D rilling I nnovations
V ol ume 2 , No. 2 , 2 0 1 4
A sp e rry D RILL ING Tec h nology Jour nal
In This Issue
Advancements in
Powered Rotary Steerable
Technologies Result in
Record-Breaking Runs
See pages 4-9
Optimized Platform
Placement to Cover All
Geological Targets in
Baronia Field
See pages 35-40
Executive Steering Committee
Eric Carre
Senior Vice President, Drilling and Evaluation
Ahmed Kenawi
Vice President, Sperry Drilling
A Message from Ahmed Kenawi
Greg Powers
Vice President, Technology
Editorial Advisory Committee
Welcome to the fourth issue of Drilling Innovations –
a technical journal that focuses on Halliburton
solutions and technical successes.
Halliburton is uniquely positioned to solve increasingly
complex drilling challenges by utilizing the expertise
offered by Drilling Engineering Solutions (DES) – an
integration between Sperry Drilling, Baroid and Drills
Bits and Services. DES strengthens Halliburton’s
ability to offer customers risk mitigation, optimized
well bore placement for increased reserve recovery,
and maximized drilling performance.
An integrated performance drilling systems approach
has helped our customers in challenging environments. In this issue, several papers illustrate
how an integrated solutions-based approach been successful. For example, a through
motor telemetry (TMT) powered rotary steerable system combined with early planning, risk
assessment and global experience set new records, and exceeded benchmarks in difficult
formations. Another paper explains how careful planning and collaboration among subject
matter experts resulted in high production levels in two multilateral wells due to the effective
execution of the drilling and completion phases.
These examples, along with the rest of the papers in this issue, highlight the tangible
benefits of drilling optimization. By using cutting edge technology and collaborating with the
right technical experts, Sperry can provide customers with the solutions needed to drill safe,
faster and on target every time. Additionally, you can find more in-depth information about
Sperry’s drilling expertise in the Drilling Engineer Solutions and Applications Handbook,
which I encourage you to ask your Halliburton contact about.
Please enjoy this issue of Drilling Innovations, and as always, feel free to contact me if you
have any questions.
Kind regards,
Mac Upshall
Akshay Sagar
Andreas Grossmann
Derrick Lewis
Managing Editor
Roselle Mohle
Circulation
Steven Thrift
Design
Griffin Creative Company
This magazine is published biannually
by Halliburton Sperry Drilling.
For comments and suggestions,
please contact: Sperry@Halliburton.com.
Sperry Drilling’s DrillDOC® collars provide the
measurements necessary to fully understand
downhole drilling dynamics. They deliver real-time
measurement of torsion, weight, bending and
vibration measurements.
Directly measuring tension, torsion, bending and
vibration identifies the actual drilling parameters
that are being applied to the bottomhole assembly
(BHA) and the bit. These measurements, utilized by
our experts can give operators greater insight into the
wellbore to reduce uncertainty, minimize unplanned
events and optimize the drilling performance.
Ahmed Kenawi
Sperry Drilling Vice President
© Copyright 2014 Halliburton
All rights reserved.
2
Contents
4
4
Advancements in Powered Rotary Steerable Technologies
Result in Record-Breaking Runs
Geo-Pilot® GXT Rotary Steerable System Fit-For-Purpose Solution
9Planning Managed Pressure Drilling With Two-Phase Fluid
in a Depleted Reservoir
Managed Pressure Drilling Bergermeer Gas Storage Project
9
17Multilateral TAML Level 4 Junction Provides Maximum Flexibility
for Drilling and Intelligent Completions
Planning and Executing an Intelligent Multilateral Well
17
23Challenges and Successes in Horizontal Drilling Shallow 3D
Unconventional Turbidite Reservoir, Mexico
E xploiting Vast Oil Resources in Mexico’s Chicontepec Basin
31Instrumented Motors Prove Crucial in Unconventional
Well Placement
Real-Time Geosteering with Gabi™ Motor
34Optimized Platform Placement to Cover All Geological
Targets in Baronia Field
Enhanced Oil Recovery Project Malaysia
23
40Overcoming Extreme Weather Conditions by Drilling with Mpd
Offshore in the Arctic
Alaska Field Improves Drilling Economics with MPD
31
45Are You on the Right Track with Casing Milling? Innovative
Precision-Milled Windows Offer Improved Casing Exit Reliability
for Sidetracking and Multilateral Completions
MillRite® System Premium Replacement for Conventional Milling
34
40
45
3
G EO - PI LO T ® G X T RO T A RY S T EER AB LE SYS T EM F IT -F OR- PURPOSE SOLU TI ON
Advancements in Powered Rotary
Steerable Technologies Result in
Record-Breaking Runs
drilling applications. Operators drilling extendedreach wells do not want to cause excessive wear
on casing strings; additionally, operators want a
solution to mitigate stick-slip. TMT powered RSS
is bringing these and other important benefits to
the drilling process.
Hernando Jerez, SPE, and Jim Tilley, SPE, Halliburton
Applications
Copyright 2014, Society of Petroleum Engineers
This paper was prepared for presentation at the SPE Latin American and Caribbean Petroleum Engineering Conference held in
Maracaibo, Venezuela, 21–23 May 2014.
This paper was selected for presentation by an SPE program committee following review of information contained in an abstract
submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject
to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its
officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the
Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300
words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
Reproduced with permission of the copyright owner. Further reproduction prohibited without permission.
Abstract
Drilling operators continually experience increasing pressure to achieve all objectives safely and at the
lowest cost. Powered rotary steerable systems (RSS), applied within the correct drilling environment,
can improve rate of penetration (ROP), lower risks, and reduce non-productive time (NPT), which can
decrease drilling costs.
Using through motor telemetry (TMT) technology, a wired motor with a hollow rotor and flex shaft,
allows a connection between rotary steerable systems (RSS) and logging while drilling (LWD) downhole
tools. A conductor passes power and communication through the motor to operate and steer the RSS.
The wired power section uses a uniform wall thickness stator design that reduces heat production and
retention. It also delivers higher rev/min and torque directly to the RSS and bit. Using the TMT powered
RSS not only has improved ROP, but has also mitigated stick-slip vibration and reduced NPT. The NPT
improvements have been identified in areas, such as slip-stick vibration, drill string failures, drill string
torque variations, casing wear, and rig equipment failures.
Early planning and risk assessment have also been key. Experience across the globe, both on and
offshore, are presented to show the benefits of integrating advanced drilling technologies, such as TMT
powered RSS and real-time downhole measurements with effective planning, to reap tangible benefits
from drilling optimization.
With improved performance as a result of increased torque capacity and bit speed, and reduction of
the stick-slip mechanism, this new motor-driven rotary steerable technology has delivered superior
performance and improved ROP in challenging medium and hard formations. After more than 10,000
drilling hours and nearly half a million feet drilled, TMT powered RSS technology is setting new records
and exceeding benchmarks by bringing greater horsepower to the rock destruction process with longer
runs and higher ROPs.
Introduction
4
Optimized drilling systems include not only
matched drilling tools, but also the integration
of technology, processes, and people across all
stages of the drilling process1. This is important
as the industry places emphasis on improvement
to drilling programs to reduce NPT, improve safety
and efficiency, and optimize production.
drilling tools have greatly improved drilling
efficiency and allowed much higher ROPs.
Choosing the proper drilling system is critical
to boosting the well construction process and
pushing the drilling limit. The proper BHA design
and modeling is critical to drilling the well
and contributes to the optimization of drilling
efficiency.
Fit-for-purpose bottomhole assemblies (BHAs)
together with a wide array of advanced downhole
Delivering power downhole without increasing the
rotary speed of the drillstring is a demand in some
TMT powered RSS has a broad range of
applications, focused mainly on performance
drilling and mitigating certain drilling phenomena,
such as vibration. Because of the wired connection
and the modular design, drilling optimization or
formation evaluation sensors can be incorporated
in front of the wired motor, providing great
versatility to the BHA configuration.
From a performance point of view, TMT powered
RSS increases ROP, decreases vibration, and
decreases casing wear by delivering the torque
directly to the bit. The power section decouples
the drilling string from the RSS, eliminating
torsional vibration common in RSS applications.
This benefit increases reliability not only for the
RSS but also for all of the electronic sensors in
the string including optimization and formation
evaluation sensors. In addition, the drill bit lasts
longer and can deliver better ROPs.
An important application for TMT powered RSS
is in instances when the drilling rig experiences
limit capacity related to top drive power to rotate
the drilling string or drillpipe torque limitations.
Using a TMT powered RSS can reduce stress on
the rig and reduces wear on topdrive and drill pipe.
Extended-reach drilling (ERD) and complex well
profiles are classic applications for TMT powered
RSS by reducing surface torque and increasing
reach capabilities.
A TMT powered RSS allows a variety
of sensor combinations for multiple applications,
including geosteering, performance drilling,
and reduced stick-out in casing while drilling
applications.
Benefits
• More energy is directly applied to the bit,
improving cutting efficiency and ROP while
also overcoming stick-slip and torsional related
dysfunctions.
• Decoupling of the bit from the drillstring reduces
transmission of vibrations to LWD and other
BHA components, improving life.
• Drill string rotary speed can be reduced
to minimize casing wear while bit speed
is optimized for the best drilling performance.
• When applied in the proper drilling environment,
TMT powered RSS improves ROP and reduces
NPT, leveraging to drill faster and with less risk,
resulting in decreased costs.
• Improved ERD capabilities and exposure
of the payzone, which can greatly reduce capital
expenditure.
• The TMT powered RSS shows capability of
significantly increasing ROP in conditions where
rig topdrive does not provide adequate torque
and surface rev/min.
TMT Motor Design
RSS’s generally require communication with the
measurement while drilling (MWD) system to
transmit directional control information to the
surface and to transmit directional commands from
the surface to the RSS. Directional information
from the RSS is critical information for the
directional driller to help ensure the well path is
being drilled according to the directional plan.
Communication between the RSS and MWD
is also required to send formation evaluation
information from sensors located in the RSS to the
surface. An example is the azimuthal gamma ray
sensor located in the RSS. Wiring the RSS motor
allows transmission of power and high speed
communications between the RSS and the MWD.
The power section is designed for high torque low
speed operation. Fig. 1 shows a schematic of the
main components of TMT.
The main challenges in the wired motor design
include compensating for the eccentric motion
of the rotor in the power section, passing the
transmission section and the bearing pack and
compensating for different rotational speeds
between the rotor and upper housing.
TMT Motor Design Features
The rotor in a power section has an eccentric
and axial motion that is a function of the lobe
Figure 1. – TMT main components.
configuration, the fewer the lobes, the higher
degree of eccentric motion. When passing a
conductor from the top of the rotor to the top
of the motor housing, this eccentric and axial
motion must be compensated for. The method
employed is to use a mechanical compensator
that compensates for movement in the
axial and radial directions while providing a
bidirectional continuous conductor for power and
communications transmission.
Rotation must also be compensated for because
the rotor is decoupled from the upper housing in
the rotational sense. A slip ring is employed to
allow for the differential rotation while, at the
same time, providing a conductor for stable power
transmission and for high frequency, high speed
communications.
The TMT motor design employs a titanium flex
shaft to transmit rotation from the power section
to the driveshaft. The flex shaft design allows
incorporation of a solid conductor through a bore
in the center. In addition, the titanium flex shaft
provides high torque capability to drive higher
loading below the wired motor.
The TMT motor has flexibility to use virtually any
conventional power section provided the torque
and rev/min specification is within the tool limits
and application requirements. The preferred power
section type is uniform wall thickness. The uniform
wall thickness power section provides higher
torque output and a higher temperature rating.
Higher torque capability will allow for smoother
rotation of the RSS and drill at a higher ROP. In
addition, the uniform wall thickness expands with
temperature at a constant rate. Thinner rubber
thickness that expands at a constant rate means
that the rotor and stator can be fit precisely
for high temperature application. This allows
application of the TMT technology at temperatures
up to 175°C.
Wired Motor— RSS BHA Design
The placement of a motor in an RSS assembly
requires consideration of the impact on the MWD,
RSS, and BHA performance. The system described
here is modular in design, which allows flexibility
in placement of the motor in the BHA. The motor
can be placed between the RSS and MWD or
within the modular MWD components.
The optimum placement of the power section is
normally directly on top of the RSS and below
the MWD. This placement allows torque to be
delivered directly to the RSS, allows higher bit
speed without over-rotating the MWD, minimizes
the amount of string below the power section, and
decouples vibration to the MWD and upper string.
The BHA can also be designed with drilling
optimization sensors or LWD sensors located
below the motor. Placement of the drilling
optimization sensor below the motor and above
the RSS can be used to measure torque, weight
on bit (WOB), and bending on bit, for example,
directly above the RSS for drilling optimization.
LWD sensors can be placed directly above the
RSS and below the motor to obtain measurements
closer to the bit.
The wired motor can also be configured with a
bent housing for conventional motor applications,
allowing power and communication to the bottom
of the motor and placement of sensors directly on
top of the bit. Typical applications include ranging
sensors for intersection wells and LWD sensors for
near bit formation evaluation. Fig. 2. shows some
BHA configurations depending on the application.
Figure 2. – Modular BHA configuration using a
TMT powered RSS.
5
G EO - PI LO T ® G X T RO T A RY S T EER AB LE SYS T EM F IT -F OR- PURPOSE SOLU TI ON
Geological proposal, however, identified a hard/
abrasive drilling environment, multilayered dipping,
and folded formations with dips in the range 40
to 70°. The stratigraphy of this area corresponds
to the old Mesozoic and Paleozoic geological eras
starting with the Cretaceous period, subjacent by
Jurassic, Devonian, Silurian, and Cambric. On top
of the hardness and abrasiveness, the geological
cross-section shows important discontinuities with
highly faulty events.
Figure 3. – TMT RSS application with vibration data above and below the motor.
Case History 1—
Offshore Deepwater UK
TMT powered RSS technology was used for an
operator in a high-pressure/high-temperature (HP/
HT) development well in the UK Central North
Sea. The challenge included maximizing ROP
through hard chalk / limestone formations in the
12 1/4-in. section and then drilling the 8-in. hole
section through the HP/HT reservoir using LWD,
eliminating the need for wireline.
