface, so they can be easily and efficiently removed at the surface. The mud
also forms an impermeable filter cake and provides good lubricity. The inertness
makes the mud stable to contaminants and makes it easy to run. The formulation
and operation of this “ideal” mud are unique. In some muds, when oil is the main
component with less than 5% water, the mud would be called an oil-based mud.
The most common type of mud used today, is formulated with at least 5% water as
an emulsified phase and is called an invert emulsion mud. Water not only adds to
the viscosity and fluid loss control functions but also reduces the fire hazard of the
mud.
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Components and Properties
An invert emulsion mud consists of a mixture of oil and water. Oil and water are
incompatible fluids but can be mechanically mixed under high shear to form
emulsions where one phase exists as small droplets (dispersed phase) in the other
phase (continuous phase). Invert emulsions consist of water droplets in a
continuous oil phase and normally contain higher volumes of oil.
Water
Oil
Water
Water
Water
Mechanically Formed Water-in-Oil Emulsion
Such emulsions are unstable because the droplets will collide to form a larger
droplet. The instability is due to the much stronger polar interaction between water
molecules than between water molecules and oil, as illustrated above. The stability
of the emulsion can be drastically improved by the addition of chemicals called
surfactants. They have the special ability to concentrate between the oil and water
phases to form a rigid skin, and so stabilize the emulsion.
In practice, oil-based muds from the field are more stable than ones prepared in
the laboratory. Here the solids in the mud also form at the water-oil interface and
further add to the stability.
Oil Phase
Oil is the largest single component of the system. The chemical and physical
properties of the oil influence many properties of the system, including:
•
•
•
•
•
Solubility of the surfactants
Viscosity
Performance of the organophilic-clays
Flash point
Toxicity of the mud
All the solids of the mud must remain strongly oil wet and contained in the oil.
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A widely used oil is diesel oil (number 2 straight run). Diesel oil has a flash point of
165°F or above and an aniline number between 140°F to170 F. It contains a high
level of aromatic hydrocarbons, which give good solubility for the surfactants and
allow the organic clay to disperse easily. Diesel oil is widely distributed and readily
available.
The high content of aromatic hydrocarbons (20 - 40%) gives diesel oil an
unpleasant odor and makes it toxic to both the environment and the operators.
The so-called low toxicity mineral oils (LTMOs) are more highly refined oils that
have had the aromatic fraction removed. There are over 50 different grades of
LTMOs with slightly different characteristics. The performance of different oil-mud
formulations (surfactants, fluid loss additives, and organo-clay) must be evaluated
with any proposed oil.
In order to comply with the environmental protection regulations which specifically
address the disposal of drilling fluids and their associated cuttings in the Arabian
Gulf, a locally produced low aromatic oil was chosen and used for formulating the
oil-based mud.
Laboratory tests indicated that it had an LC50 value of 180,726 ppm which was
substantially less toxic than a white mineral oil used worldwide as the diesel oil
substitute. All the oil mud additives were found to be compatible with the low
aromatic oil and the desired mud characteristics were easily achieved
The US EPA have regulated the discharge of drilling fluids from offshore drilling
rigs by setting a numerical limit of three percent (30,000 ppm) on the toxicity of the
fluid to be discharged.
Toxicant Classification
Practically non-toxic
Toxic
Very toxic
LC50 Value, ppm
> 100,000
< 30,000
< 10,000
Regional Organization for the protection of the Marine Environment
( ROPME )
February 1990 protocol States :
“Drilling fluids discharged from offshore operations must not contain
persistent systemic toxins ”
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A low toxicity oil (SAFRA OIL) is used for offshore operations. Laboratory analysis
indicated that the Safra oil is almost identical to mineral oil.
Mineral Oil Safra Oil
Specific Gravity
0.7967
0.7896
o
165
179
Flash point, F
Aromatics
<1
<1
Paraffines
> 99
> 99
Olefeins
Nil
Nil
Sulfur
< Det.limit < Det.limit
Kin-vis at
70 oF,Cst
2.16
2.21
o
1.45
1.476
120 F,Cst
212 oF,Cst
0.79
0.800
173
168
Aniline point,oF
Diesel Oil
0.8398
159
30 - 50
1 wt%
4.84
2.56
156
Saudi Aramco’s Industrial Hygiene concluded that the health hazard rating of the
Safra oil was H-1 (slight health hazard). The recommended exposure limit for this
oil on a time weighted average (TWA), according to Fisher Scientific material
safety data sheet (MSDS), is 100 mg/m3. At this exposure level, the low-toxicity
Safra oil causes irritation and only minor, reversible injury. Diesel Oil No.2 has a
TWA of 5 mg/m3 and is classified H-2, a moderate health hazard, i.e. one which
can cause temporary incapacitation or injury on intense or continued exposure.
Property
TWA, mg/m3
Health hazard rating
Fire hazard rating
Reactivity rating
Flash point,°F
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Diesel No.2
5
2
2
1
165
Low-Toxicity Safra oil
100
1
2
1
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Water Phase
The shales being drilled can develop very strong adsorption forces that can draw
the water out of the emulsion. Water has a very low level of solubility in oil and,
thus, can escape from the droplet into the oil. If the adsorption forces for the water
are greater than the forces keeping the water in the droplet, then the water will wet
the shale. These forces are countered by using brine as the water phase. The
water content of invert emulsion muds is normally less than that of the oil content.
The solids in the mud are normally in the oil phase and the surfaces are oil wetted
rather than water wetted.
Emulsifiers
Emulsifiers are surface-active molecules (surfactants) that orient themselves
between interfaces of incompatible liquids or surfaces and lower the surface or
inter-facial energy or tension. A common example is soap.
The chemical structure of these surfactants is characterized by a special molecule
that has both a hydrophilic or water loving “head”, which is polar and ionized, and
an organophilic or oil loving “tail”. The properties of surfactants are determined by
the chemical nature of these two groups and the relative ability of these two groups
to either pull the molecule into water so that it is water soluble, or to pull the
molecule into oil so that it is oil soluble. The surfactants used to make oil muds are
oil soluble.
Surfactants concentrate at interfaces between incompatible surfaces and lower
surface energy or tension. The oil soluble invert mud surfactants position itself at
the interface forming a skin around the emulsified dispersed phase. The rigid skin
prevents droplets from coalescing and breaking when colliding.
Special
surfactants (oil wetting agents) are also added to react with the surfaces of the
minerals barite and clay to make them oil wet.
3.1
Balanced Activity
Balanced activity occurs when the formation’s thirst for water is equal to the
oil-based mud’s thirst for water.
Shale Activity
The forces for the adsorption of water are complex and very powerful. The
important contributing factors, identified by Mondshine and Chenevert, were:
•
•
•
Mineral composition of the shale
Salinity of the pore fluid
Inter-granular or confining stress of the shale
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The concept of shale activity can be explained by imagining a situation where
shale could be sampled at depth and the confining stress can be kept on the
sample. The sample is then brought up to the surface and placed in a closed
container. As the stress is removed, shale expands, and the water in the
shale will eventually reach equilibrium. The greater the adsorption forces, the
lower the concentration of water vapor in equilibrium. This water vapor
concentration is expressed as a percentage of the saturated water vapor of
pure water and can be measured by an instrument called a hygrometer. The
measured value for the shale is called the “activity”.
Formation clays such as montmorillonite and illite have a very strong
adsorption of water. High salinity pore water creates osmotic adsorption.
The inter-granular stress relates to the work that has been done in expelling
the water from the clay surfaces. The activity of the shale can be calculated
from knowledge of the inter-granular stress and pore solution salinity. It is
typically 0.75 to 0.85 for tertiary shales to 0.60 for shales at greater depth.
Activity of Brine
When salt is added to water, it lowers the number of water molecules in the
vapor phase due to close association with the ions, particularly the cation.
Thus the “activity” of the water can be reduced from 1.0 to 0.75 by saturation
with sodium chloride and to 0.34 by saturation with calcium chloride. In
practice, the use of calcium chloride brines (350,000 mg/l) is preferred.
These brines allow adjustment of activity over a wider range, and the calcium
ion is compatible with the salts of the surfactants.
Factors Determining Oil/Water Ratio
The minimum quantity of oil in the mud will depend on the mud density. The
oil content should increase as the mud density increases to provide room for
the solids. The normal ranges of oil to water ratios for different mud weights
(solids contents) are as follows:
Relationship Between Mud Weight and Oil-water Ratio
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Mud Weight PCF
Mud Weight SG
Oil/WaterRatio
62-75
1.00-1.20
50/50
75-82
1.20-1.32
65/35
82-95
1.32-1.50
70/30
95-105
1.50-1.68
75/25
112-120
1.80-1.92
80/20
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Oil Determination in Mud
Since low toxicity oil is expensive, accurate measurement of the ratio of oil to
water in the mud is very important. Changes in the ratio will give important
indications of changes in the mud properties, for example, an invasion of
formation water due to an imbalance in the activity of the brine phase or a
brine flow. The mud is retorted to distill over the water and oil, leaving the
solids and salts. A large 50-ml still should be used.
Viscosity Control
Viscosity control in oil-based muds is potentially more difficult than in waterbased muds because the strong polar interactions and ionic bonds are
eliminated in the continuous oil phase. The bonds between components in oil
are very weak hydrogen bonds, which are very easily broken with thermal
energy. Therefore, viscosity tends to decay rapidly with elevation of
temperature.
To resolve this problem, bentonite treated with organic cationic surfactants is
used to displace the inorganic ions (calcium and sodium) and make the clay
wettable by oil rather than water. This allows the organo-clays to disperse in
the oil.
Water plays an important role in fully developing viscous properties. Water
wets the edges of the clay platelets so the clays can associate through polar
edge-to-edge bonds.
The viscosity in field muds is controlled through the use of organo-clays to
increase the low shear viscosity (yield point and gels). The grade of organoclay should be tested further with the type of base oil to be used. Adding a
very small stream of water when the organo-clay is mixed with the mud is
sometimes advantageous. The plastic viscosity will increase as the weight of
the mud and the water content increases. Oil soluble polymers have been
recently introduced to control viscosity.
These polymers may have
application in muds with high oil content or in high temperature conditions.
The influence of temperature on the viscosity of oil-based muds is much
greater than with water-based muds. The viscosity/temperature profile has a
much greater gradient due to the weak nature of the bonds in oil-mud
systems. Care must be taken to measure the rheological properties at a
defined temperature that is close to the downhole parameters.
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The mud is subjected to significant pressures downhole. These pressures
compress the mud, forcing the components closer together and increasing
the viscosity. This effect tends to compensate for the loss of viscosity due to
the higher temperatures downhole. In critical wells, the pressure/temperature
profiles of viscosity should be determined on a high temperature/high
pressure viscometer.
Fluid Loss Control
Fluid loss control is a measure of the ability of the mud to lay down an
impermeable filter cake that can retain the fluid fraction in the wellbore and
minimize the buildup of a thick filter cake.
Colloidal Size
Emulsified Water
Droplets
Oil-based Mud
Oil Wet Solids
Build Mud Cake
All Oil
Filtrate
Wall cake build up
Invert emulsion muds can either be formulated so that this property is well
developed or poorly developed. Invert mud with well-developed fluid loss
control has an important advantage in preventing differential sticking when
drilling overbalanced into production sands. In cases where a low fluid loss
would drastically lower the penetration rate, the mud can be formulated so
that the fluid loss is as high as that of a water-based mud.
The many sub-micron sized water droplets, surrounded with surfactants, act
as colloidal particles to seal the filter cake. The tiny droplets are repelled
from the oil wetted filter cake built up from the oil wet solids, such as barite,
organo-clay, fine drilled solids, and oil wet solids specifically added to
improve the oil wet character of the filter cake. Thus, the fluid loss is low.
The filtrate will only consist of oil if the emulsion system is well developed
with the correct concentration of surfactants.
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The concentration of the surfactants in the oil filtrate is likely to be much lower
than in the whole mud because they are closely associated with the water
phase and the solids. This ensures that the invading filtrate will not alter the
wettability of the formation and so cause formation damage. The repulsion of
the oil from a water wet capillary will also contribute to a lowering of the fluid
loss.
The fluid loss test of an oil-based mud is one of the most important
indicators of the stability of the emulsion. The test has to be carried out
at high temperature and pressure in order to obtain a measurable level
of filtrate. The temperature is normally about 20 F higher than the
bottomhole temperature and at 500 psi pressure.
This description of the fluid loss mechanism shows that emulsifiers play an
important part in repelling the water from the filter cake. The presence of
water in the filtrate is a clear indication that the level of emulsifiers is too low.
Addition of emulsifiers should be made in the same proportion as
recommended in the initial formulation. This will be particularly important for
muds that have a relatively high proportion of water.
The permeability of the filter cake may be further reduced by the addition of
colloidal oil wettable solids such as amine treated lignite. The level of
addition of these “dark brown powder” will be in the region of 3 to 8 ppb. Oilbased systems used for drilling through oil reservoir rocks should not contain
any asphaltic material.
Asphaltic additives will contribute both to the toxicity of the oil mud and
to the residual formation damage.
A mud will be formulated for high fluid loss when field experience has
indicated that the low fluid loss severely reduces the drilling rate. This may
be observed in harder, older formations where the inter-granular cementation
is very well developed. The level of emulsifiers will be restricted to the
minimum required for stability, and the oil wettable colloidal solids would not
be added. The API fluid loss of these formulations will be in the region of 5
to 20 ml.
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Typical Formulation of an Invert Oil Mud
Components
Quantity
Base Oil,
bbl:
0.573
Primary Emulsifier,
gal:
1
Lime,
lbs:
4
Filtrate control agent “amin lignite” , lbs:
Water ,
6
bbl:
Viscosifier “Organophilic clay” ,
0.253
lbs:
4
Secondary Emulsifier,
gal
0.2
Barite,
lbs:
174
CaCl2 ,
lbs:
32.3
Property
Value
Electrical Stability (volts)
1000-1200
600 Fann Reading
75
300 Fann Reading
48
Plastic Viscosity (cps)
27
Yield Point (lbs/100 ft2)
21
Gels 10 sec/10 min (lbs/100 ft2)
HTHP Fluid Loss 200º F/500 psi
3.2
8/16
(ml all oil)
1.8
Rig Site Procedures
The following rig site procedures for oil-based drilling fluids application:
•
•
•
•
•
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Mixing
Mud testing
Engineering of properties
Maintenance
Rig preparation
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Mixing
Ideally, the volume of oil-based mud will be built up completely in a separate
tank rather than be built “on the fly”. This ensures that the expensive
components are in the correct proportions and that the salinity and oil-towater ratio are accurately prepared. New volumes will be needed for
additions to the active mud system to maintain volume due to the hole
volume generated and to compensate for the mud lost with the cuttings.
The ideal sequence of addition of the components is as follows:
1.
2.
3.
4.
5.
6.
7.
8.