In the 12 1/4-in. section, the TMT RSS assembly
was used to drill from 5,276 to 13,938 ft (1,608
to 4,248 m) measured depth (MD). Average
penetration rate was 78.6 ft/hr (24 m/hr), a
62% improvement over conventional rotary
steerable system performance in an offset
well. Total footage drilled was 8,662 ft (2,640 m)
with zero NPT.
In the 8 1/2-in. section, The HP/HT TMT RSS BHA
with HP/HT LWD quad combo delivered the
entire 2,323-ft (708-m) section in a single run,
intersecting all geological targets with zero NPT.
In what was the fourth longest section in the UK
for drilling hours on bottom since records began,
the LWD quad combo was downhole for 355 hr
(14.8 days) with 296 circulating hr (12.3 days).
Successful LWD performance eliminated the
need for wireline logging, and the well reached
total depth (TD) at 16,232 ft (4,948 m) 25 days
ahead of plan.
A major benefit of TMT technology is this case
was decoupling the BHA to reduce vibration on the
LWD and upper string. This reduces damage and
potential NPT while, at the same time, improving
ROP and drilling performance. Fig. 3. (a time based
6
log) shows that, while some torsional resonance
vibration exists below the motor, it is not
transmitted to the LWD tool and drillstring above.
In this particular case, two downhole vibration
sensors were part of the drill string, the first
between the RSS and the TMT motor and a second
one behind the TMT motor within the LWD. The
left graph in figure 3 is the data from the sensor
below the TMT, it shows in the track #4 high
average values of vibrations both in Y and X axis;
on the other hand, the right graph in the same
track (sensor above the TMT) shows minimum or
null average vibration values both X and Y axis.
This is the decoupling effect from the TMT motor,
which reduces transmission of vibrations.
The first well was drilled with a rotary BHA
including a straight mud motor. Low ROP was
experienced, and the hole inclination drifted
until reaching an equilibrium angle around 20º.
The drilling continued with the hole deviation
moving in the 10 to 20º range of inclination.
The equilibrium angle is dependent on various
factors, including formation dip angle, drillability
anisotropy, and drilling parameters in use. The
well was TD with 13º of inclination and a vertical
section of 270 m.
For the second well, a drilling motor was used with
both sliding and rotating drilling modes in both
intervals (12 1/4- and 8 1/2-in. hole sizes), ROP was
lower compared to the first well because of the
directional work to keep the well close to vertical.
The abrasiveness of the formation required
performing several trips to drill each interval.
Another well used a push the bit vertical seeking
tool powered with a motor above it; this approach
managed to drill the well vertical and improve ROP.
The vibration measured below the TMT
motor was -5.0 g average x-y delta torsional
resonance. The vibration measured above
the TMT motor was -0.5 g average x-y delta
torsional resonance, indicating a reduction
due to the decoupling effect.
Case History 2—Continental Europe
Exploratory Campaign
In this vertical drilling application, the
TMT powered RSS delivered maximum
performance, outperforming the benchmark
well in the area with RSS or performance
motors. During a four-well exploratory
campaign, different drilling systems were
used aiming to maximize ROP. The structural
setting in this continental Europe project
corresponds to ancient Paleozoic and
Mesozoic depositions. Because of limited
drilling, not much information was known at
the beginning of the project.
Figure 4. – (left) drilling time curve for the four wells
campaign; (right) inclination data for the four wells.
Still, some drilling inefficiencies were experienced,
including vibration that reduces the life of the bit.
The last well incorporated a point the bit RSS
together with a wired power section to drill both
the 12 1/4- and 8 1/2-in. intervals. The TMT powered
RSS system not only managed to keep the well
close to 0º inclination but, because of the vertical
cruise control mode in use, the drilling time was
optimized by drilling the well in automatic vertical
mode, maximizing ROP. Fig. 4. (left) shows the
time drilling curve for the four exploratory wells.
The TMT powered RSS also shows value to keep
the well vertical. Fig. 4. (right) shows the deviation
survey for the four wells.
During the entire run, the TMT powered RSS
observed a strong build tendency caused by the
steeply dipping formation. The TMT powered RSS
was operated with bit deflection over 60% and
mainly at 80 to 90% to keep the wellbore vertical.
Vibration mitigation measures were employed
at the direction of real-time engineering
monitoring; however, low to medium vibration
severity was still present while drilling in the
presence of interbedded formations; medium
to high vibration was also present when picking
up the bit off bottom.
secondary reservoir by dropping angle to 84° and
steering inside that zone for approximately 900 ft.
With an average ROP of 36.4 ft/hr in the 6 1/8-in.
lateral section, this run also established a field
record. Fig. 5. shows the trajectory created.
In the build section alone, a field record average
ROP of 59.60 ft/hr saved the operator 2days, or
approximately USD 100,000, while in the
6 1/8-in. section. The geosteering assembly
achieved a field record average ROP of 36.4 ft/hr
to save the operator another 3 1/2 days, or about
USD 175,000.
Case History 4 Unconventional Play
Drilling efficiency requires attention to a variety
of key indicators. Modeling BHAs together with
advanced drilling technologies contributes to
the stability of the drilling system, optimum
performance, and ultimately improvement to
efficiency. The fourth case history was in an
unconventional play in which a TMT powered
RSS was used to drill a long lateral section,
performing better than the best well previously
drilled using mud motors.
The lateral hole intervals had been traditionally
drilled with motors, achieving ROP of 50 to 70 ft/
hr. Lately, however, rotary steerable systems were
introduced to drill long lateral complex trajectories,
which has resulted in increased ROP. The objective
of this well was to use a TMT powered RSS
to navigate in the best quality of rock while
matching/exceeding the established benchmark
ROP as a minimum.
A TMT powered RSS assembly was used to
drill the 8 1/2-in. lateral section of the well; total
footage drilled with was 4,074ft MD in one run.
Table 1 shows relevant data of the powered RSS
application and presents run data, comparing a
TMT powered RSS to a motor.
The TMT powered RSS drilled in total 4,074 ft
along the shale formation while geosteering and
achieving good quality rock based on formation
evaluation data in real-time. The effective ROP
was more than fourfold compared with the ROP
experienced in offset wells. The improvement of
ROP by using the TMT powered RSS saved 24 hr
of rig time. Fig. 6. shows thecomparison of TMT
powered RSS and best offset mud motor run.
Case History 3—
Middle East Hard Formation
A mature field application in Kuwait required TMT
technology to improve ROP in a hard formation.
The well consisted of build and land sections in an
8 1/2-in. hole sizes, followed by a lateral section in
6 1/8-in. hole size. At the same time, a high degree
of steerability was required because of geologic
uncertainty. TMT technology, along with high build
rate RSS, was chosen for this application.
Figure 5. – Realtime Geological Model Interpretation
In the 8 1/2-in. section, high build rate was required
at landing because of formation tops coming in
high. The required trajectory was achieved with
record ROP in this field, 60 ft/hr average, including
connections and reaming times. A total of 2,500 ft
was drilled building angle from 4 to 88° inclination
in 32.5 drilling hours versus the 3.5 days planned
for the section.
In the 6 1/8-in. lateral section, the assembly
included a TMT powered RSS and LWD tools
including geosteering service to navigate through
the reservoir. The assembly successfully drilled
the reservoir for 1,500 ft, and then steered into the
Figure 6. – Footage and ROP Comparison
7
G EO - PI LO T ® G X T RO T A RY S T EER AB LE SYS T EM F IT -F OR- PURPOSE SOLU TI ON
The matched uniform wall thickness power section powering
a point the bit RSS improved steerability and reduced
inefficiencies. Producing the power and speed as well as
torque closer to the bit results in better steerability and a
better wellbore quality. This led to a record lateral in terms
of ROP.
Drilling efficiency improved as vibration-related damage was
reduced by minimizing stick-slip and by decoupling the LWD
tools from damaging shocks and torsional vibration. Some
vibration was experienced with the TMT powered RSS, mainly
during circulation out of bottom. Fig. 7 shows a comparison of
vibration experienced with both systems.
The TMT powered RSS has been a drilling efficiency stepchange2. The proper planning in the right application can
deliver great benefits for the well construction. Fig. 8 shows
2013 footage and drilling time using TMT technology.
Figure 7. – Stick-slip vibration comparison (TMT powered RSS
vs. downhole motor).
Conclusions
• The TMT powered RSS with improved performance as a result of increased torque capacity
and bit speed and reduction of the stick-slip mechanism has delivered superior performance
and improved ROP in challenging medium and in hard formations.
• TMT wire technology is the most reliable way for a high speed and power communications
between the RSS and the MWD, allowing for BHA design flexibility to accommodate
placement of downhole sensors ahead of the power section.
• A benefit of the TMT powered RSS is that it decouples the BHA, reducing vibration on the
LWD and upper string. This reduces damage and potential NPT while, at the same time,
improving ROP and drilling performance.
• In a vertical drilling application, the TMT powered RSS has delivered maximum
performance, outperforming the benchmark well in the area in comparison to RSS alone or
performance motors.
• The matched uniform wall thickness power section powering a point the bit RSS improves
performance significantly in hard formations and HP/HT applications.
Acknowledgements
Authors
The authors thank the management of
Halliburton for their support of this project
and encouragement to publish this work.
Hernando Jerez
has 21 years of
experience working
with Halliburton. He
has served in multiple
positions including
field hand, operations, engineering and
management. Hernando led Sperry Drilling
operations in Venezuela and Mexico before
moving to Houston where he is now the
Drilling Tools product manager for Sperry.
References
Alvord, C., Noel, B., Galiunas, L. et al. 2007. RSS
Application From Onshore Extended-ReachDevelopment Wells Shows Higher Offshore
Potential. Paper OTC 18975-MS presented at
the Offshore Technology Conference, Houston,
Texas, USA. 30 April–3 May. http://dx.doi.
org/10.4043/18975-MS.
Figure 8. – TMT Powered RSS cumulative footage and
drilling hours.
8
Zimmer, C., Pearson, J., Richter, D. et al. 2010.
Drilling a Better Pair: New Technologies
in SAGD Directional Drilling. Paper SPE/
CSUG 137137 presented at the CSUG/SPE
Canadian Unconventional Resources &
International Petroleum Conference, Calgary,
Alberta, Canada, 19–21 October. http://dx.doi.
org/10.2118/137137-MS.
Jim Tilley is the
global product
manager for rotary
steerable systems
based in Houston,
Texas. He received
his BSc in petroleum engineering from
Texas A&M University. Jim has been
with Sperry Drilling since 1984 starting
in field operations in the Gulf of Mexico
and progressing through technology and
management positions. He has been involved
with rotary steerable systems operations and
management since 2002. Jim is a long-term
active member of SPE.
M A N A G E D PRESSURE D RI LLING B ERG ERMEER GA S S T OR A G E PRO J ECT
Planning Managed Pressure Drilling With
Two-Phase Fluid in a Depleted Reservoir
operation. This paper documents the key planning
considerations required to drill and complete
a highly depleted reservoir using two-phase
MPD techniques.
Martyn Parker, Jelle Wielenga, and Vladimir Bochkarev, TAQA; Isabel Poletzky, SPE,
Mark Juskiw, and Saad Saeed, Halliburton
Introduction
Copyright 2014, SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition
This paper was prepared for presentation at the SPE/IADC Managed Pressure Drilling and Underbalanced Operations
Conference and Exhibition held in Madrid, Spain, 8-9 April 2014.
This paper was selected for presentation by an SPE/IADC program committee following review of information contained in
an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers
or the International Association of Drilling Contractors and are subject to correction by the author(s). The material does not
necessarily reflect any position of the Society of Petroleum Engineers or the International Association of Drilling Contractors,
its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent
of the Society of Petroleum Engineers or the International Association of Drilling Contractors is prohibited. Permission to
reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must
contain conspicuous acknowledgment of SPE/IADC copyright.
Reproduced with permission of the copyright owner. Further reproduction prohibited without permission.
Abstract
The Bergermeer Rotliegend sandstone reservoir has been depleted by production. This has substantially
reduced reservoir pore pressure and well deliverability. Pressure depletion has been accompanied by an
expected decrease in minimum in-situ stress, resulting in a substantially sub-hydrostatic drilling fluid
density being required to enable drilling. As a result, Managed Pressure Drilling (MPD) using two-phase
fluid has been chosen as the enabling technology for drilling and completing initial wells for the Gas
Storage Bergermeer Project.
MPD for the Bergermeer wells is defined as the use of two-phase flow of drilling fluid including
nitrogen injection via a tieback casing to maintain bottom hole pressure (BHP) below the anticipated
reservoir minimum in-situ stress at a long hole depth. Application of MPD technology in the Gas Storage
Bergermeer Project will allow drilling the planned boreholes without exceeding minimum in-situ stress,
minimizing the risks of differential sticking and drilling fluid losses if natural fractures are present.
Reservoir pressure in the Rotliegendes reservoir was originally 238 bar (3451 psi) at 2100 m (6890 ft)
subsea. By mid-2009, gas reinjection was started to bring the reservoir up to an operating pressure of 133
bar for gas storage operations. By May 2013, the time of drilling the 1st of the new gas storage wells into
the Bergermeer reservoir, the formation pressure had been brought up to 81 bar in block 1 and 35 bar in
the adjacent block 2.
Due to permitting restrictions, it was not possible to drill a test/pilot well before drilling the first gas
injection/production wells to physically determine formation rock strength. Therefore a decision was
made to drill into the 81 bar reservoir with a target BHP of 117 to 127 bar; this equated to
an equivalent circulating density (ECD) of 0.57 to 0.63 SG. Two wells were drilled during
May–June 2013, one S-shaped vertical well in block 1 and one horizontal well into block
2. This was achieved maintaining a constant BHP within the predetermined window using
MPD with gasified fluid; in reality it was possible to drill the wells with a very stable BHP
with a 0.6 SG ECD. Dynamic formation integrity tests (FIT) were performed to determine
the formation rock strength in a controlled manner using two-phase MPD techniques at
predetermined depths in the reservoir; results indicated that rock strength was adequate
for using conventional drilling techniques. Despite the successful implementation of MPD,
future wells will be drilled conventionally although MPD could deliver the wells should
the formations turned out to be weak, and it remains as an important contingency in case
formation strength turns out to be weak in future wells.