Transfer all the calculated oil volume in the mixing tank
Add the primary emulsifier
Mix Lime [not in the same hopper where the emulsifier is added]
Disperse the filtrate control agent “amin treated lignite”
Mix for 30 minutes
Transfer all the calculated water volume with the CaCl2
(CaCl2 brine prepared in separate tank )
Disperse the viscosifier “organophilic clay”
Add the Secondary emulsifier
Mix for 30 minutes
Mix the weighting material - barite or calcium carbonate fine
This order of addition ensures that the clay is fully dispersed and the polar
activator (water) is added before the secondary emulsifier. The formulation is
always aided by heat and energetic mixing so maximum shear should be
applied. Care should be taken to measure the components accurately to
ensure that the desired properties are obtained.
Mud Testing
The viscosity related characteristics are measured using a Fann-35
viscometer. Oil-mud viscosity is very sensitive to temperature, so the test
temperature must be defined closely through the use of a thermostatically
controlled mud cup. The temperature used should be stated in the test
results. The temperature is normally 120 F but should be higher if flowline
temperatures or bottomhole temperatures are higher. The mud should not be
tested at temperatures higher than 190°F.
The fluid loss test is normally measured at elevated temperature and
pressure. The bottomhole temperature plus 20°F is normally selected to
make the measurements with 200 F as a practical minimum. Normally the
test is carried out with a pressure of 600 psi on the top and 100 psi on the
bottom to prevent the evaporation of any water that may be in the filtrate.
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If the mud is specially formulated to have a high fluid loss, then the API fluid
loss test is conducted at room temperature at 100 psi.
The ratio of oil to water is determined by analysis of the retort reading. Care
has to be taken to ensure that this is accurately carried out. This value is
used with the titration results of the aqueous phase to calculate the salinity
of the brine phase. The density of the solids in the mud can also be
calculated from this measurement.
The stability of the emulsion is measured by applying an alternating voltage
between two electrodes and measuring the voltage when 2 milliamps of
current flows through the electrode. The electric current polarizes and
coalesces the droplets so that they conduct electricity. This voltage is
expressed as “volts for electrical breakdown”.
There are two instruments designed to take the electrical stability
measurement. The older version had a manual adjustment of the
increase in voltage and other features that made reproducibility of the
readings difficult. A more advanced instrument increases the voltage
automatically and offers improved reproducibility although the readings
are lower.
In general, electrical stability increases as the emulsifier concentration
increases. However, other factors such as oil-water ratio, viscosity, and salt
content also influence the reading. It is best taken as an indication of trends.
Values over 400 volts are acceptable, with readings typically in the range of
400 to 1200 volts.
Engineering of Properties
Typically the rheological properties of oil-based mud have higher plastic
viscosities than the yield point. This is due to the higher level of solids and
the low energy of interaction in the nonpolar oil environment. The yield points
can be increased by the addition of organo-clay and oil soluble polymers.
Increased water content will have the same effect if the ratio of water to oil
does not exceed 50/50. The viscosity is very sensitive to temperature.
Properties must be measured at a fixed temperature (120 °F) or higher, as
appropriate. Viscosity is reduced by the addition of oil and strong oil-wetting
surfactants (oil-wetting agents). The fluid loss should be determined at
elevated temperature and pressure with typical values of 2 to 5 ml for a
normally formulated mud.
The relaxed fluid loss muds will have a measurable fluid loss under API
conditions of 5 to 15 ml, which should be all oil.
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Water in the filtrate and increased surface mud volumes are both important
indications that the emulsifier strength is low. The water content and solids
content should be checked to determine whether there was an influx of brine
or solids.
The initial treatment would be to increase the emulsifier
concentration.
The ratio of water to oil and the salinity of the water phase should be
constant. If the water content is decreasing and the cuttings are water wet
and sticky, then calcium chloride should be added. If the activity is too low,
then the mud will extract water from the shale to establish an equilibrium with
the shales.
The alkalinity of the mud is maintained by the addition of an excess of lime. If
the alkalinity falls, there may be an invasion of hydrogen sulfide (H2S),
carbon dioxide (CO2), or a magnesium-rich brine. Lime must be added to
restore the alkalinity. Checks should be made to determine the level of water
wetting.
Maintenance
Oil-based mud maintenance is much easier than with water-based muds.
This is mainly because the drilled solids are building up slower in the mud.
The properties, therefore, stay much more stable. Maintenance essentially
requires new volumes to replace the volume of the new hole and the mud
removed with the drilled solids.
The fluid-loss test is the most indicative test of changes in emulsifier
level. A change in the fluid loss and, particularly, water in the filtrate, is
a good indication that the emulsifier level is becoming depleted. The
treatment should be with the range of emulsifiers normally used.
The total water content of the mud should be carefully monitored, and
additions of new volume should be made as accurately as possible, to ensure
that the water activity of the brine is correct.
Oil-based muds can apparently run with very little problems and tend to
be neglected. However, if the neglect leads to a water wet situation, the
consequences can be DISASTROUS. Barite will settle, mud density will
be reduced, and the hydrostatic head will be lost. Well control problem
will develop or a BLOWOUT.
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Rig Preparation
A number of operational aspects of oil-based muds are quite different from
those of water-based muds. The following issues should be of major
concern:
¾ The rubber components in the circulating system (Hydril rubber hoses,
pump seals, impellers, etc.) need to be changed to a grade that is
stable in the oil used for preparing the mud. Check and verify the rubber
quality through the Lab R&D Center.
¾ Water additions to the mud need to be controlled strictly. The mud tanks
may need to be covered to minimize rain water contamination. The tanks
may need to be covered and additional ventilation added to minimize
vapor and misting problems. Oil wastes and run-off from the drill floor
and cellars need to be collected and contained.
¾ Oil-based mud viscosity changes with temperature considerably more
than that of water-based mud. Thus, when cold, it is very viscous and
may be difficult to pump. Care should be taken not to lose the mud over
the shaker screen.
3.3
Systems Problems/Solutions
Oil-based mud system problems and recommended solutions:
•
•
•
Unstable Emulsions
Water Wet Solids
Cement Displacement
Unstable Emulsions
The emulsion can become unstable if the emulsifiers concentration used is
not effective or too low for the level of solids and water or brine in the system.
This may be the result of too little addition or due to water influx and solids
build up. Usually this problem occurs when weighting the mud up fast. A
change in the water content from the retort test data and a decrease in the
electrical stability (voltage readings) are indicators that the emulsifier level is
too low. However, the most sensitive indicator is the presence of increased
levels of water or emulsion in the filtrate.
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Water Wet Solids
All the solids in the mud are in the oil phase. The solids and minerals
surfaces are treated with surfactants so that they can remain strongly oil wet.
This keeps viscosity effects of the solids low so that high levels of weighting
materials and drilled solids can be easily incorporated into the mud. The
most serious problem that can befall an invert emulsion is for the emulsion
mud to “flip”. This happens when a mud converts from an oil-continuous fluid
to a water-continuous mud. The solids become water wet quickly and adhere
to each other. The solids may clump together and be removed by the shaker
screen. Barite is a particular problem. Because barite is present in large
quantities, it will contribute significantly to the requirement for oil-wetting
surfactants.
The mud will most often “flip” when there is a rapid change in composition.
For example, flipping can occur during rapid weighting-up of the mud without
the addition of an oil-wetting agent or during rapid drilling of a wet shale
sequence.
The condition is treated by the addition of oil-wetting agents, secondary
emulsifier, and additional oil. The situation is best avoided by paying
attention to the mud condition and adding surfactants to maintain the
emulsifier level recommended in the initial formulation. Sometimes it is
more economical to dispose of the mud than treat it.
Cement Displacement
Oil-based muds usually drill a gauge hole that can significantly improve the
efficiency of the displacement of mud by the cement. However, for a good
cement bond to take place, the cement crystals must grow into the formation
and steel surface. This process will not be favored in oil-wet pores, so the oil
mud must be removed and the rock and the metal surfaces should be
cleaned with a water-wetting surfactant prior to the cement.
3.4
Advantages/Disadvantages of Using Oil-Based Mud
Oil muds, like other drilling fluids, must be properly applied to derive all the
benefits associated with them. There are obvious advantages in using these
systems, or they would have ceased to exist in the industry. Likewise, there
are disadvantages that limit oil mud use to those applications where it is best
suited.
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Advantages
Lubricity; Torque and drag problems due to deviated wellbore, crooked hole,
and side-tracks can be reduced considerably by the use of oil muds. Since
oil is the external phase, the bore hole and tubulars are exposed to a much
better lubricating fluid than any water mud can provide.
Temperature Stability; Oil muds have application on wells with high
bottomhole temperatures. Oil muds have remained stable in wells with a
logged bottomhole temperature (BHT) of 585 F.
Shale Stabilization; A properly conditioned oil mud should have no effect on
a shale formation. Therefore, a gauge hole can be drilled through watersensitive shales.
Resistance to Chemical Contamination; Carbonate, evaporite, and salt
formations do not adversely effect the properties of an oil mud. CO2 and
H2S can be easily treated out with lime.
Improved Screening with Shale Shakers; Since drill cuttings are inert to oil
muds, they remain more competent. Therefore, the shakers remove a higher
percentage of solids than is possible with water-based muds.
Solids Tolerance; Because drill solids are inert in an oil environment, oil
muds have a much higher solids tolerance.
This reduces dilution
requirements, thereby reducing costs.
Less Damaging to Sandstone Oil Production Zones; Oil muds normally
have a low fluid loss when the filtrate is oil. The filtrate invades only a short
distance into the production zone and causes little or no damage in the
formation clays and permeability.
Note, however, that Oil muds can cause sever damage to carbonate gas
production zones
Less Chance of Differential Sticking; Due to the thin, slick filter cake
formed by an oil mud, the chance of differential sticking is minimal. Note,
however, that differential sticking is still possible if drilling highly
overbalanced, especially with a “relaxed filtrate” system.
Drilling Underbalanced; In some instances where rock matrix strength is
sufficient, drilling underbalanced to increase R.O.P. is possible when using oil
mud. The advantage of the oil mud is good wellbore stability through sand
shale sections.
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Re-use;
Due to the excellent stability and solids tolerance of a wellconditioned oil mud, it can sometimes be used for more than one well.
Although the initial make-up cost is normally high, the re-use of oil mud can
actually be cheaper than water-based muds in some cases.
Reduced Cement Costs; Gauge hole drilling can substantially reduce
cement volume needed and costs. This can benefit in two ways; far less
excess cement is required and a more constant flow regime can be achieved,
giving a better primary cement job. However, cementing with oil mud in the
hole can be tricky due to the vast difference in the continuous phase of the
mud and cement.
“Relaxed Filtrate” Oil Muds; Invert oil muds are now being run with high
fluid loss and low electrical stability values. This type of oil mud is showing
very high rates of penetration and has broadened the use of oil muds
considerably.
Low Toxicity Oil Muds; Replacing diesel in both the mud and chemicals
with a mineral oil has allowed the usage of oil muds in some environmentally
sensitive areas. These muds also have the flexibility of being run either
conventionally or “relaxed filtrate”.
Flexibility; With the advent of both “relaxed filtrate” oil muds and low toxicity
oil muds, application has increased dramatically. Any size hole, any
environment, and any lithology can be drilled with specially tailored oil mud.
Reduction of Metal Stress Fatigue; Stress fatigue of tubulars is reduced
considerably when using oil muds.
Reduced Corrosion; Oil muds are not corrosive since oil, instead of water, is
in contact with all metal surfaces. However, care must be taken to ensure
that the CaCl2 from the internal phase does not come into contact with these
same surfaces.
Performance with PDC Bits; Higher rates of penetration are achieved
drilling homogeneous shale formations
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Elimination of Gas Hydrate Potential; Gas hydrates, ice-like structures,
form under pressure above the freezing point of water in mixtures of gas and
water muds. Drilling in deep water increases the potential risk of hydrate
formation due to the cooling of the mud around the BOPs by the sea water.
The most suppression of the temperature of hydrate formation is achieved by
additions of sodium chloride. Twenty-seven-degree suppression is achieved
at saturation. Beyond this, oil-based mud is the only method of eliminating
the potential of hydrate formation.
Disadvantages
High Initial Cost per Barrel; The oil fraction alone of a barrel of oil mud may
cost US $50 to $80 per barrel. This is a considerably higher cost than most
water-based muds at any weight. Therefore, initial make-up costs will be
high. Low toxicity oil-based mud may cost US $ 120 to $ 370 per barrel.
Slow Rates of Penetration; Oil muds historically have produced lower
R.O.P.s when compared directly to water muds and rock bits. Two theories
have been proposed to explain this:
•
Oil muds have a higher viscosity at the bit. A greater pressure drop
through the bit results in increasing the loss of hydraulic horsepower.
•
The chip hold-down effect. Normal oil muds have no spurt loss.
Therefore, the chips created by the rock bit are held in place by
differential pressure.
If the oil mud has a higher overall viscosity than water-based mud, which is
the normal case, the ECD will be higher, therefore, reducing the R.O.P.
(Note that “relaxed” oil muds have reversed this condition in some instances.)
Mechanical Emulsification; To achieve the emulsion quality needed,
mechanical shearing is required to supplement chemical emulsifiers. This
can be accomplished by either pumping the mud at a high rate through the bit
or by using a shearing device.
Pollution Control Required; Because of ever-tightening environmental
restrictions, rig modifications may be necessary to contain spills, clean oilmud cuttings, and handle whole mud without dumping. Burning of whole mud
may also be required.
Fire Hazard; Since both the base oil and oil mud made with it can burn, extra
precautions are required for fire prevention. Additional gas, smoke, fire
detectors, and protection devices may be necessary.
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Disposal Problems; As mentioned previously, oil mud cuttings may have to
be cleaned before dumping. Some environments require that cuttings be
sent to proper disposal areas. Also, whole mud cannot be dumped.
Therefore, if solids need to be reduced, dilution with new mud is the only
answer, which will increase the active mud volume. Oil mud volumes only
increase. At some point in time, the oil mud must be disposed of.
Centrifugation for Solids Control; Less Effective Oil muds have inherently
higher viscosities than water-based muds. Also, the oil is compressible,
which again increases the viscosity under pressure. Hydrocyclones and
centrifuges have a higher cut point with oil muds.
Gas Stripping; Intrusion of gas into an oil mud can cause the weight material
to settle. This is a particular problem in using oil muds as packer fluids on gas
wells.
Magnitude of Mud Problems; Mud problems with oil muds can be
disastrous. Emulsion breakdown and water wetting are extremely costly and
time consuming.
Special Logging Tools; Required Electric logs do not work in an oil mud
environment. In some instances, this can preclude the use of oil mud on an
exploration well.
Lost Circulation; Lost circulation with oil muds is very expensive. Also, the
problem may not be curable. Therefore, it may not be practical to consider oil
muds in possible lost-circulation zones.