For the Gas Storage Bergermeer project, significant planning into the overall system design,
equipment selection, techniques, procedures and training lead to an operation where
precise control of the annular pressure profile was achieved and maintained throughout the
The Rotliegendes reservoir is Permian, and
consists of well-sorted, fine-grained Aeolian
sandstones. The average thickness of the reservoir
is approximately 200 m. Porosity is generally high,
ranging from 15 to 30%, and averaging 23%.
Vertically, the best porosities occur in the middle
part of the reservoir, with generally lower porosity
in the upper portion in the Weissliegendes facies.
Horizontal and vertical permeability is generally
high, with 300 and 200 MD, respectively. A number
of thin low-porosity streaks occur throughout the
reservoir. The upper and side reservoir seals are
provided by Zechstein evaporites.
The Weissliegend, the upper formation of the
reservoir, is better cemented but is less permeable
than the Rotliegend, which attributes to greater
rock strength. The formation permeability also
favors the horizontal plane over the vertical.
There are two sections of the reservoir that
slant, therefore the water cut level is below both
formations in the 1st section but traverses up
into the bottom formation Rotliegend in the
2nd section. With these factors in mind, the
1st section wells are planned to be S-shaped and
the wells in the 2nd section will be horizontal in
the stronger Weissliegend.
The Bergermeer Rotliegend sandstone reservoir
has been depleted by production. This has
substantially reduced reservoir pore pressure
and well deliverability. Independent studies into
Figure 1. – Geographic Location (Source: Google Maps).
9
M A N A G E D PRESSURE D RI LLING B ERG ERMEER GA S S T OR A G E PRO J ECT
the field depletion indicated that there was a
high potential for a decline in the minimum insitu (fracture closure) stress in the Rotliegendes
reservoir, requiring sub-hydrostatic ECD
fluids to be used to avoid drilling fluid losses
to the formation.
Uncontrollable mud losses resulting from a mud
with a density such that it cannot adapt to MPD
techniques could result in consequences ranging
from compromising sand face completions, to
complete loss of an expensive wellbore. FITs were
performed, to prove or disprove the possibility
of reservoir stress rebound, and plans for drilling
future wells can be made accordingly.
The location of the wells was in a semi-urban
setting between the towns of Bergen and Alkmaar
requiring extra precautions with regards noise
and light to accommodate the proximity to
the local population and limit disruption to the
environment (Fig. 1).
so that no nitrogen would be pumped down the
drill pipe string. This design also allowed the use
of a Pressure While Drilling (PWD) tool, which
aided in providing early detection of fluid losses.
To achieve stable BHP conditions in a two-phase
MPD system, it was clear that the overall system
would benefit significantly from uninterrupted
injection of both nitrogen and drilling mud. Thus, a
continuous circulation system was used making it
possible to maintain continuous mud pump rates
for the drilling operations from start of reservoir
to TD. The continuous circulating system also
allowed for trips while pumping back into the shoe
with nitrogen injection.
Defining the MPD Parameters
Normally, MPD is thought of as a singlephase system and many would argue that the
introduction of nitrogen, a compressible gas,
to the system reduces the level of control. Past
operations similar to this have been termed as
Low-Head Drilling operations.
Background
The MPD objectives were to drill into the depleted
Bergermeer formations (2100 m to 2200 m TVD)
with a sub-hydrostatic ECD fluid and to maintain a
desired bottom-hole pressure (BHP) between 117
to 127 bar (the fracture reopening pressure). This
required a two-phase mud system, nitrogen and
oil-based mud system, which yielded an ECD of
0.54 to 0.63 SG.
However for the Gas Storage Bergermeer project,
significant planning into the overall system design,
equipment selection, techniques, procedures and
training lead to an operation where precise control
of the annular pressure profile was achieved
and maintained through out the operation.
This paper details this planning process in the
following sections.
It is worth noting that an ultra-low density mud
system using hollow glass spheres had been
evaluated for this project, however field trials in
nearby wells found that a 0.90 SG OBM system
could be reduced to a 0.78 SG density. However,
as a dynamic system, the achievable ECD was 0.90
SG as proven by a field trial in similar nearby well.
While MPD drilling the 8 1/2-in. reservoir sections
in Block 1, or the 6 1/8-in. reservoir laterals in Block
2, nitrogen was added primarily by tieback annulus
injection. Addition of nitrogen resulted in fluid
density reduction such that BHP did not exceed
reservoir minimum in-situ stress. Mud pump rate,
nitrogen injection and the geometry of the bottom
hole assembly (BHA), drill string and ‘A’ annulus
(drill string x liner-tieback annulus or the drill string
x production casing annulus), determined BHP
and hole cleaning parameters.To determine
whether it was possible to use a single-phase
fluid, it was necessary to quantify the change in
reservoir stress. This was most useful if there
were natural fractures in the reservoir—if no
fractures existed, test pressures were not high
enough to initiate fracturing.
Regarding the drilling fluids selected for
drilling the reservoir sections, the drilling mud
that appeared likely to offer the best overall
performance was synthetic oil-based mud (SOBM).
It appeared to have the least impact on formation
damage, and minimized the risk of foaming in a
nitrified mud system.
Formation evaluation was critical for the project,
and historically, two-phase flow has been
detrimental to conventional Measurement While
Drilling (MWD). To maintain a viable MWD
system, a parasitic injection string was designed
10
determine flow combinations of drilling fluids (both
SOBM and water-based mud (WBM)) and nitrogen
gas, in the various possible hole sizes, with a
variety of drill strings, but all aimed at achieving a
maximum BHP of 127.6 bar (1850 psi).
Fluid levels were carefully managed during
tripping, since they were substantially below
surface. Briefly, it was proposed to use a 97 to
131 bar (1400-1900 psi) BHP operational envelope,
as periodic unloading of the ‘A’ annulus was
required on trips in the hole. This 97-131 bar
BHP operational window was also the target for
sand face completion operations. Note initial
assumption was formation pressure of 81bar (1175
psi). It was conventional practice to include a 13.8
bar (200 psi) trip margin. In order to drill and trip
as recommended, the designed MPD operations
cannot proceed past the point where reservoir
pressure rises to 103.4 bar (1500 psi).
Performing FITs was recommended to determine
whether reservoir stresses were changing. With
significant improvement, determinations could
be made as to when use of a single-phase SOBM
would be appropriate. If there is no rebound,
planning should commence for consideration of
stress cage or other drilling fluids, which contain
additives to seal porosity and fractures, which
may allow drilling and other operations at higher
bottom hole pressures.
Basis for MPD Well Design Optimization
Repressurization will bring the reservoir pressure
into the recommended BHP operational envelope
towards the end of the current drilling schedule.
Multiphase simulation runs were made to
MPD design for Bergermeer was based primarily
on the requirement for a maximum of 127.6 bar
(1850 psi) bottomhole circulating pressure and
adequate bottomhole hole cleaning to remove
drilled cuttings from the wellbore.
Initial multiphase simulator runs aimed at simply
achieving the target maximum BHP of 127.6 bar
(1850 psi). Once a combination of mud pump rate
and nitrogen injection arrived at a satisfactory
BHP solution, annular liquid velocity was next
considered. Minimum acceptable annular liquid
velocities of 45.7 m/min (150 ft/min) in vertical and
low-inclination holes, and 54.9 m/min (180 ft/min)
in high-angle and horizontal wellbores are used.
Injecting additional nitrogen had a minor effect
on liquid velocity. Nitrogen’s main influence was
in reducing the effective density of the drilling
fluid. With the low BHP, these wells could
not accommodate higher liquid rates without
exceeding the design pressure limit.
For a constant mud pump rate, annular BHP at
the bit initially decreased as nitrogen gas was
introduced into the system. This hydrostatic
pressure reduction was gradually offset by
increasing fluid flow friction and decreasing liquid
fraction in the fluid. This portion of the curve is
referred to as being ‘hydrostatically dominated’,
and is prone to slug flow.
Computer modelling for Bergermeer indicated
slug flow was going to prevail in most situations,
with (typically) discrete flows of liquid with lower
wellhead pressures, followed by discrete gas flow
and higher wellhead pressures. The MPD manifold
had a programmable choke, which assisted in
maintaining a stabilized wellhead pressure.
Liquid pumping rate was an important factor in
the control and magnitude of the two-phase
BHP. Small changes in pump rate resulted in
significant changes in BHP specifically for the
6.125" hole section in the horizontal wells. It was
also found that the 8.5" sections had a greater
tolerance to change of the mud flow rates.
The effect of a single phase flow on the BHP
clearly demonstrated the importance of using a
continuous circulation system.
Other factors that were considered with respect
to the annular BHP of a circulating system using
tieback nitrogen injection were the drill string
connections. Normal connections involve stopping
circulation, which interrupts the steady state
flow of a two-phase system and cause significant
pressure transients or pressure ‘spikes’. If
conventional connections were made, nitrogen
and the liquid drilling fluid would phase-separate
in the ‘A’ annulus, and a period of circulation
would be required to re-stabilize flows and BHPs
prior to resuming drilling. To avoid this issue
and its associated non-productive time, use of
in-string continuous circulation subs were included
into the plan.
of the injected nitrogen in the circulation fluid. To
account for this complexity, a computer simulator
must be used. For Bergermeer, two-phase
hydraulics modelling simulations were run using
steady state software and the results were then
verified using a transient two-phase hydraulics
simulator. To validate results of the modelling,
data was collected from two-phase flow during a
familiarization period, and this data was analyzed
and used to calibrate the computer modelling.
The steady state multiphase simulator predicts
flow conditions for extended flows at the
nominated rates and the described geometric
and fluid situations. It can predict changes
which may occur in a wellbore if circulation
conditions are changed, but could not predict
the dynamic changes between one circulation
condition and another.
A transient wellbore hydraulics simulator that
has been extensively used for Underbalanced
Drilling (UBD) operations was used, since it is
also a valuable tool when used for MPD operations
when gas injection is required. The physical
and mathematical basis of the transient simulator
enables the user to investigate a wide variety
of problems (both static and dynamic) related to
UBD operations.
In summary, the two-phase hydraulics modelling
simulations indicated that it would be possible
to reduce the hydrostatic of the fluid system
by introducing nitrogen to achieve the desired
operating window. There was an initial slug
related to the start of gas injection in all the
different hole sections for both wells but the effect
on BHP was minimal. While the simulator took
into account this initial start-up condition, the
actual drilling program included a staged pumping
schedule to minimize slugging and pressure spikes
at start up.
Dynamic Simulation of Different
Drilling Events
The modeling performed with the transient
simulator for the 8 1/2-in. hole sections verifies the
operating envelope of the modeling performed
with the steady state software. Again the main
difference between the static modelling and the
more comprehensive dynamic flow modeling is
that effects on flow parameters and pressures can
be seen vs. time rather than just as a snap shot at
a given flow period as per the steady state. These
results were interesting as the slug flow condition
can be reviewed in more detail. These results
showed that after the initial two-phase MPD start
up, the dynamic conditions stabilized in a short
time, thus having the ability to maintain both
nitrogen and mud returns as separate discreet
flow regimes led to a very stable two-phase
system where the effects of slug flow conditions
could be minimized.
Transient wellbore hydraulics software was used
to simulate the entire drilling process, especially
the main events that could result in a BHP being
outside the required operating window. Fig. 2
shows some of the transient simulation results for
one of the two wells, where events such as start
of nitrogen injection, simulated connections with
different times for pump offs to get the surface
survey, and dynamic FIT can be observed.
Use of continuous circulation subs maintained
circulation during connections, keeping BHP
constant. They also avoided pressure variations
associated with re-establishing two-phase
circulation. This also assisted in not worsening any
hole instability which could have developed.
Two-phase Hydraulics Flow Modeling
Two-phase circulation for MPD is complex with no
linear relationships, due to the compressive nature
Figure 2. – Results from the Transient Simulator.
11
M A N A G E D PRESSURE D RI LLING B ERG ERMEER GA S S T OR A G E PRO J ECT
Concentric Nitrogen Injection
The decision was made early in the planning phase
to use concentric nitrogen injection (injection
of nitrogen between the outer casing and a
preinstalled drilling liner) in favor of drill string
nitrogen injection. Drill string nitrogen injection
is considerably more efficient than injection
of nitrogen higher up the well via concentric
casing and although this technique would
have required less nitrogen there are simply
too many disadvantages for using drill string
nitrogen injection.
Due to the Bergermeer wells being designed as
large bore with 9 5/8-in. completions for the high
flow rate gas wells with the need for injection
and production capability, the Bergermeer wells
required the use of a drilling liner to achieve
suitable hole cleaning velocities regardless of
nitrogen injection location.
The disadvantages for drill string injection can be
summarized as follows:
• Injection of nitrogen via the drill string would
have led to the requirement for specialized
MWD tools, EM-MWD (electromagnetic
measurement whilst drilling).
•N
itrogen injection via the drill string would
have complicated the use of continuous
circulating subs.
• Nitrogen injection comingled down the drill
string with drilling mud would have led to high
velocities in the drill string with the potential for
localized erosion of drill string/BHA components.
• Nitrogen injection would have required a change
out of the rotary drilling hose to a nitrogen
compatible one.
The use of concentric nitrogen injection had the
following additional benefits:
• Provided a suitable conduit to inject nitrogen on
a continuous uninterrupted basis.
• Allowed for the installation of a purpose-built
nitrogen injection downhole choke assembly
to ensure that the nitrogen injection point was
always maintained at a suitable differential
pressure to prevent U-tubing from the drilling
annulus to the concentric casing annulus during
MPD operations.
• Allowed for installation of a surface read
out real-time downhole pressure gauge to
control BHP.
• Ensured that the two fluid streams where
separated thus allowing for use of the
continuous circulation subs.
12
The nitrogen injection requirements and
availability were a critical factor in defining the
two-phase MPD requirements. As a part of an
overall system, it was found from the hydraulics
modelling that rates up to 4000 to 5000 scf/min
would be required for concentric nitrogen injection.
Measurement Whilst Drilling (MWD)
BHA Configuration
As previously stated, the MWD section of the BHA
was not subjected to nitrogen flow either from
the inside or the outside of the tools as the MWD
tools were always below the nitrogen injection
point whilst drilling. The main considerations
therefore for MWD/BHA selection essentially
centered on the following points:
• MWD tool selection for reduced mud flow rates.
• MWD tool selection/configuration for minimal
drilling pump rate changes for communication
and downlinks.
• MWD tool porting/restricted orifice to achieve
suitable standpipe pressure and minimize the
effects of U-tubing drill pipe to drilling annulus.
Suitably Applied Surface Back Pressure
To have a suitable degree of control on the BHP, it
was necessary to manipulate the annular pressure
profile (operating window) and this could only
be achieved with a suitably applied surface back
pressure (ASBP).
All adjustable choking devices have a control
range which is referred to as the Cv range (flow
coefficient or flow capacity range). For the twophase MPD planning on Bergermeer, the flow
capacity of the choking devices was a critical
issue that had to be reviewed using specialized
process engineering software. Simply put, the
combined flow of comingled drilling mud and
nitrogen returns had to be controlled by the MPD
automated choke manifolds at very low pressures
of 4 to 14 bar (60 to 200 psi):
• Drilling mud rates required for suitable
hole cleaning and the BHA 950 to 1000 lpm
(250 to 260gpm)
• Nitrogen rates required 4000 to 5000scf/min
• Drilling mud density of 0.9 SG
• Two-phase hydraulics modelling indicated that
the desired ASBP range required would be 4 to
14bar (60 to 200psi).
• A typical 3" MPD drilling choke has a Cv max.
range of 120
The above combination is the worst possible
situation: relatively high comingled flow rate with
a relatively low operating pressure to be controlled
by a proportionally small Cv operating window.
The specialized process engineering software
identified that to control the ASBP with the
required MPD parameters then the throughput of
the system had to be designed so as not to create
surface flowline restriction that would create a
very high surface pressure, yet allow the required
ASBP to achieve the desired MPD BHP drilling
window of 117 to 127 bar.
The process engineering software also identified
that the surface flowlines upstream of the MPD
choke manifolds would have to be 8" flow lines,
and that to use standard 3". MPD chokes, at least
3". MPD chokes in parallel would be needed to
drill 8-1/2" hole section with an ASBP of 4 bar (60
psi); above 7 bar (100 psi), 2 X 3". MPD chokes
would be required.
The large ID flow lines also remained important
to the separation system to be able to run the
MPD 1st stage separator at a minimum operating
pressure of 2 bar (30 psi), required to ship drilling
mud the distance from the separation package to
the rigs header box at an elevation of 4.5 m.
With the contractual requirement for 100% system
redundancy in the MPD chokes this meant that two
full automated MPD choke systems were required.
Description and Application of
Equipment and Processes
In principle, the theory is simple enough. The
drilling hydrostatic is reduced by introducing
nitrogen into the drilling annulus, the volume
of drilling mud removed by the nitrogen is then
controlled by application of ASBP (choking the
return flow from the drilling annulus), to precisely
control the annular pressure profile. A full
underbalanced separation system downstream
of the MPD choke manifolds was used to remove
and safely vent the nitrogen from the drilling
mud. The drilling mud with all nitrogen removed
from solution was then returned back to the rigs
header box for processing as normal i.e., over the
shakers, centrifuges, and then back to the active
mud pits. Fig. 3 shows a simplified MPD twophase equipment overview, and Fig. 4 shows the
rig location.
Some of the main considerations during the up
front planning and engineering were:
• Since MPD drilling procedures deviate
Figure 3. – Two-phase MPD System Overview
significantly from conventional methods, it was required to perform
detailed equipment design reviews, Hazard Identification (HAZID), and
Hazard and Operability (HAZOP) to develop MPD procedures specific
to the MPD equipment being supplied and the MPD operating window
available for the Bergermeer project. These procedures required activities
in addition to conventional procedures to properly manage a dynamic twophase circulation system.
• Development of MPD training courses to familiarize the operator, drilling
contractor, mud loggers, and MWD/DD personnel was performed in the
months leading up to the 1st MPD operation.
• Additionally there was an equipment commissioning, familiarization,
and calibration process scheduled prior to entering the reservoir to
allow function testing of MPD equipment, including a surface control
and separation package, the Rotating Control Device (RCD), and
nitrogen generation unit, to establish baseline monitoring trends
and to train crews.
• An auditable process (NORSOK Z-MC-007) was used to check the MPD
piping, electrical, and instrumentation of the RCD, RCD, separator,
nitrogen, and continuous circulation subs. Each item had an individual
Mechanical Completion Certificate (MCC) used to ensure the equipment
was rigged up, installed, and functioned correctly. All MPD equipment
was signed off as per the MCCs and included all relevant pressure tests.
• The process return lines from the RCD to the MPD manifold were exposed
to flow of a mixed gas-liquid system containing drilled solids. To monitor
for erosion, it was recommended to use an Ultrasonic Thickness (UT)
meter to survey the flow lines periodically. A baseline UT survey was
conducted once the equipment was rigged in, and additional surveys were
performed periodically to monitor for changes in the system.
MPD Equipment
Figure 4. – Rig Location.
The MPD equipment rigged up for the wells included (see Fig. 5):
• Cryogenic Nitrogen Pumping Package
• RCD
• Emergency Shut Down (ESD) valve skids for primary and
secondary flowlines
• 2 x MPD choke manifolds run in parallel
• 1st stage separator c/w pump and piping skid and spare pump
• 2nd stage pressurized knockout vessel
• Coriolis metering skid
• Silenced safe vent
• Data Acquisition System (DAS) for automated ASBP control
• Surface Readout Downhole Gauge (DHG)
Other critical equipment was:
• Continuous circulation sub allowing for continuous circulation
on connections
• Downhole PWD sensor to provide real time at the bit BHP readings
• Downhole nitrogen casing injection valve
Environmental Considerations
During MPD operations, gases from the separation package were conducted
to a vertical vent stack equipped with noise silencer. A fit-for-purpose
silenced, safe nitrogen vent system was designed to specifically meet the
requirement for the Bergermeer MPD project.
Figure 5. – MPD Equipment Set Up.
13
M A N A G E D PRESSURE D RI LLING B ERG ERMEER GA S S T OR A G E PRO J ECT
Well Control
reach TD safely; have no recordable accidents,
no incidents; no major spills;maintain the BHP
within a certain window as per requirements;
test the fracture gradient of the Weissliegend
formation with a dynamic FIT to determine if
the fracture gradient was high enough for future
wells drilled with one less casing string; test the
fracture gradient of the Rotliegend formation with
a dynamic FIT to determine if the formation was
suitable for single-phase drilling; successfully
install the completion assembly while remaining
below fracture pressure and minimize NPT by
reducing drilling problems such as losses and stuck
pipe events.
A consequence of two-phase circulation is a loss
in well monitoring sensitivity. The presence of
compressible two-phase fluids requires trend
monitoring analyses to interpret well status and
identify well control events, as instantaneous
surface parameter readings cannot be used to
interpret well status. Thus, conventional kick
detection methods are no longer valid.
A concentric casing string well profile was
designed for these wells to inject nitrogen at a
fixed point in the annulus in conjunction with a
continuous circulating system for liquid injection
down the drill pipe, all to provide continuous
circulation and maintain a constant BHP
throughout the drilling process.
The exhaust stack was designed to accommodate
the exhaust flow from two distinct streams, a
pressure control valve and a pressure safety valve.
Two noise level requirements were specified,
namely 70 dB(A) at 5 m and 50 dB(A) at 300 m and
the exhaust stack was located at three positions
within the site. It was found that a silencer was
necessary in the exhaust stack to enable both the
noise requirements to be met. It was found that
the noise requirement to meet a sound pressure
level of 70 dB(A) at 5 m from the vent stack was
the governing condition.
nitrogen at a fixed point into the drilling annulus.
This ability for continuous nitrogen injection was
supported by the ability to continuously circulate
drilling mud down the string via subs incorporated
into each stand of the drill string giving an
uninterrupted/separated circulating system for
the two-phases (drilling mud and nitrogen) into
the wellbore.
This design of uninterrupted/separated two-phase
circulation provides the ability to maintain a
constant BHP throughout the drilling process.
The downhole gauge (DHG) was installed
directly above the injection point to provide
real-time measurements of the pressure in the
drilling annulus.
Two wells were drilled using the two-phase
MPD techniques: BGM 24 and BGM 29, and the
corresponding results are summarized in the next
paragraphs.
BGM-24
Fig. 6. details the MPD Operations Matrix
and the actions to be taken by the MPD
supervisor in communication with the driller
who is the designated focal point for all
communication.
A tapered 7-in. x 9 5/8-in. concentric casing string
was designed to facilitate higher velocities for
hole cleaning and as conduit to allow injection of
In a well control situation, no drilling
or injecting of mud and nitrogen will
immediately occur. If a well control
situation develops, then the rig’s
flowline and choke manifold, termed
the secondary flow path, tested to
345 bar (5000 psi) should be used.
The secondary flow path has the rig’s
annular preventer closed and well flow
is routed via the rig choke manifold.
It was recommended to perform an
FIT to determine the BHP the
well could competently hold for
well control purposes.
Prior to MPD operations, a 9 5/8-in.
liner was hung and cemented in the
13 3/8-in. casing with a top of liner (TOL)
at 1640 m MD. The bottom of the liner
was landed in the lower portion of
the Weissliegend shale just above the
Rotliegend at 2069 m MD.
Dynamic FITs were performed at 2090 m
MD successfully testing the Weissliegend
to 1.1 SG ECD for future casing string
requirements.
Results
Dynamic FITs were also performed at 2127
m MD and 2201 m MD in the Rotliegend to
0.87 SG and 1.1 SG respectively. The test
that reached 0.87 SG has been determined
to be inconclusive as the dynamic FIT was
being performed at a faster rate of closure
before letting pressures stabilize.
Since the predicted fracture gradient
of the reservoir was relatively low,
below 0.9SG (7.5 ppg), two-phase MPD
was selected to drill with a reduced
BHP. FITs were used to determine if the
depleted reservoir could withstand a
column of conventional drilling fluid.
The main objectives of the two-phase
MPD were to: drill the wells and
14
BGM-24 was drilled S-shaped with the portion
below 1380 m MD continuing vertical. The
maximum vertical section from the surface position
was 166 m. BGM-24 was drilled vertically
with MPD successfully from 2072 m MD to
TD at 2201 m MD for a total of 129 meters
of open hole.
The well pressures were controlled within
2 bar +/- of the BHP targets, either with
Figure 6. – Bergermeer MPD Operations Matrix.
manual choke operations or automated choke
pressure settings. The average ECD achieved for
drilling this section was 0.61 SG (5.08 ppg).
at 3944 m MD for a total of 567 meters of open
hole. The maximum vertical section from surface
position was 2411.5 m.
At the end of drilling, the MW was down to 0.92
SG and nitrogen injection rates of 4,000 scf/min
were required to maintain BHP in the 117 to
127 bar target window with a mud pump rate
of 950 lpm. At this time it was found that 2 of
the 3-in. power chokes had to be opened to 80%
with a resulting well head pressure of 6-7 bar
(87 to 100 psi).
A 9 5/8-in. liner was hung and cemented in
the 13 3/8-in. casing with a TOL at 2171 m/MD
1796m TVD. Within the 9-5/8 in. liner a second
7 in. liner was landed at 2897 m MD/2091
m TVD. The bottom of the 7-in. liner was landed
in the Weissliegend sandstone at 3376 m
MD/2207 m TVD.
Figs. 7 and 8 show the stable MPD parameters
for pressure and flow which were maintained
through out the reservoir drilling phase. At 13:45
a dynamic FIT was successfully performed to a
1.1 SG equivalent before returning back to MPD
parameters.
BGM-29
BGM-29 was the second well drilled with MPD
and the first horizontal well of the gas storage
project. Prior to MPD the well was kicked off near
surface, built to a 68° angle and held f/ 2000 m
MD t/3044 m MD between 63 and 68°. The well
was kicked off a second time and built to 90° at
3377 m MD. BGM-29 was successfully drilled
horizontally with MPD from 3377 m MD to TD
This well differed from BGM-24 by using a dualstring concentric casing consisting of 2153 m MD
of 9 5/8-in. casing and 744 m MD of 7 in. casing to
stab into the Polished Bore Receptacle PBR at the
top of the 7-in. liner at 2897 m MD. This was done
to get the nitrogen injection point deeper into the
well which was necessary to sufficiently reduce
the BHP when circulating in two-phase drilling
operations. The nitrogen injection choke had been
modified from lessons learnt on well BGM 24 by
having the internal sand screen and the check
valves removed.
Prior to MPD, the well was drilled out
conventionally 3m into the Weissliegend and a FIT
was conducted to 1.15 SG with 0.9 SG MW. After
the FIT, the concentric casing was partly displaced
with nitrogen where a small amount of gas was
channeled into the drilling annulus. A bottoms up
was circulated to the MPD system to remove the
nitrogen and the hole was partly filled to prevent
further channeling.
The SOBM density peaked at 0.97 SG due to the
inability to maintain a 0.9SG OBM with the correct
solids profile during the course of operations ; this
resulted in an upper pressure limit of the MPD
window being extended to 160 bar. Due to the
increase in mud weight, the original target BHP of
117-127 bar was changed to 130-135 bar and MPD
operations were able to maintain the required BHP.
With the CaCO3 profile required for the reservoir,
the mud weight could not be maintained at 0.9 SG
and steadily increased from the accumulation of
fine particles. The mud weight built to 0.94 SG and
gradually rose to a 0.965 SG at TD.
Fig. 9 shows that stable MPD parameters
for pressure and flow were maintained from
approximately 2:00 to 12:00; the 6-in. section was
TD’d at about 20:00. Fig. 10 shows that a dynamic
FIT was successfully performed and the well was
subsequently bled off.
Conclusions
Two wells were
successfully drilled using
MPD techniques with twophase fluid. During drilling,
the BHP was maintained
within the requested limits
at all times. No major
instances of pressure
spiking, loss circulation, or
well kicks occurred.
Figure 7. – Pressure Data MPD Two-phase Operations 11-05-13.
Figure 9. – Pressure Data MPD Two-phase Operations 19-06-13.
Figure 8. – Flow Rate Data MPD Two-phase Operations 11-05-13.