Effect on Rubber; Oil muds can cause either shrinkage or swelling of normal
rubber parts. Therefore, it may be necessary to change out BOP parts, the
Hydril, etc., to either neoprene or Buna N, depending on the base oil.
Rig Cleanliness; Extra effort is required to keep a rig clean when oil muds
are used. Measures such as special dressing areas and steam cleaners on
the rig floor may be required
Hole Cleaning; Hole cleaning is more difficult with oil muds. Some reasons
for this include:
•
•
•
Cuttings do not disperse into the mud as they do in water mud.
Oil muds are more Newtonian and therefore have minimal carrying
capacity.
Oil muds are less thixotropic than water muds.
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Kick Detection; H2S, CO2, and methane (CH4) are all soluble in oil mud. If gas
enters the wellbore, it can go into solution under pressure. As the gas moves
up the hole, it reaches its bubble point and will come out of solution. If this
occurs at a shallow depth, it may be too late to prevent a BLOWOUT.
Planning; In most cases, extensive planning and training are required for
successful oil mud use. Rig crews should be briefed, and reporting
procedures and contingency plans must be decided upon beforehand.
Planning takes time, but it is essential.
3.5
Summary
¾ Oil-based muds uniquely cancel hydration reactions with the formation,
especially water sensitive shales. Hydration of shales can be prevented
by addition of CaCl2 to the emulsified water phase.
¾ Polar or ionic reactions are eliminated so the mud is more tolerant to
contaminants that can be detrimental to water-based muds such as
anhydrite, cement, hydrogen sulfide, carbon dioxide, and drilled solids.
¾ The mud is stable at high temperatures.
¾ The surfactant/water droplets act as “ball bearings” to lower the friction
between the drill pipe and the wall of the hole.
¾ Fluid loss characteristics are well developed so differential sticking is
minimized.
¾ The mud is expensive and different from water-based muds, so rig
equipment and mud-handling practices must be modified to take this into
account.
¾ The mud must be carefully maintained to ensure that the continuous
phase is maintained as oil.
¾ Due to the high unit cost, the mud should not be used where lost
circulation is an anticipated serious problem.
¾ The means of disposal of oil contaminated cuttings and mud must be
considered and appropriate action taken.
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PLANNING A DRILLING FLUID PROGRAM
1.0
INTRODUCTION
2.0
DRILLING FLUID PROGRAM PLANNING
2.1 Information for Offset Wells
2.1.1 Geological Characteristics of the Formation
2.1.2 Previous Well Reports
2.2 Casing Programs
2.2.1 Pore Pressure and Fracture Gradient
2.2.2 Casing Depths
2.3 Drilling Fluid Program Preparation
2.3.1 Mud Weight for Each Casing Interval
2.3.2 Selection of Fluid Types
2.3.3 Specification of Properties
2.4 Technical and Cost Objectives
2.5 Mud Formulation
2.6 Mud Properties
3.0
APPLYING A DRILLING FLUIDS PROGRAM
3.1 Implementation
3.2 Trend Analysis
4.0
DRILLING FLUID MANAGEMENT
5.0
DUTIES AND RESPONSIBILITIES
5.1 The Foreman’s Responsibilities
5.2 The Contractor Mud Engineer’s Responsibilities
5.3 The Saudi Aramco Drilling Engineer’s Responsibilities
6.0
BASIC FIELD TESTING EQUIPMENT
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PLANNING A DRILLING FLUID PROGRAM
1.0
INTRODUCTION
A good drilling program ensures that the essential decisions affecting its success
are correctly made. The drilling fluid is a critical component during the drilling and
completion of a well. At the planning stage, three factors greatly influence the
success or failure of a well. They are:
•
•
•
Establishing a casing program
Determining the desired mud weights
Selecting the mud types
Time spent preparing a drilling fluids program will often be repaid. The drilling
operation is often critical. The boundary between success and failure may be quite
small. The hole stability is often time-dependent. Therefore, time saved in drilling,
perhaps by changing the bit and improving solids removal practices, may bring
about other benefits apart from the obvious financial ones.
2.0
DRILLING FLUID PROGRAM PLANNING
Drilling fluids programs are designed and based on a collection of information from
a specific drilling area. This information comes from many sources. The selection
of the appropriate drilling fluid cannot be made until all relevant information has
been gathered. A comprehensive drilling fluids program anticipates potential
problems. Such a program provides an engineer with the information to identify
problems discovered while drilling.
Seismic sections and geophysical charts provide much information and should be
examined carefully. The stratigraphic tops and the approximate depth at which
they will be encountered should be identified.
The overall process of planning a drilling fluids program for a well include the
following:
•
•
•
•
Review data from offset wells including geological information, mud recaps,
and bit records
Review casing programs
Determine desired mud weights
Select mud types
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•
•
•
Determine mud properties
Establish important mud and solids control operational details
Integrate with mechanical aspects of drilling, including hydraulics, directional
drilling, and bit types
2.1
Information from Offset Wells
This section will discuss information from offset wells including:
•
•
2.1.1
Geological characteristics of the formation
Previous well reports
Geological Characteristics of the Formation
When designing a mud program, pay close attention to the geology of
the drilling site. Information from adjacent wells and seismic sections
provide a guide to the formations that may be encountered. The
following procedure should be observed before deciding on a mud
program.
•
•
•
•
•
•
•
•
•
•
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Define lithology
List formation tops
Characterize formation composition
Estimate hardness and strength of the rocks
Estimate potential to hydrate and disperse
Estimate bedding plane orientation
Review tectonic history to estimate direction and magnitude of
stresses in the formation
Locate abnormal pressure zones and determine fracture
gradients
Determine probable production intervals
Determine temperature gradient and bottom hole temperature
(BHT).
Certain drilling fluid formulations are temperature
sensitive. These include polymer-based systems and lime and
gypsum muds. The expected bottom hole temperature may
influence the choice of drilling fluid. Temperature also effects
the rate of fluid loss. Generally, an increase in temperature
results in greater fluid loss. This must be considered when
calculating the fluid loss properties of a drilling fluid. Corrosion
of drilling hardware increases as the temperature increases.
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•
The corrosion rate can double with every 55°F increase in
temperature.
Confirm casing points as these often correlate with formation
changes and formation tops
A particularly difficult shale sequence such as the Sudair, Unayzah,
and Qusaiba may justify further analysis using the techniques of XRD
analysis or determination of the cation exchange capacity. This will
allow a more accurate definition of the problem and show where the
problems with water sensitivity may be most critical.
2.1.2
Previous Well Reports
Attention should be paid to wells that have been drilled in the area of
the proposed well. If there is no radical change in the geology
between one site and another, then it can be expected that problems
encountered in previous wells may also occur in a new well. Points
that should be examined include:
•
•
•
•
•
•
•
•
•
Time spent on well
Mud type used
Suitability of mud used
Properties of the mud
-Mud weight
-Rheology (PV, YP, gels)
-Fluid loss (API, HTHP)
Type and configuration of solids control equipment
Types of bit
Penetration rates
Hydraulics
-Pumps and jets
-Weight on bit and RPMs
Hole problems
-Correlation with mud composition and properties
-Lost circulation
-Shale problems
-Differential sticking
-Key seats
Causes of problems in previous wells should be analyzed carefully.
These problems can then be “designed out” of future wells.
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2.2
Casing Program
This section will discuss the development of a casing program including:
•
•
Pore pressure and fracture gradient
Casing depths
2.2.1
Pore Pressure and Fracture Gradient
An accurate determination of the formation pressures to be
encountered is critical to the drilling operations.
Abnormal pressure environments may be detected and evaluated by
several methods summarized in Table 3C-1. As the table indicates,
the data may be obtained before the well is drilled, refined during the
drilling, and refined even more after the well is drilled and logged.