Figure 10. – Pressure Data MPD Two-phase Operations 20-06-13.
Due to the strength of the
final FIT, MPD was not
required for the completion
runs. MPD crews and
equipment remained on
standby until completion
of a conventional FIT was
successfully performed
using the screen
deployment fluid.
For further dynamic FIT
operations prior to the
start, the nitrogen rate
should be lowered to
15
M A N A G E D PRESSURE D RI LLING B ERG ERMEER GA S S T OR A G E PRO J ECT
increase the hydrostatic pressure and reduce the
ASBP on the RCD.
Throughout the operation the minimum
controllable ASBP was maintained to conserve
nitrogen use.
Specific monitoring equipment can greatly assist
in trend monitoring. Trend monitoring of such
variables as surface/down hole annular pressures,
active surface mud volumes, and standpipe
pressures allow reasonable predictions of the twophase circulation system and well control events.
Computer simulations had been performed to
investigate parameters for MPD operations.
A DAS was installed to monitor data throughout
the MPD operations. Information was also
collected by other means, downhole pressures,
borehole diameter and directional information
Acknowledgements
Nomenclature
The authors would like to thank TAQA
for their participation in this project and
for allowing publication of this paper.
They would also like to thank the drilling
contractor and all other contractors and
consultants involved for helping to make this
project a success. The authors would also
like to thank Halliburton Energy Services,
Inc. for their support during the project and
for permission to publish this paper.
ASBP = Applied Surface Back Pressure
BHA = B
ottom Hole Assembly
BHP = Bottom Hole Pressure
BOP = B
low Out Preventer
CCS = C
ontinuous Circulation Sub
Cv = Flow coefficient or flow
capacity range
DAS = Data Acquisition System
DHG = Down Hole Gauge
ECD = Equivalent Circulating Density
ESD = Emergency Shut Down
FIT = Formation Integrity Test
HAZID = Hazard Identification
HAZOP = H
azard and Operability
MCC = M
echanical Completion
Certificate
References
Gas Storage Bergermeer– MPD Basis of
Design. Martyn Parker. 2011
BGM-24 and BGM-29 Drilling Programs.
BGM-24 and BGM-29 End Of Well Reports.
was gathered and transmitted by the MWD tool
in the BHA. Throughout the operation, data was
compared with modelling predictions from the
wellbore hydraulics simulators. In this
way, operational data could be used to assist
in model calibration. Data was also used to
generate trend analyses, necessary to replace
conventional kick monitoring procedures.
MPD = M
anaged Pressure Drilling
MW = M
ud Weight
MWD = M
easurement Whilst Drilling
NPT = N
on-Productive Time
PBR = Polished Bore Receptacle
PLC = P
rogrammable Logic Controller
PWD = P
ressure While Drilling
RCC = R
emote Choke Control Console
RCD = Rotating Control Device
SG = S pecific Gravity
SOBM = Synthetic Oil-based Mud
TVD = T
otal Vertical Depth
TOL = Top of Liner
UBD = Underbalanced Drilling
UT = Ultrasonic Thickness
WBM = Water-based Mud
Authors
Martyn Parker has 25 years
of experience in the oil and gas
industry. Starting his career with
Schlumberger for 12 years working
with in DST and well test, he cross
trained in slick-line and coiled
tubing. In 2000 Martyn joined Precision Drilling as the
underbalanced drilling (UBD) operations coordinator
looking after the Shell Southern North Sea UBD campaign
through to 2005. In 2005 through to 2007 he was seconded
full time to Shell Netherlands as the overall UBD project
manager. In 2007 Martyn joined Halliburton GeoBalance®
services and worked predominantly in Norway on several
managed pressure drilling projects and FEED studies before
leading the technical development of the DONG South Arne
offshore North Sea UBD project. Martyn was involved in
the startup and initial development MPO managed pressure
operations from 2009 thru to 2011.
In 2011 Martyn became a consultant and was employed by
TAQA Energy to lead two-phase MPD for the Bergermeer
Gas Storage project onshore Netherlands. Since the end
of this project in June 2013 he has remained with TAQA
Energy as night drilling supervisor.
16
Isabel Poletzky is the
underbalanced drilling global product
champion for Halliburton Sperry
Drilling’s GeoBalance® services.
She earned BSc and MSc degrees
in petroleum engineering from the
Universidad Nacional de Colombia and the University
of Houston. Isabel has 15 years of industry experience
including drilling and production engineering, directional
and horizontal well planning and design, and 10 years
of experience in underbalanced and managed pressure
drilling applications. She also spent two years working
as a drillsite petroleum engineer on the Kuparuk field for
ConocoPhillips in Alaska.
Isabel’s expertise includes reservoir characterization while
drilling, modeling of multi-phase flow, and candidate
selection for underbalanced and managed pressure drilling
projects. Recent responsibilities have included proposals,
well planning, engineering and design, training, and
coordination of underbalanced and managed pressure
projects worldwide. Isabel has co-instructed several UBD
and MPD courses and has also taught wellbore hydraulics
modeling. She has written and presented several papers
and served on technical program committees for SPE and
IADC. Isabel is a member of SPE and IADC.
Mark Juskiw is a managed
pressure drilling project manager for
Sperry Drilling working worldwide on
various types of MPD projects. Mark
graduated from the University of
Tulsa, Oklahoma in 1982 with a BSc
degree in petroleum engineering.
Saad Saeed is a global technical
advisor for underbalanced and
managed pressure drilling for
Halliburton. Saad graduated with
a degree in petroleum engineering
from the University of New South
Wales in Sydney, Australia. He initially worked extensively
in Well Testing, Data Acquisition, Permanent Gauges and
Production Logging both domestically and internationally.
Having a keen interest in computer science (artificial
intelligence) and its application to the energy industry,
Saad returned to university to get his master’s degree
in computer science. After graduating, Saad joined
Halliburton’s underbalanced and managed pressure drilling
group – GeoBalance® services – in Houston, TX. Since
joining GeoBalance services (over 11 years ago) he has
been involved in all facets of the business from extensive
field engineering and operational support to supervision,
project management, technology development, business
development, and training.
PL A N N I N G A N D EX ECU T ING AN INT ELL IG ENT MUL TIL A T ER AL W ELL
Multilateral TAML Level 4 Junction
Provides Maximum Flexibility for Drilling
and Intelligent Completions
Mohamed Samie, Ahmed Siham and Bruce Gavin/Halliburton
Copyright 2012, Society of Petroleum Engineers
This paper was prepared for presentation at the SPE Kuwait International Petroleum Conference and Exhibition held in Kuwait
City, Kuwait, 10–12 December 2012.
This paper was selected for presentation by an SPE program committee following review of information contained in an abstract
submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject
to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its
officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the
Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300
words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
Reproduced with permission of the copyright owner. Further reproduction prohibited without permission.
Abstract
A multilateral (MLT) well with an advanced intelligent completion string was recently completed in the
Middle East. The well was designed as a “stacked” dual producer in the upper and lower reservoir, and
was drilled using the latest geo-steering techniques to accurately place the wellbore in a highly faulted
and geologically complex structure. Rotary-steerable drilling systems (RSS) were used in several of the
hole sections, along with advanced logging-while-drilling (LWD) tools including multi-pole acoustic,
azimuthal deep resistivity, and resistivity at bit. Encounters with unstable shale and faults made
the drilling difficult, but the decisions made in real-time to navigate the well resulted in a very high
percentage of net pay in both laterals.
This well combined TAML Level 4 multilateral (MLT) technology with passive inflow control devices in the
laterals and an advanced intelligent completion system in the mainbore. The TAML Level 4 multilateral
junction was cemented to isolate unstable shale above the reservoir and to provide zonal isolation from
the lateral completions, which were compartmentalized into stages with proprietary swellable packers
and inflow control devices (ICDs). The intelligent completion was run in the mainbore with two interval
control valves (ICVs) and isolation ball valve (LV ICV) to manage the production from each of the two
Figure 1. – Well B Pre- and post-well geology models.
laterals independently. The ICVs and LV ICV are
controlled hydraulically through four control lines
to surface, which were run in a flat-pack with one
electric line to control a downhole gauge package
for each lateral. Finally, the well was configured
to allow the installation of a large electric
submersible pump (ESP) to be run inside the upper
9 5 /8-in. production tubing.
This project required intensive planning and
coordination for more than a year in advance,
which made the project successful despite the
difficult drilling conditions and resulted in very
little NPT for wellbore construction operations.
This paper will focus on the planning, execution
and lessons learned from the project.
Planning
In the existing horizontal wells in the target
sand reservoir of the target field, premature
water breakthrough caused the water cut trend
to increase within months of production. This
occurred because the reservoir has a very high
permeability sands along with active faults
containing high viscous reservoir fluids.
New technologies were required to overcome the
issue, maximize reservoir contact and enhance a
more uniform oil production from a single location.
Introducing the smart TAML Level-4 MLT well
design to this reservoir along with inflow control
device (ICD), inflow control valve (ICV), isolation
ball valve (LV ICV) and other downhole gauges
proved to be the optimum solution. It also aided
in managing the production and the reservoir
proactively to achieve maximum oil recovery.
Moreover, drilling several laterals from a single
wellbore with the ability to control production
from both laterals had a great economic advantage
because of the optimized cost effective field
management.
These reservoir improvements encouraged the
customer to implement this technology on “Well
A” and “Well B” of the target field and consider
it for further deployment in other fields. Using
the latest in geosteering techniques to accurately
place the wellbore in this highly faulted and
geologically complex structure was essential.
point-the-bit rotary-steerable drilling systems
(RSS) were used in several hole sections including
the 12 ¼-in. build/tangent hole section, the 8 ½-in.
lower lateral L0, the 8 ½-in. build section, and
the 6 1/8-in. upper lateral L1, along with several
advanced logging-while-drilling (LWD) tools. The
RSS enabled continuous rotation for more effective
17
PL A N N I N G A N D EX ECU T ING AN INT ELL IG ENT MUL TIL A T ER AL W ELL
wellbore cleaning as well as producing smoother
hole section due to proprietary point-the-bit design
of the RSS systems selected for this project. The
added value of advanced geo-steering techniques
& practices including pre- and post-well geology
models for Well B is shown in Fig. 1.
The LWD data acquisition program used for
the subject well was designed to cover a broad
range of applications, from using basic gamma
and resistivity data to evaluate shale quality for
the placement of the multilateral junction, to
interpreting the advanced quadro-pole bimodal
acoustic tool data to provide a permeability curve
in near real-time for accurate placement of the
passive ICDs in the lateral completion.
An at-bit resistivity tool was used to provide early
detection of faults and assist in proactive decision
making while geo-steering the wellbore in the
sweet-spot of the thin reservoir. The azimuthally
focused resistivity tool is a laterolog design
that is primarily used to measure the wellbore
ring resistivity in conductive mud; however, it
was successfully applied here in oil-based mud
system to provide a qualitative at-bit resistivity
measurement. The anticipation of faults early
enough was instrumental to allow for steering
decisions to be made at the correct moment
by guiding the well path up or down without
overcorrection, thus minimizing the doglegs
and smoothing the lateral trajectory for easier
installation of the sophisticated completion. A
state of the art geo-steering azimuthal deep
resistivity (ADR) tool was utilized in drilling the
lower 8 ½-in. lateral section and upper
6 1/8-in. lateral section. The tool generates
average resistivity curves with multiple depths
of investigation (DOI), as well as azimuthally
binned resistivity images and geo-steering signal
curves and images with multiple frequencies and
multiple spacings, resulting in multiple DOI ranging
from few inches up to 18 ft into the formation
dependent on the true resistivity. The tool output
integrated with the use of 3D well placement
software provides early geo-steering warning and
accurately calculates the distance and direction to
adjacent bed boundaries.
Estimating the productivity of the laterals
presented a unique challenge in these wells
because the lateral completion was designed with
ICDs that must be adjusted before installation
by selecting the correct nozzle size for the
reservoir quality in each of the swellable-packer
compartments. This required an immediate
interpretation of the permeability in each lateral
within hours of its being drilled so that the ICDs
could be configured accordingly on the rigsite.
With the expected reservoir pressures, pressure
drop across the ICDs, and flow rate from the ESP,
the flow ports in both ICVs were custom designed
to suit the life of the well.
Execution
Figure 2. – Pre-completion reservoir characterization.
With the start of the execution phase, and the
start of drilling the 16-in. build hole section, the
customer held daily meetings in the customer
office where the drilling, geology, and geophysics
teams met with all service companies and
discussed the actual well updates as well
finalizing plans for upcoming phases.
After the 12 ¼-in. build/tangent hole section
was drilled to casing point using dual gamma
ray (DGR)–electro-magnetic wave resistivity
(EWR)– azimuthal litho-density (ALD) in addition
to rotary steerable system with integrated at-bit
inclination/at-bit gamma, two proprietary latch
couplings were installed with the casing tubulars
as shown in Fig. 3.
Figure 3. – Installation schematic for liner and latch couplings.
18
Based on logs and surveys, the placement of the
primary latch coupling was planned carefully to
land just below the Wara formation; this ensured
the junction exit was in the shale to offer proper
isolation. The other latch coupling was placed
80 ft higher for contingency. The latch coupling
is critical to the MLT systems. It is part of a
proprietary advanced reservoir drainage services.
The latch coupling serves a vital role in MLT
applications by providing a consistent, repeatable
platform for the depth and orientation of
multilateral equipment. It also provides full-bore,
unrestricted casing access to the lower mainbore.
The latch coupling maintains casing pressure
integrity, which allows the well to be completed
and produced in any manner, while the option
of drilling an additional lateral bore at
a later date is maintained. The latch
couplings can be installed above or
below existing lateral bores
to provide access to virtually any
productive interval of the reservoir.
Once the main bore was drilled and completed
successfully with ICDs and swellable packers, the
upper lateral phase was initiated. A retrievable
bridge plug was set in the 9 5/8-in. casing just
above the lower completion to prevent any
debris from milling the lateral from falling into
the lower completion and affecting flow from
the ICDs as shown in Fig. 4. To accomplish this,
a window was milled in the casing by anchoring
the milling equipment to the latch coupling,
previously installed and integrated with the
The 8 ½-in. build/landing hole section for the
upper lateral L1 was then drilled using GammaResistivity-Azimuthal Density tools in addition to
at-bit inclination/at-bit gamma integrated on the
rotary steerable system.