Table 3C-1, Techniques Used to Detect and Evaluate Over-pressure
Source of Data
Geophysical methods
Drilling parameters
Drilling fluid
Drilled cuttings
Well logging
Direct pressure measuring
devices
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Formation
“Formation” velocity, Gravity, and Magnetics
Electrical prospecting
methods
Drilling
rate
“d”
exponent
Torque, Drag
Drilling porosity log
Gas content, Flow line mud weight,“Kicks” Flow
line temperature
Chloride variation. Drill pipe pressure technique.
Pit level, volume. Flow rate and Hole fill-up
Shale cuttings. Bulk density. Methylene blue
adsorption.
Electrical resistivity
Volume, shape and size of cuttings
Electrical surveys
– Resistivity
– Conductivity
– Shale formation factor
– Salinity variations
– Interval transit time
– Bulk density
– Hydrogen density
– Thermal neutron capture cross-section
Downhole gravity data
Pressure bombs. Drill stem test. Wireline
formation test
Time of Recording
Prior to spudding well
While drilling
While drilling but delayed
by the time required for
mud return
While drilling but delayed
by the time required for
mud return
After drilling
While well is tested or
completed
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Fracture gradients can be calculated using one of three methods.
•
•
•
2.2.2
Hubert and Willis
Mathew and Kelly
Ben Eaton
Casing Depths
After the formation types, formation pressures, and pore pressures
have been considered, the most suitable positions for the casing
shoes can be determined. The number of casing strings will be
decided by factors such as the depth and the required diameters of
the production tubing. A mechanically competent rock should be
selected for the casing shoe so that it may be cemented in to take the
pressures of the next open hole.
Casing intervals should try to isolate formation types on the basis of
the pressure requirements or formation type that may require a
particular type of drilling fluid. For example, shales may require
inhibitive mud, such as a salt-polymer mud, to control hydration and
dispersion.
Evaporite sections often require separation. Consideration has to be
given to using salt-saturated mud. If the mud is not saturated, it will
be washed out. This may be tolerated, otherwise the mud should be
saturated to salt. For these conditions, a minimum density of 75 pcf
should be considered. If this density is too high, consideration should
be given to oil-based mud.
If the casing program introduces compromise situations where the
mud weight will be too high or too low for the formation, problems will
occur in drilling the section.
2.3
Drilling Fluid Program Preparation
•
•
•
Mud weights for each casing interval
Selection of fluid types
Specification of properties
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2.3.1
Mud Weights for Each Casing Interval
The required mud weight is determined by
•
•
•
•
Formation pressures
Mechanical characteristics
Potential for lost circulation
Potential for the formation to flow
The mud weights should be very carefully chosen since weight
materials can contribute 50 to 70 percent of the mud cost. If the mud
weight is too high, then
•
•
•
•
•
•
Mud costs will be excessive
Drilling rate will be impaired
Potential for fracturing the formation will be greater
Potential for lost circulation will be greater
Risk of formation damage will be greater
Risk of differential sticking will be greater
If the mud weight is too low, then
•
•
Problems may be caused by borehole instability
Risk from fluid invasion or a blow out may be increased
When the borehole is unstable, try to distinguish between instability
due to insufficient mud weight and instability due to low levels of
inhibition.
2.3.2
Selection of Fluid Types
Selection of drilling fluid types should be based on consideration of:
•
•
•
•
•
•
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Environmental factors, which will determine the list of acceptable
muds
Bottom hole temperatures
Optimum penetration rates
Formation composition and stability related to inhibitive property
Availability and properties of the continuous fluid phase
Producing formation evaluation to determine the potential for
formation damage
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•
Availability and quality of formulation and treatment chemicals
The selection of the appropriate drilling fluid for a well must also
consider environmental concerns for the area in which drilling is taking
place. Care should be taken to minimize the effects of drilling on the
environment by selecting nontoxic drilling additives, providing
adequate disposal of waste mud, etc.
Certain drilling fluid formulations are temperature sensitive. These
include polymer-based systems and lime and gypsum muds.
Therefore, the expected bottom hole temperature is required
beforehand, as it may influence the choice of drilling fluid.
Temperature also effects the rate of fluid loss. Generally an increase
in temperature results in greater fluid loss. This must be taken into
account when calculating the fluid loss properties of a drilling fluid.
Corrosion of drilling hardware increases as the temperature
increases. The corrosion rate can double with every 55 F increase in
temperature.
The inhibitive requirements largely determine the formulation. Freshwater muds offer the lowest level of inhibition but the lowest cost.
Increased inhibition will move the mud towards the calcium-based
muds and then on to the polymer muds.
2.3.3
Specification of Properties
The physical and chemical properties of the drilling fluid are specified
for each selection based on optimum drilling and economic
performance. Of particular importance are
•
•
•
•
Rheology for optimum hole cleaning and hydraulics
Filtrate loss and filter cake quality for optimum formation
stability, penetration rate, and formation productivity
Alkalinity and salt content for optimum mud performance and
formation inhibition
Solids type and concentration
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2.4
Technical and Cost Objectives
The costs of individual components should be distinguished from the cost of
the overall well. For example, using more expensive inhibited mud may allow
a hole to be drilled quicker or casing to be set lower. Efficient hole cleaning
in the larger hole sizes may require purchase of a larger diameter drillstring,
installation of additional mud pumps, and more shaker screen capacity.
These expensive capital items can be justified if the hole section can be
drilled without any problems. A reduction in the drilling time due to fewer
hole-cleaning problems brings further benefits as time-related instability is
reduced.
Protection of the productivity of the producing zones should also be
considered. A tighter specification and inclusion of bridging agents may
reduce the formation damage caused by invasion of incompatible filtrate and
mud solids.
Detailed drilling fluid formulation design for each hole interval
The hole should be considered section by section. The mud is defined for
each section. Each section should begin with a statement detailing the
objectives of the mud program and an explanation of how and why the
particular properties and system were chosen.
2.5
Mud Formulation
General points to be taken into consideration are as follows:
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•
In areas of soft rock and high ROP, large volumes of mud will usually be
required, and inhibition is unimportant. Preference should be given to
inexpensive mud systems with high solids tolerance. This include
bentonite / lime muds, or polymer-extended bentonite muds.
•
In areas where temperature is a problem, such as when using highdensity muds, systems with high temperature tolerance should be used.
These include low clay deflocculated polymer systems (where there is
close control of drilled solids content), synthetic high temperature
polymer muds, or oil-based systems.
•
In medium to large diameter holes (12-1/4 inch and larger) with
unweighted muds, both hole cleaning and hole enlargement are usually
primary concerns. Simple flocculated bentonite systems with high
structural viscosity should be considered.
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The required inhibitive properties are an essential consideration controlling
the character of the mud and the formulation.
The formulation should be derived from a combination of laboratory and field
experience. The mud products should be closely specified so that their
performance in the field is well defined.
This section should specify the material concentrations (usually in lb/bbl
units) of all the mud additives during the particular interval. If major variations
in the mud density are expected during the hole interval, then more than one
formulation should be included in the program. For example, if during the
interval the mud density is programmed to increase from 10.5 to 14.5 ppg,
then formulations should be given for muds with densities of 10.5, 12.0, 13.0,
and 14.5 ppg.
2.6
Mud Properties
In many areas, there are “standard” drilling fluid programs. Deviation from
this standard system should be justified. The expected advantages and
differences between the chosen mud and the standard program should be
described.
The rheological properties are designed as a consequence of the hydraulic
considerations and the mud weight.
The formulation should include only those properties considered necessary to
the success of the mud program. There is no need to include all those
properties listed on the API Mud Report form. It should state which
properties are critically important and which properties are less important.
Usually it should state the reason for controlling the property and, if
applicable, how to control the property.
3.0
APPLYING A DRILLING FLUIDS PROGRAM
Application of a drilling fluid program in terms of implementation and trend analysis.
3.1
Implementation
The mud materials should be ordered and delivered to the rig site. The mud
engineer and drilling crew should be familiarized with the aims and objectives
of the mud systems and any special requirements. The solids removal
equipment should be specified and installed on the rig.
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3.2
Trend Analysis
During the process of drilling a well, the wellbore and the drilling fluid provide
valuable information and feed back on the overall operation. Sometimes the
feed back is immediate and straight forward. Other times it is subtler, and the
trend can only be spotted by careful analysis of trends over a longer time
period.
The trends that should be analyzed include:
•
•
•
•
•
•
•
Basic mud properties to see if they are changing
Contaminants identified from the changes in chemical and physical
properties. Mud chemical usage to see if there are deviations from the
program and initial formulation
Additions of water to monitor mud volumes built and to correlate with
solids build up and operation of the solids removal equipment
Volumes of cuttings and type of cuttings over the shaker to see if the
hole is being cleaned efficiently and to detect hole failure in the form of
cavings coming to the surface
Tight connections, an indication that the mud weight may be too low or
that the hole is not being cleaned properly
Connection gas, an indication that the mud density is too low
Torque and string weights on tripping, indications that the lubricity of the
mud should be changed or of deterioration in the hole condition
When a trend is detected, the mud can be treated before a problem
emerges.
4.0
DRILLING FLUID MANAGEMENT
The Foreman is directly responsible for the daily conditioning of the mud. To
deviate from the mud program as outlined in the well program, the Foreman must
obtain prior approval from the Drilling Superintendent.
Technical analysis and treatment of the drilling fluids may be obtained from various
sources:
4.1
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A Contract Mud Engineer may be utilized with the prior approval of the
Drilling Superintendent.
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5.0
4.2
Drilling Fluids Specialist, Lab R&D Center in Dhahran may be contacted
for technical assistance. He can aid in locating materials, and suggesting
possible mud treatments and alternative chemicals. The Lab R&D Specialist
can further coordinate with the contract Mud Engineers, and with the
Shedgum Mud Plant when needed.
4.3
Saudi Aramco Drilling Fluid Laboratory, Lab R&D Center in Dhahran ,
can provide extensive field and/or laboratory analysis of field muds and can
further assist in recommending treatments for problem muds.
4.4
Saudi Aramco Drilling Engineer assigned to the rig should analyze the
solids control equipment, and make recommendations to improve the rig
performance.
4.5
Shedgum Mud Plant should be used to store and recycle the drilling and
completion fluids. Also, pre-mix a special drilling fluid.
RESPONSIBILITIES AND DUTIES
5.1
The Foreman’s Responsibilities:
A)
The Foreman will make certain that the mud type and properties as
specified in the drilling program are developed and maintained.
B)
The Foreman will consult his Drilling Superintendent to determine the
extent to which the various Mud Engineering Services will be used.
C)
The Drilling Foreman will personally inspect the contractor’s rig to make
certain that all mud equipment as specified in the contract is on location
and is operating satisfactorily. This tour will include inspecting the shale
shakers to make certain that the proper size screens are in place, that
the proper cone liners are installed in the Hydrocyclones and that the
latter are functioning properly. The Foreman should also inspect the
mud cleaner and the centrifuge (if one is installed), make certain that
the mud pit volumes specified in the contract are correct, and in
general, make sure that everything is ‘as it should be’. If he has any
doubts concerning the solids control equipment and/or its operation, he
may request assistance from Drilling Engineering.
D)
The Foreman will keep an inventory of all mud materials used in the
following manner:
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E)
1.
The transfer of drilling materials is to be completed and submitted
for each well (see Aramco Form # 5518).
2.
Use the daily drilling report form to state the actual amounts of
materials used that day. DO NOT USE AVERAGES OVER A
PERIOD OF TIME.
The Foreman will maintain a record of the following fluid properties:
1.
2.
3.
4.
5.
6.
5.2
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HOURLY:
•
Weight (pcf)
•
Funnel viscosity (Sec)
TWICE A TOUR:
•
API water loss (ml/30 mins)
•
pH
ONCE A TOUR: (with Mud Engineer on site)
•
PV / YP
ONCE A TOUR: (with oil based muds & Mud Engineer on site)
•
Electrical stability (volts)
•
Alkalinity (Pm)
•
HTHP water loss (ml/30 mins @ 300oF and 500 psi)
Daily (with Mud Engineer on site)
•
Methyl Blue Test (lbs. of Bentonite/bbl mud)
•
Alkalinities (Pm, pf/Mf)
DAILY: (below 10,000 ft. with Mud Engineer on site)
•
HTHP fluid loss (ml/30 mins @ 300oF and 500 psi)
The Contract Mud Engineer’s Responsibilities
A)
The Mud Engineer on location shall perform the standard API drilling
fluid analysis at least once a day. This test will be completed on the API
Mud Drilling Mud Report Form and submitted to the Foreman prior to
0500 hours. The mud engineer may be required to run more than one
test a day.
B)
The Mud Engineer shall complete his own Company’s Report Form in
full and shall include the flowline and suction temperature and the
temperature(s) at which the PV, YP, and gels are measured. When
desanders, desilters, mud cleaners, or centrifuges are in use, both the
underflow and the overflow mud weights shall be recorded for each
device in use. The feed header pressure will also be recorded for each
device in use. The shale shaker screen size(s) and other equipment
specifications are to be reported, including any non-functioning or mal-
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functioning solids removal equipment. The frequency of sand trap
dumping and the total volume of mud dumped each day shall also be
reported. All materials used, and the method of addition (how
dispersed, length of time to disperse, problems encountered, etc.) shall
be included as comments on the API Mud Report.
C)
D)
5.3
The Mud Engineer shall use the Saudi Aramco rig mailing system to
transfer a copy of each day’s mud report to the Drilling & Workover
Engineering Division office, Dhahran.
The mud engineer on location shall make all recommendations as to
mud treatment in writing, using the Mud Report Form. This form will be
given to the Drilling Foreman.
The Saudi Aramco Drilling Engineer’s Responsibilities
A)
The Aramco Foreman is encouraged to refer any mud problems to the
Drilling Engineer(s) assigned to his rig for consultation.
B)
The Aramco Drilling Engineer should maintain a current diagram of
the entire circulating system with all pipes, valves, solids equipment,
transfer pumps, tanks and degasser clearly marked. The make and
size of pertinent equipment shall be shown. A copy of this diagram
should be provided to the Foreman who is encouraged to make
appropriate corrections and/or comments. This diagram could be
invaluable during an emergency operation.
The Foreman is encouraged to enlist the services of the Aramco Drilling
Engineer as to the performance of the solids control equipment.
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6.0
BASIC FIELD TESTING EQUIPMENT
The required field tests are listed on the API Drilling Mud Report form (API RP
13G, Second Edition, May 1982 and Third Edition, February 1992).