Since one of the main requirements of the well
design was to isolate the shale section, the level-4
MLT was the solution. This was accomplished
by running the 7-in. liner to cover the open hole
up to the whipstock tip and then cementing
The latch coupling orientation was
then obtained with measurementwhile-drilling (MWD) in order to offset
the milling equipment and whipstock
precisely to the planned upper lateral
exit at the workshop.
The lower 8 1/2-in. lateral hole
Figure 4. – Drilling and completing the main lateral.
section was then drilled in one run
utilizing gamma ray- deep-reading
resistivity and geo-steering – azimuthal density
casing. A specialized milling machine that allows
– compensated thermal neutron – quad bi-modal
the creation of a near-rectangular window at a
acoustic tool in addition to the proprietary rotary
precise depth and azimuth on a repeatable basis
steerable system with integrated at-bit inclination/ was used as illustrated in Fig. 5. This control of
at-bit gamma. These tools provided real-time
the window geometry and position makes this type
density and gamma borehole images for accurate
of window particularly useful for Level 2 and 4
dip picking, along with directionally sensitive
wells, in which lateral re-entry and through-tubing
resistivity and geo-signal curves, on top of the
re-entry are required. The windows are machined
regular formation evaluation real-time curves.
with an elongated full-gauge aperture along their
Geo-steering specialists watched the real-time
entire length and are exactly in line with the axis
responses from all tools and fed them into the pre- of the casing. The proprietary system eliminates
well model to update the earth model accordingly.
problems associated with conventionally milled
The customer’s drilling and geology teams were
windows in which window geometry is typically
actively monitoring the well data in real-time using elliptical and spiraled. Magnets are also included
a real-time operations (RTO) online connection
in the bottomhole assembly (BHA) for well
which allowed a faster and more comprehensive
cleaning and to capture any metal shavings that
decision making process. Several sub-seismic
the mud was unable to lift to surface. This helps
faults were encountered and picked on the images
ensure integrity of the screens in the mainbore.
After the milling as illustrated in Fig. 6 was
in real-time along with fracture zones. These
faults were not readily visible on seismic images
finished, the milling machine was then pulled out
prior to the start of the drilling operations, due
of the hole. Another dedicated cleanout trip was
to the non-conclusive resolution of the seismic
made with magnets and junk subs for better hole
images. However, these encountered faults did not condition and cleaning.
cause severe challenges in the well placement,
as the lower reservoir unit was thicker than the
The retrievable whipstock was then run and
calculated fault throw which prevented exiting the
seated onto the latch coupling for further drilling
reservoir unit after passing the fault plane.
operations in the upper lateral.
Figure 5. – Run milling machine and mill window.
Figure 6. – Mill-off whipstock.
19
PL A N N I N G A N D EX ECU T ING AN INT ELL IG ENT MUL TIL A T ER AL W ELL
it. The pressure integrity of this junction is
mostly dependent on the cement; therefore the
cementing company introduced specialized cement
which proved to be very efficient in isolation of
the junction zone. It is vital for the successful
completion of the multilateral well that the liner
lands exactly on the whipstock in order to be able
to retrieve the latter. On “Well A”, there were
serious problems getting the liner all the way
to bottom because of the nature of the reactive
shale. The shale was swelling and the liner was
dragging with minimum circulation. This issue was
addressed and a new high torque liner running tool
was introduced on “Well B” in order to have more
tolerance for rotation. After setting and cementing
the liner successfully and cleaning out cement
as illustrated in Fig. 7 & Fig. 8, normal drilling
operations in the upper lateral were continued.
The upper 6 1/8-in. lateral hole section was then
drilled in one run utilizing the same suite of tools
20
run in the lower 8 ½-in. lateral in addition to the
azimuthal focused resistivity AFR tool which was
run in oil-based mud for acquiring at-bit resistivity
measurements. These tools provided the same
real-time formation evaluation curves utilized in
the lower lateral. The upper reservoir unit posed
various challenges to the drilling operations due
to the complex geology of the structure. Several
sub-seismic faults were encountered which were
not previously visible on the seismic image prior to
drilling the well. The nature of the upper reservoir
unit being thinner than the calculated fault
throws, caused multiple exits from the target zone
resulting in a couple of geological side-tracks after
plugging back the zones beyond the fault planes.
Drilling in multiple units before and after fault
planes also imposed further challenges due to mud
weight incompatibility with the non-producing
shaly intervals throughout the borehole, which
caused some tight hole and stuck pipe incidents
in Well “A”. These occurrences were properly
overcome by utilizing different solutions
proposed by the drilling team so that the
lateral section reached the planned geological
targets. The lessons learned were carried over
to Well “B” where stuck pipe incidents were kept
to a minimum.
After the upper 6 1/8-in. lateral was drilled to
total depth (TD) successfully, the ICD completion
was run in lateral as shown in Fig. 9, and the
whipstock with the cemented liner sitting on it
was then retrieved in one run using washover
pipe as shown in Fig. 10. This provided the
option of completing the well with no restriction
in the main bore.
To prove the reliability of the Level-4 multilateral
junction, the client required access to the lateral
to perform stimulation via coiled tubing. A
workover whipstock was run in and latched into
the latch coupling without the need to orient it
Figure 7. – Setting the 7 in. liner.
Figure 8. – Drilling out cement and the 6 1/8-in. lateral.
Figure 9. – Installing the upper lateral completion.
Figure 10. – Whipstock washover and retrieval.
or the use of MWD tools to locate the window.
After successfully exiting through the window, the
workover whipstock was then pulled out again.
The advanced LWD petrophysical data gathered
while drilling the horizontal hole sections of
the MLT well contained several important and
informative indicators that helped engineer the
smart completions design. Permeability from
Stoneley wave energy loss was made quantitative
by calibrating with core permeability data from
the same field (using the Stoneley-perm module
in proprietary analysis software), in addition to
using the sonic compressional and shear slowness
in cross plots with density and resistivity as well
as Compressional/Shear velocities VPVS ratios to
indicate rock quality and deduce any secondary
porosity from the difference in sonic porosity vs.
density porosity. A borehole profile and inferred
hole caliper were provided using the azimuthal
stand-off correction data from the ALD density
image. LWD recorded data was then processed
and analyzed using petrophysical software
packages to finalize the completion string design
as illustrated in Fig. 2.
The significant input for QBAT here was using the
Stoneley-derived permeability to identify zonal
permeability profiles so that the ICD screens
could be nozzled accordingly to achieve uniform
production from all zones across the lateral over
the life span of the well.
This was performed on both the 8 ½-in. lower
lateral (L0) and the 6 1/8-in. upper lateral (L1). Both
ALD and CTN were run in the lower lateral while
ALD only (no CTN) was run in the upper lateral.
By direct comparison, it was found that Stoneleyderived permeability values more closely followed
the chemostratigraphic analysis for cleaner sand
units, in which other permeability empirical
calculations/indications were showing abnormal
behavior. Having several cores cut previously in the
same reservoir/field helped ensure quantitative
permeability figures that are calibrated to
core permeabilities at the applicable intervals
throughout both laterals.
Density porosity was the primary porosity
indicator. Sonic porosity was also provided (Wiley
Calculated) for redundancy and to verify any effect
of secondary porosity not seen by the sonic. In
this case, no apparent secondary porosity was
captured, as all fractures seen were apparently
closed fractures (as seen on density image).
After analyzing the complete formation evaluation
data gathered by the LWD suite in both laterals,
the preliminary completion string design was
agreed among geology, drilling, and completion
specialists to arrive at the best reservoir profiling
and compartmentalization. The design was then
modeled using a simulated BHA that included
collars and stabilizers gauged to match the final
swellable-packers, ICD screens and blank pipes
sequences to ensure that the hole condition and
DLS compatibility allowed the completion strings
to be run successfully to bottom.
Installation of Intelligent Completion
The retrievable bridge plug was retrieved from the
9 5/8-in casing, and well clean-up operations were
conducted in preparation for running the intelligent
completion. The intelligent completion consisted of
the following assembly:
• 2 retrievable feed-through production packers
• 2 dual sensor permanent downhole gauge
systems (tubing and annulus)
• 2 single sensor permanent downhole gauge
systems (tubing)
• 2 multi-position interval control valves (ICV)
• 1 isolation ball valve (LV ICV)
• 1 perforated sub
• 1 ratch latch / seal assembly
• 5 control lines
a) 4 hydraulic
b) 1 electric
• control line protector clamps
were positioned such that the production flow
rate through the upper and lower ICVs could be
estimated through calculation.
Above the uppermost feed-through production
packer, the production tubing was crossed over
from 4 1/2-in. to 9 5/8-in. The four-line hydraulic
control lines, contained in one flatpack, and the
single electric gauge line were held against the
outside of the 4 1/2-in. and 9 5/8-in. tubing using
cross coupling protection clamps. All five lines
were fed through and isolated at the tubing
hanger. The isolation ball valve and both ICVs were
functioned to prove the integrity of the hydraulic
system. The electric gauge line was tested to
confirm the pressure and temperature readings
from all four gauge systems.
The ESP was run inside the 9 5/8-in.
production tubing.
Surface control lines connected to the well head
were run below ground level approx 100 m to the
area where the automated control panel and data
acquisition unit are to be located. The automated
control panel is used to control the ICVs and ball
valve, through field communications system, from
the software in the field control room. Pressure
and temperature data from the permanent
downhole gauges will be viewed in the data
acquisition unit and in the field control room. Final
completion string is illustrated in Fig. 11.
The ratch latch/seal assembly
was tied into the top of the
lower completion in the mother
bore. The retrievable feedthrough production packers were
positioned above and below the
lateral to isolate the production
from the mother bore and the
lateral. The perforated sub and
closed isolation ball valve allowed
produced fluids from the mother
bore to be controlled through
the lower ICV. Production from
the lateral was controlled
though the upper ICV.
The permanent downhole
gauge systems in each zone
Figure 11. – Final completion string design.
21
PL A N N I N G A N D EX ECU T ING AN INT ELL IG ENT MUL TIL A T ER AL W ELL
Lessons Learned
The below captured practices and lessons were
developed during the process of drilling and
completing well “A” and were later carried over to
ensure seamless well delivery in well “B”:
1. Depending on the well profile, the back-up latch
coupling to be placed two casing joints above/
below the planned junction depth.
2. Well clean-up was critical to the success of the
MLT and the completion. A very high percentage
of milled casing was recovered (~150kgs)
3. Drilling off the whipstock with 8 1/2-in. motor
BHA, adjust motor to minimum bend angle and
try to rotate to drill at least 30 ft. Avoid sliding
if possible to minimize dogleg as whipstock
provides ~ 8 deg localized DLS.
4. Running the 7-in. liner through the Wara shale
sections can be problematic. This was solved on
the next well using the high-torque liner running
tool to allow rotation and circulate the liner to
bottom.
5. Latex cement provided excellent junction quality.
Cement volume was good.
6. Fluid loss device/solution required for upper
lateral completions to avoid losses during
washover and clean-out operations. Recommend
a flapper-type of device to be incorporated into
proprietary hydraulic-set seal-bore retrievable
7-in hanging packer assembly.
Conclusion
With careful planning, comprehensive technical
knowledge and collaboration among subject
matter experts, and the effective execution of the
drilling and completions phases of both MLTs, the
final outcome proved to be a huge success for the
client and everyone involved.
Both wells have shown exceedingly high
production levels after the installation of smart
completions strings and confirmed after actual
production verification testing (PVT) logs,
ranging from 50% to 150% improvement in
each individual lateral over regular production
in near-by horizontal wells.
The asset managers as well as the field
development team indicated huge enhancement
in the production levels, and indicated that the
inclusion of smart completions and reservoir
compartmentalization techniques would help
stabilize the saturation levels within the
economical values for an improved recovery curve
and less water cut/water coning effect over a
longer well life span. This would eventually bring a
huge increase in the net present value of the asset
and result in more efficient/economic reservoir
drainage.
It is worth mentioning that the two subject
wells and the promising results achieved have
encouraged the customer to plan many of its
upcoming horizontal wells to be completed using
smart completion strings, as well as to expand
MLT technology usage in all applicable fields.
Authors
Mohamed Samie is the business
development manager for Sperry
Drilling in Northern Gulf, currently
focused on business acquisition
and growth efforts for Sperry’s DD,
LWD, MLT and SDL sub-product
services lines in Kuwait, Qatar and Jordan. Mohamed
joined Halliburton in 2005 as an LWD field professional
in Saudi Arabia. He progressed through field ranks and
held several supervisory and operational roles in Saudi
Arabia, Libya and Kuwait. Mohamed earned his BSc in
computer science with a minor in business administration
from the American University in Cairo. He is a published
SPE author and a contributing member to the Society of
Petrophysicists and Well Log Analysts (SPWLA).
22
Ahmed Siham was a Sperry Drilling multilateral
technology field professional in Saudi Arabia from 2004 to
2012. He is a graduate of Ain Shams University in Cairo
with a BSc in mechanical engineering.
Bruce Gavin is the senior product
manager for Flow Control Products,
Intelligent Completions, based in
Houston, Texas. He received his
HND in mechanical engineering
from Aberdeen Technical College.
Bruce has been with Halliburton since 1993 starting in the
Technology group in Aberdeen, developing Intervention
and Completions equipment. Most recently, he was based
in Dubai as Region BD/Technology manager for Intelligent
Completions, supporting MENA and Eurasia regions for
Intelligent Completions and has recently relocated to
Houston. Bruce is a long-term member of SPE.
E X PLO I T I N G V A S T OI L RESOURCES IN ME XI CO ’ S CH ICO NT EPEC B A SIN
Challenges and Successes in Horizontal
Drilling Shallow 3D Unconventional
Turbidite Reservoir, Mexico
G. Gutierrez Murillo, PEMEX; G. Villanueva Zapata, and E. Medina, Halliburton;
J. Salguero Centeno, CBM E&P
Copyright 2014, Society of Petroleum Engineers
This paper was prepared for presentation at the SPE Latin American and Caribbean Petroleum Engineering Conference held in
Maracaibo, Venezuela, 21–23 May 2014.
This paper was selected for presentation by an SPE program committee following review of information contained in an abstract
submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject
to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its
officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the
Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300
words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
Reproduced with permission of the copyright owner. Further reproduction prohibited without permission.
Abstract
Aggressive plans for exploiting vast oil resources within the Chicontepec basin (Mexico-Poza Rica) are
currently underway. One of the most complex deposits in the
world, this basin is qualified as an unconventional turbidite
reservoir, and one of its characteristics is the existence of
hydrocarbon resources in shallow regions. Horizontal wells
within this basin are extended three-dimensional (3D) wells
in parallel arrangement, suitable for termination techniques,
such as simultaneous multi-fracturing.
Commercially developing these resources requires the
construction of wells that present major challenges. These
challenges can be attributed to low depth, required dog
leg severities close to 8°/30 m, 3D geometry necessary for
construction and horizontal navigation uphill “boomerang”
within the target unconsolidated sand formations (which
are thin and unstable with mechanical hydraulic limitations),
superficial limitation of space, the use of conventional
drilling equipment, and required exhausting analysis.
Based on this scenario, there is a massive plan
for increasing the recovery of unconventional
hydrocarbons in the Chicontepec basin, which is
characterized for having one of the most complex
reservoirs in the world. The average production per
well before applying unconventional techniques
was 28 BOPD, with an average cumulative
production of 30,000 bbl. Currently, production
is up 2,000 BOPD, with cumulative production of
630,000 bbl.
The Paleochanel of Chicontepec is apaleophisiographic elongated unit with a NW-SE
orientation and extends to the subsoil, from Cerro
Azul to Tecolutla cities in Veracruz State, Mexico.
It has an approximate length of 123 km with a
variable width of 25 km to the north and 12 km
to the south, with a surface of approximately
3100 km2 (Fig. 1). Geologically, it belongs to the
province of Tampico-Misantla and is part of the
Chicontepec basin.
Figure 1. – Chicontepec Paleochanel location.
The successful exploitation of these wells was achieved
with thorough planning simulation, detailed engineering analysis, and the selection of appropriate
tools for each operational stage. Monitoring key factors during drilling was essential to helping prevent
problems with uncompacted sands and gas migration.
The use of advanced technology helped reduce deviation from the plan designed for the well and helped
achieve a successful completion using a rotary steerable system (RSS), in some cases from the first
casing, to prevent collapse and initiate the construction of the kickoff point (KOP).
Introduction
The operating company faces significant short and mid-term challenges within the Chicontepec basin,
such as efficient management of primary reservoirs, which are declining, and the substitution of this
declination with unconventional hydrocarbon to sustain production; this requires unconventional drilling
and completion techniques.
The lithological sequence ofthe target zone
includes several interbedded formations from the
top, with approximately 350 m of consolidated
conglomerates associated with light-gray
calcareous soft shales, which also contain
freshwater aquifiers followed by shale layers
that work as seals overlying oil-bearing
sandstones (Fig. 2).
The target sand for the well is the C-50 unit,
this unit is located at a shallow depth. The
vertical depth is approximately of 1091 m, which
was reached and crossed in previousvertical
wells. Potential for exploitation exists despite
its low depth because of narrow thickness and
23
E X PLO I T I N G V A S T OI L RESOURCES IN ME XI CO ’ S CH ICO NT EPEC B A SIN
Figure 2. – (Left) geologic column and 3D horizontal well path image in geological sequence.
inside the target at 1000 m, in a parallel position,
with 150 m of distance between them in the
horizontal section. The effective construction time
per well was 35 operating days with 1.69 days
of non-production time (NPT), which represented
4.8% of the days employed positioning one of
the first unconventional wells with the best
performance in the region. This success allowed
increasing the recovery factor and maximizing
production by reducing drilling of vertical wells in
the region, leading to an overall cost reduction to
the project.
Development
Figure 3. – 3D horizontal path profile of both wells.
unconsolidated sands, although the previous
information gathered suggested uncertainty and
challenges related to drilling horizontal wells.
The wells were designed using 3D displacement
with parallel projection between them, meeting
zipper frac completion requirements (Fig. 3).
During planning, doubts regarding the feasibility
of drilling in such conditions arose related tothe
target depth being low and generation of high
severities reaching 8˚/30 m in an unconsolidated
formation with an unstable background and
constant gasification. Another consideration was
lowering the production liner successfully with
24
sleeves and swellable packer arrangements, which
is key during multifrac completions.
A rigorous engineering procedure was planned,
prioritizing the completions, an accurate selection
of suitable tools for each stage, and data gathering
before drilling. The project had to be completed on
time and within budget. This was accomplished
successfully and the wells were drilled and
completed. The A and B wells reached a vertical
depth of 1091 m true vertical depth (TVD) and 2407
m measured depth (MD). The construction KOP
began at 435 m, with a lateral displacement of
1400 m, maintaining an effective horizontal section
Problem Definition. There were several
challenges during planning of the first two 3D
unconventional horizontal wells, some of which
are listed below.
• Construction severities were demanding (8°/30
m) in these unconsolidated shale formations
affected by a high deviation degree.
• Achieving a successful run into a wellbore with
4 1/2-in. liner, packed with 15 sleeves and 25
swellable packers, with an external diameter of
6.45 in., in a hole of 6 3/4-in. crossing high dog
leg severities (DLSs).
• Running the production liner across unstable
shale formations of the reservoir with constant
gasification prone to fluid loss in a TVD.
• With respect to the path, it was necessary to
keep the tangent with vertical drilling for the
proper adaptation of the artificial lift system
(pneumatic or hydraulic). This led to more
severities.
• Selection of a compatible fluid with the
formations, which were prone to damages
during drilling of the target zone.
• Maintaining optimum stability of the walls in the
horizontal section.
• The achievement of a horizontal section of 1000
m developed in a target sand with a thickness
of 12 mV, 150 m away from its parallel well,
which crossed through and navigated inside
the production target. Complications with
maintaining the “uphill” trend were expected
because this would impede the effective
transmission of drilling parameters, mainly on
the weight of the bit and in the severity of
high torques and poor cleaning of the hole,
among others.
• The conventional core of the horizontal section
was recovered because it was vital information
for wells that were multifractured.
• Another challenge was the little or practically
no experience drilling 3D horizontal wells with
targets displaced from their axis.
Such challenges generated significant uncertainty
related to the technical feasibility of drilling. In this
scenario, the vertical wells that were drilled were
verified and, with the experience gained, a plan
was structured for horizontal wells as follows:
• The target zone is “C-50” located inside the
Tertiary top of Chicontepec formation. There
are high leakoff test values (2 gr/cc) close
to the overburden values in vertical wells
-+crossed through. Although this sandstone with
argillaceous matrix exhibits natural softness, it
tends to close fractures very quickly, which was
experienced during many leakoff tests in nearby
wells. The fracture’s gradient value is 1.99 gr/cc,
therefore events with total lost circulation are
almost non-existent.
• Stuck events caused by differential pressure are
not present at this depth and unlikely to happen.
• The gas delivery behavior in this zone is
constant because the reservoir has light oil
associated with gas; for this reason, the
probability for gasification and/or blowouts
during drilling is high, further maximizing the
horizontal section.
• Stuck events for mechanical effects are possible
because of unconsolidated sands and a threat of
collapsing against the drilling string exists.
• It was determined that the maximum stress for
this zone was oriented to the NE-SW 30°. The
wells were oriented to the minimum stress with
a maximum of 90; this optimized the expected
hydraulic fracturing completion.
Figure 4. – Planning flowchart.
Planning
During this phase, several changes were
made. Previous wells drilled and international
experiences in similar conditions were taken
into consideration for planning the construction
of the well. This scheme was structured
with simulations. The plan for the well was
implemented into an integral drilling program,
which was approved and executed. The planning
process involved a traditional and standard flow
chart, shown in Fig. 4.
the stage and the weight. It was also possible
to define the preliminary arrangement of a
completion with a liner with sleeves and swellable
packers. These results were based on information
from vertical wells including geophysical logs,
diagnostic fracture injection tests (DFITs) and/
or leakoff tests (LOTs), background information
on shales hydration, “breakout” studies, core
analysis, and production tests, etc. The same
analysis was modeled and adapted for the
target zone.
Hole Stability Analysis
Parameters for this Phase
A geomechanical analysis of multiple hydraulic
fracturing and a hole stability study was performed
(Fig. 5). This analysis was vital to defining an
optimum path with a trend favoring the fractures.
This included the selection of drilling fluid per
• The target formation properties are a sand
body with quite argillaceous interbedded with
an average thickness of 40 mV; nevertheless,
the best quality of the rock extends to a limited
thickness of 12 mV, 1.25 gr/cc pore pressure,
Figure 5. – (Left) stress estimation—shear fault “Sh” and safe operational window for mud weight; (right)
minimum mud weight to reach the hole stability in different directions of the well.
25
E X PLO I T I N G V A S T OI L RESOURCES IN ME XI CO ’ S CH ICO NT EPEC B A SIN
TVD of 1090 mV, with the presence of
natural microfractures per zone, with
good oil saturation.
• The formation compressibility ranges from
approximately 5,000 to 10,000 psi, with an
overburden gradient of 2 gr/cc; the difference
between the minimum and maximum horizontal
stress is 0.1 gr/cc and exhibits little influence on
hole stability.
• Inhibition of reactive shales studies showed that
water-based fluid systems (based on polymers)
avoided clay hydration and maintained the
pH within a range of 9.5 to 10.5, minimizing
clay dispersion, and creating optimal polymer
development, which was encapsulated in a
concentration that ranged from 0.5 to 3.5 lts/m3
potassium chloride (KCl).
• For the intermediate and production segments,
an oil-based mud was used to provide better
ROPs and a reliable cleaning tool for the well
and for drilling solids suspension. With this,
the content of solids was reduced from 2 to
4% in the system and allowed the creation of
a “crosslink” system that gels at low speeds,
disperses at high speeds, and can bear water
contamination. This fluid also offers maximum
lubrication, reducing the torque and drag,
and providing exceptional protection against
corrosion. Additionally, it is thermally energy
efficient, stable, and resistant to bacteria.
Well Direction
Several engineering designs were created for the
3D horizontal wells, meeting at least the three
drilling stages of the completion expected. A
combination of hole diameters and well directions
were analyzed, focusing mainly on the severity
required to reach the target and navigate in the
same uphill trend without generating tortuosities
and microtortuosities to help ensure introduction
of the liner.
From the beginning, it was required to generate
high severities with minimum weight because the
extended horizontal section was 1000m with a
limited thickness of 12 mV, in which the directional
work would consume time and technical resources.
Based on this, the best drilling direction was
chosen with a hole combination and coat tubing
14 1/2- × 10 3/4-in., 9 1/2- × 7 5/8-in., and 6 3/4- × 4
1/2-in., obtaining a successful result. This last stage
was for the extended horizontal well. There was a
requirement for landing the well at a TVD of 1090
m; it implied the construction of a shallow KOP
of 435m in the first stage of 14 1/2 in. This led to a
26
constant construction that ranged from 4°/30 m
to a 9 1/2-in. severity stage with a 50°inclination
at 1000 md and 947 mV. The increase of severity
reached 8°/30 m during the lateral displacement
in construction and a drilling at 6 3/4 in. on the
stage where it should land at 90° in a TVD of 1090
m (1577 md) with 12 mV penetration inside the
reservoir. The drilling progress continued with a
horizontal tangent, generating a horizontal section,
an uphill “boomerang,” above 1000 md, which
reached a final depth of 2407 md. The azimuth of
the well was projected at 150°SE. It was based
on a geomechanical model, the same designed to
favor the multi-fracturing programmed for these
wells, in addition to safeguarding the anti-collision
with wells close to the sludge.
The directional path planned versus the actual one
has a phase displacement of 2.65 with a distance
from center to center (Fig. 6). This shows almost
perfect navigation inside the target zone with
high-quality construction of a hole, eliminating the
microtortuosity, almost to a null value, attributed
to the rotatory systems.
Superficial Stage 14 1/2 in. at 410 md
The plan for this stage was to cross the entire
conglomerate, cover the aquifers, and isolate
the high level of vibration of the formation in the
drilling column. The verticality control allowed an
effective directional job during the second stage;
for the vertical control, a conventional motor of
8 in. with high torque, a rotor configuration/stator
of 6/7 × 4 stages
was used in slick
mode with an AKO
graduation of 1.5°
equipped with
measurement while
drilling (MWD)
(inclination and
direction sensors).
The settling point
was at 410m with
a 0º inclination and
an azimuth of 171°.
The navigable
drilling system
was chosen to
control and avoid
collision incidents
with nearby wells
and to minimize
the vibration in the
conglomerate associated with basalt (300m) and
for improving the penetration rate. The bottomhole
assembly (BHA) (Fig. 7) was made up for the first
run with a tricone bit with chiseled inserts of
aggressive cutoff, protecting the caliber because it
was designed to cross through the conglomerate.
For the second run, a replacement was used
with a polycrystalline diamond compact (PDC)
bit of 14 1/2 in. with seven blades and cutters of
13 mm. According to the model, this BHA would
be constructed every 30 sliding m with a 9.4° of
rotation; the tendency was to decrease at 1.2°
approximately 30 m each; nevertheless, it would
vary according to the formation index.
This section was drilled with water-based mud
(KCL polymeric 3.5%) that ranged from 1.17 to 1.30
gr/cc, with a minimum flow of 400 gal/min and
an optimum of 700 gal/min. The total flow area
(TFA) of the bit with 0.92 in2 was 1.37 hydraulic
power (HSI). The plan was to minimize “washing”
and channeling in the conglomerates; meanwhile,
the cleaning was improved with viscous sludge.
Toward the base zone and the settling point, a
lithological change was expected. Shales would
change from a semihard to a hard state with high
hydration; so a 10 3/4 in. J55, 40.5 lbm/ft casing
was placed. The casing was built up with 28
centralizers and a 100% standoff, which helped
achieve excellent centralization in the hole. It
was cemented with a slurry of 1.90 gr/cc with
gas control because of the existence of input
superficial gas in neighboring wells.
Figure 6. – Well path: plan (mode) vs. real mode.