Standard field testing for water-based drilling fluids
(API 13B-1, June 1,1990 &/or future revisions)
TEST
EQUIPMENT
Mud weight (density):
Viscosity:
Rheology & Gel Strength:
Atmospheric Mud balance and Pressurized Mud balance
Marsh Funnel, Graduated Cup (one-quart) and Thermometer
Six- speed Viscometer (3,6,100,200,300&600 rpm) and
heated cup 220ºF
Filtration:
Filtration:
Low-Temperature / Low-Pressure cell
High-Temperature/High-Pressure
with pressure & heating system)
Retort instrument (50-cm3)
200-mesh sieve, funnel and glass measuring tube
(Sand content set)
Water, oil and solids:
Sand content:
Reactive Clays:
Mud or filtrate pH:
Methylene blue capacity (MBT)
pH meter (0-14), for 150ºF, resolution 0.1 unit &
calibration solutions
pH Paper (0-14)
H2S test:
Alkalinity & lime content:
Chloride:
Total hardness Ca & Mg):
Calcium, Magnesium:
Calcium sulfate:
Aldehyde:
Sulfide & carbonate:
Hydrogen sulfide detection kit (Lead acetate paper discs)
Chemical analysis kit
Chemical analysis kit
Chemical analysis kit
Chemical analysis kit
Chemical analysis kit
Chemical analysis kit for monitoring the biocide treatment
Garrett Gas Train and Drager tubes for low and high
CO2 and H2S
Potassium above 5000 mg/l:
Chemical analysis kit for monitoring potassium ion concentration
Formulation Pilot Tests :
Pilot test kit ( balance, Hamilton beach mixer.......etc. )
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Standard field testing for Oil-based drilling fluids
(API 13B-2, Dec. 1,1991 &/or future revisions)
TEST
EQUIPMENT
Whole mud alkalinity:
Chemical analysis kit for oil-based mud to measure “
excess” lime.
Chemical analysis kit for oil-based mud to measure chloride
in the aqueous phase.
Chemical analysis kit for oil-based mud.
Electrical stability meter with calibration resistors / diodes.
Retort instrument (50-cm3) and a hand-held calculator for.
correctly performing mathematical operations detailed in the
API procedure.
Whole mud chloride:
Whole mud calcium:
Emulsion stability:
Solids content:
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SOLIDS CONTROL
1.0
INTRODUCTION
1.1 Description of Solids in Drilling Fluids
1.2 Lost Circulation Solids
1.3 Weighting Agent
1.4 Colloidal Clays
1.5 Formation Solids
2.0
SOLIDS CONTROL EQUIPMENT
2.1 Shaker Screens
2.2 Hydrocyclones
2.3 Mud Cleaners
2.4 Centrifuges
2.4.1 Centrifuging Unweighted Mud
2.4.2 Centrifuging Weighted Mud
2.4.3 Dual Stage Centrifuging
2.4.4 Centrifuging Hydroclone Under Flow
3.0
SELECTION OF EQUIPMENT AND CONFIGURATION
3.1 Design Considerations
3.1.1 Type of Formation
3.1.2 Inhibitive Properties of the Mud
3.1.3 Density of the Mud
3.1.4 Size of the Hole
3.1.5 Drilling Rate
3.1.6 Availability of Equipment
3.1.7 Dumping Restrictions
3.1.8 Equipment Selection
3.1.9 Low-Density Muds
3.1.10 High-Density Muds
3.1.11 Oil-Base Muds
4.0
PERFORMANCE ASSESSMENT
4.1 Identification & Correction of Malfunctions
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SOLIDS CONTROL
1.0
INTRODUCTION
An important key to successful and economic drilling operations is the effective
removal of the drilled formation solids. If these solids are incorporated into the
mud, they will have a detrimental effect on many critical mud properties, such as
the rheological and fluid loss properties, which in turn may adversely affect the
drilling operation. The higher surface area of the fine entrained solids increases
the chemical treatments such as the fluid loss additive, and dramatically increases
the mud costs.
Fine drilled solids build up make management of the mud rheological properties
difficult. The hydrodynamic volume of the solids increases, which increases the
plastic viscosity and the gel characteristics. These changes reduce penetration
rates, increase circulation pressure losses, and lessen the carrying capacity of the
mud.
The higher solids content gives thicker wall cake, increasing the frequency of
differential sticking problems. The pump parts and bit also wear out faster.
1.1
Description of Solids in Drilling Fluids
The solids in the drilling fluid can be divided into lost circulation solids,
weighting agents, colloidal clays added as mud additives, and drilled solids
as cuttings or dispersed solids. The essential properties of solids can be
described in terms of:
•
•
•
•
Size
Density
Shape
Hardness
Consideration of both the size and density of the solids determines the type
of solids removal equipment to be used. The size of the solids is usually
measured in microns (µ) where one thousand microns = 1 millimeter (mm) =
0.03937 inches. The human hair is about 50 µ in diameter.
The size of the solids that come to the surface range from particles measured
in millimeters (mm = 1000 microns) down to clays with sizes less than a
micron. Table 3D-1 gives the terms normally used to describe the particle
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SOLIDS CONTROL
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size. Consideration of both the size and density of the particle determines the
methods used to separate the particles.
TABLE 3D-1. Size Definitions in Drilling Fluids
Size(Microns, µ)
API Name
2000
Common Name
Coarse
Large
250
Intermediate
Sand
74
Medium
44
Fine
2
Ultra fine
Below 1
Colloidal
420
1.2
Silt
Clays
Lost Circulation Solids
Lost circulation solids are added to prevent loss of whole mud to the
formation. They are designed to bridge large pores in highly permeable
sands and vugs and fractures.
Essentially three types of material are added, defined as fiber (such as wood
or hair), flakes (mica, cellophane), and granular (walnut shells, marble
chippings). The size ranges are summarized in Table 3D-2.
TABLE 3D-2. Size Ranges
of Lost Circulation Material
Material
Size Range (µ)
Cellulose fiber
2 - 200
Ground marble
2 - 600
Mica flakes
150 - 1,200
Walnut
150 - 4,800
Marble chips
2,000 - 5,000
The addition of these materials to the mud can seriously affect the
performance of the shaker screen by blinding it. If so, the screens may have
to be by-passed.
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1.3
Weighting Agent
These solids are intentionally added to the mud to increase the density of the
finished mud. The range of materials that may be added, the density of the
material, and the maximum mud weight is summarized in Table 3D-3
TABLE 3D-3. Weighting MaterialsUsed to Increase Mud Density
Material
Calcite & Dolomite
Specific Gravity
Maximum Mud Weight
2.70 – 2.78
1.40 SG
110 pcf
3.74
2.28 SG
142 pcf
Barite
4.2-4.3
2.65 SG
156 pcf
Illmenite
4.5-5.0
3.11 SG
190 pcf
Hematite
4.7-5.05
3.11 SG
190 pcf
Galena
7.4-7.7
3.6 SG
220 pcf
Siderite
The selection of the material will relate to the required density. Barite is most
widely used above a density of 1.2 SG (74 pcf). Calcium carbonate is used
as an alternative for low density muds. Iron oxide, such as hematite, are
used for higher density fluids and in oil muds over 1.8 SG (112 pcf).
The size ranges of the weighting agents is in the range of 10 to 80 µ, and the
median size is in the range of 12 to 16 µ. The level of coarse material (above
50 µ) is limited to about 10% to minimize losses in desander/desilter units.
The level of fines (less than 10 µ) is limited to about 20 to 30% to minimize
problems with the rheological properties of the mud, such as excessive
plastic viscosities, yield points, and gels.
Solids removal techniques, such as hydrocyclones and centrifuges, depend
on gravitational forces that are related to the size and density of the particle.
Even though barite is approximately twice as dense as drilled solids, a
smaller barite particle will be removed with the same ease as a larger
formation solid. This mixture of particles with differ