Intermediate Stage of 9 1/2 in. at 1000 md. The
plan for this stage was to reach 1000 md/947 mV
and gain integrity for the next stage. This section
allowed a construction KOP of 435 m and to
continue drilling the well. The severities reached
4.5°/30m, an inclination of 50°, and a trend of
198°, which crossed through the shale layer
(Guayabal formation), which works as a seal
for the reservoir. For the previous work, a
conventional motor with a stabilizing sleeve
of 6 3/4 in. was used as well as a configuration of
6/7 a rotor/stator with a 1.5° AKO equipped with
MWD. The BHA “navigable system” (Fig. 8) had
a 9 1/2-in. PDC bit with five blades with 16-mm
cutters with special characteristics as well as
“back reaming” cutters. The reason for working
with this equipment was the plastic formation,
which can rapidly hydrate causing mechanical
sticking of the BHA and Drillstring.
Figure 7. – BHA components for the 14 1/2-in. stage.
Figure 8. – BHA components for 9 1/2-in. stage.
According to the model, this BHA construction was
of 1.5 at 2°/30m; a rotation in the string ranged
from 90 to 110 rev/min to avoid “whirl” vibration.
The plan for this section was to drill with an oilbased inverse emulsion mud with 1.35 gr/cc, with
a minimum flow of 350 gal/min and an optimum
flow of 470 gal/min. A TFA bit of 1.534 in2 with
0.33 HSI was used. It was planned for improving
the cleaning of the hole, high penetration regimes,
and better directional control with the severities
of this stage. The coat tubing configuration of 7
5/8-in. P110, 29.71 bm/ft BCN had 46 centralizers
with an 80% standoff, cemented with two types of
slurries: 1.60 gr/cc (700 m) and 1.90 gr/cc (300 m)
with gas control at 50% and spacer of 1.50 gr/cc,
to obtain effective sweep and fluid control.
Production Stage 6 3/4 in. (2407 m). The plan for
this final stage was to drill in two segments with
two directional systems, the first one used the
SlickBore® system with a high performance motor
of 4 3/4 in. and 1rev/gal graduated at 1.15° AKO. It
was combined with a PDC bit with a gauge length
of 6 3/4 in., 13-mm cutters, equipped with MWD
and LWD (gamma ray and resistivity in real-time).
The plan for this segment was to continue drilling
the hole with an inclination that ranged from 50 to
90°, and a 150.30° direction in the azimuth with
high severities that can reach 8°/30 m.
The behavior of the model for the BHA (Fig. 7)
ranges from 1.45 to 2.08°/30 m, with a weight of
6 tons over the bit. This showed that, with 30%
of sliding work, the well would land effectively,
without affecting the penetration rate and the
70% left would continue with the rotation.
Another important factor during this stage was
the generation of a high quality hole without
microtortuosities for effective navigation in the
horizontal section. A general example of the
different behaviour of long gauge vs short gauge
bit helping to increase the hole quality on the
wells is shown in Fig. 9.
The drilling parameters for this string ranged
from 90 to 120 rev/min, minimizing the “whirl”
vibration. The weights on the bit were from 6 to 7
ton; rates above this limit would have generated
sinusoidal buckling with an optimum rate ranging
of 220 to 250 gal/min. The plan was to pull out
the SlickBore system at a depth of 1584 m to take
a (9-m) core sample with a conventional tool; this
was the first time this procedure was performed
in this region, taken from the horizontal section at
90° (Fig. 10).
Once landed for the second phase of this
stage, dragging and torque simulations showed
limitation on the weight of the bit, generating
sinusoidal buckling 7 ton over this limit.
Additionally, there was deficient directional
control because of low penetration rates and
high tortuosities. Responding to this situation,
the decision was made to use a continuous
rotatory system (Fig. 11) with a PDC, a 6 3/4-in.
gauge, 13-mm cutters, with a rotatory system
equipped with MWD, LWD (gamma rays and
resistivity), and a PWD sensor in the annular
pressure of the well. This cutting-edge
technology arrangement was used to perform
the navigation according to geologic and
completion requirements. A horizontal navigation
27
E X PLO I T I N G V A S T OI L RESOURCES IN ME XI CO ’ S CH ICO NT EPEC B A SIN
added in case it was necessary to rotate the string
for successful positioning. A special hydraulic
hanger that allows rotation was ready. For this
reason, there was no need of mechanic wedges;
it was anchored along 70m and overlapped inside
the 7 5/8-in. casing. Once it was introduced, the
plan was to leave the inside and the liner annulus
with diesel to provide the swellable packers a
means to reach a maximum seal of (3, 500psi)
(Fig. 12). It was placed on the mouth brine of
1.02gr/cc, leaving it ready for a multistage
hydraulic fracturing process.
Lessons Learned During Stage
14 1/2 in. (410 m)
Figure 9. – Better hole quality with the combination of high-performance motor with an extended
bit caliber.
• The conglomerate was less thick than expected.
• Because this was a highly contrasting formation,
directional strings were necessary during
this stage to help ensure verticality and avoid
collision because of a high deviation tendency.
• Reaming should be a regular practice during the
drilling of each station. Avoid backreaming as
much as possible.
of 1000 m was achieved uphill in a “boomerang,”
with a high-quality hole, which nullified
tortuosities and microtortuosities without carrying
out sliding operations for directional control,
optimizing the penetration rate and reducing time
necessary to take partial surveys.
The plan for this stage was to drill with oilbased mud of 1.38 gr/cc with maximum lubricity,
reducing torque and drag with an optimum rate of
220 gal/min, with a TFA of 1.387 in2, to minimize
“washouts” and maximize the effectiveness of the
cleaning with the help of sludges sent in a tandem;
the work in its entirety was monitored using a
PWD sensor, which also verified the effectiveness
of the cleaning.
Completion Stage. The plan was to finish the
horizontal section with a production liner of 4
1/2-in. N-80, 13.5 lb/ft, a non-cemented HY513,
equipped with sleeves for the multifracturing
and for isolating swellable packers of 6.45 in.
with a hydraulic hanger of 4 1/2- × 7-in. and 13
centralizers. A torque and drag analysis was
performed to lower the arrangement down
successfully. Because it was an unconsolidated
sand body and because of high severities that
appeared in the landing, problems were expected
the moment the arrangement was introduced
effectively in the horizontal section. For this
reason, a rimming shoe with a floating device was
28
Figure 10. – BHA components SlickBore system, loads distribution, and critical rotation simulation
in the column.
Figure 11. – Components of the rotatory drill system (RSS).
• Once the stage is finished, the mud weight
should immediately be increased to 1.45 gr/
cc to help avoid a lack of stability in the high
lithological contrast of this section.
• It is possible to have a 10 3/4-in. casing with a
suitable centralization at this level. Cement
excess should be corrected at 20% values to
obtain an acceptable return.
“boomerang” at an uphill angle. The results
with the rotatory system were excellent, with a
high level of performance behavior in extended
horizontal sections. For this reason, the rotatory
systems must be used during this stage.
• This design provided enough weight for the
rotatory system, which might have been
extremely complex.
Lessons Learned During Stage
9 1/2 in. (1000 m)
Conclusions
• For this section, the motor graduation of 1.5º
AKO was very aggressive, generating an
unnecessary torque and severities above
what was necessary.
• Reaming was not necessary with 1.35 gr/cc
of oil-based mud, this stabilized the well
walls properly.
• At this level, the formation was consistent and
did not show major changes or any disturbance
in the path; the parameters were in optimal
conditions at the end of this section.
• This section provided advantages for optimizing
drilling times.
• Centralization was possible until reaching
70% standoff; adding more centralizers would
generate dragging during the running.
• An excess of 25% in the slurry design was
enough, ensuring its return to the surface.
Lessons learned During Stage
6 3/4 in. (2407 m)
• Difficulties for this section were expected
associated with sandy shale unconsolidated
bodies and constant gasification with a high
degree of deviation and difficulty keeping the
• Parallel horizontal wells were designed
exclusively for the completion discussed. The
operating company was a global pioneer for
completion of this type of well.
• The planning and execution of these operations
were carried out by a multidisciplinary team,
and a new working methodology and drilling
and completion technique was created for wells
in the area. This methodology turned out to be
more effective than planned in terms of reducing
time and costs associated with unconventional
well operations.
• Using cutting-edge technology allowed
completion of wells with reduced deviation in
terms of design and enabled the success of the
completion that was expected.
• The string and bits designs were specific for
these wells and required for this purpose; also,
optimum results were achieved with
high severities.
• The oil-based, solids-free drilling fluid played
a crucial role by reducing torque and drag
levels by 50% in comparison to an oil-based
conventional mud.
• For the first time, a conventional core of the
horizontal section was taken in the region.
• The success of these wells originated from
a detailed simulation planning and detailed
engineering analysis combined with suitable
tools selection for each stage of operating
procedures during drilling.
• The procedures allowed optimization of
the time necessary for drilling this type of
well by 37%.
• The wells were completed within the authorized
times specified by the authorization of
expenditure (AFE), achieving record time
in relation to productivity as well as reduction
to NPT.
This Information is property of PEMEX,
partial or total use are strictly prohibited
without authorization.
Nomenclature
AFE
authorization for expenditure
AKOgraduation bottomhole
motor angle
BHA
bottom hole assembly
DFITdiagnostic fracture
injection test
DLSdegree length severity
every 30m
IADCinternational drilling
contractor
LOT
leakoff test
LWD logging while drilling
MD
measured depth
MWD measurement while drilling
NPT non-productive time
PWD pressure while drilling
ROP rate of penetration
RSS rotatory steerable system
TFA total flow area
TVD true vertical depth
Figure 12. – Hanger liner, sleeve, and swellable packer.
29
E X PLO I T I N G V A S T OI L RESOURCES IN ME XI CO ’ S CH ICO NT EPEC B A SIN
Authors
Guillermo Gutierrez Murillo is
the project implementation leader of
the national program of productivity
in Ku-Maloob-Zaap asset of PEMEX
in Cd. Del Carmen. He has been in
charge of high performance multidisciplinary teams to increase well productivity and has
provided support and follow-up in strategic projects for
the Coordination of Design and for Technical Information
Production Management. He has also participated in the
creation of standards for well completions and evaluations
for pressure tests. Guillermo has 21 years of experience
in the oil industry with a specialty in unconventional
reservoir evaluation. His work as a project leader has
had a high impact in production and best practices
documentation in international and national conferences.
Guillermo received a master degree in reservoir evaluation
and management from Heriot Watt University and a
bachelor degree in petroleum engineering from UNAM. He
has written and presented more than 20 papers in national
and international forums and has participated in the
organization committee of several conferences. Guillermo
is an active member of the SPE, CIPM, AIPM and the
productivity experts’ network of PEMEX.
30
Goldy Villanueva Zapata is from
Bolivia and currently working as
a drilling engineer for Halliburton
Consulting and Project Management
with responsibilities in the Gulf of
Mexico designing and planning HP/
HT ultra-deepwater wells. In Goldy’s previous position he
was in charge of an unconventional drilling well campaign
for Chicontepec, Mexico, where successful performance
increased oil production to a record in this area. Prior to
Halliburton, Goldy was a drilling supervisor engineer for
Petrobras in Brazil and Bolivia. He has 14 years of drilling
and completions experience, including director at YPF
Chaco Petroleum, drilling supervisor, head of exploration
and drilling for YPF Bolivia. Goldy holds a BSc in petroleum
engineering from La Paz-Bolivia USMA University and
MS in finance from the CIFF University of Alcala Henares,
Madrid Spain.
Eber Medina is Pinnacle technical
leader in Mexico and has been
involved in the completion of
unconventional wells in the
Chicontepec basin in Mexico. He
has six years of experience in the
oil industry mainly in the north region in Mexico. Eber
has participated in the design and execution of hydraulic
fractures, matrix stimulations and conformance treatments
in the Chicontepec basin and the Poza Rica Altamira
district and currently is in charge of the stimulation
monitoring operations in Mexico with microseismic and
fiber optics. He is experienced in completion techniques
for multi-fracturing lateral wells. Eber holds a bachelor
degree in chemical engineering from ITCM. He is an active
member of the SPE.
RE A L - T I ME G EOS T EER ING WIT H GABI™ MO TOR
Instrumented Motors Prove Crucial in
Unconventional Well Placement
more than one million feet in lateral sections
for smaller hole sizes. However, a lack of nearbit instrumented motors exists for larger than
4 3/4-in wells.
Anthony Wright and John Snyder, Halliburton
The need for larger instrumented motors to
precisely geosteer in reservoirs prompted the
design of a 6 3/4-in. gamma-at-bit-inclination
sensor (Figure 1). This near-bit instrumented
downhole drilling system was developed to use
not only in the lateral, but also in the curve and
vertical sections before reaching the pay zone.
In addition, this system can assist reservoir
characterization for the most common 6 1/4- to
9 7/8-in production well sizes. The larger-sized tool
further enhances the suite of tools available to not
only help define the curve, but also for choosing
tops in the vertical section. This leads to a shorter
curve radius and assists with determining better
formations in which to kick off, rather than missing
the target formation.
Copyright 2014, IADC/SPE Drilling Conference and Exhibition
This paper was prepared for presentation at the 2014 IADC/SPE Drilling Conference and Exhibition held in Fort Worth, Texas,
USA, 4–6 March 2014.
This paper was selected for presentation by an IADC/SPE program committee following review of information contained in
an abstract submitted by the author(s). Contents of the paper have not been reviewed by the International Association of
Drilling Contractors or the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not
necessarily reflect any position of the International Association of Drilling Contractors or the Society of Petroleum Engineers,
its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent
of the International Association of Drilling Contractors or the Society of Petroleum Engineers is prohibited. Permission to
reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must
contain conspicuous acknowledgment of IADC/SPE copyright.
Reproduced with permission of the copyright owner. Further reproduction prohibited without permission.
Abstract
Near-bit, instrumented motors are a transformative technology used for unconventional well placement.
Near-bit sensors are located closer to the bit compared to traditional measurement while drilling (MWD)
sensors, which are normally >20 ft behind the bit, thus allowing the opportunity for exiting thin bed
formations before a formation change can be observed on the logs. These tools are also instrumental
when choosing the formation tops for each new boundary drilled. The gamma-at-bit-inclination sensor
system provides at-bit azimuthal gamma ray and inclination measurements for improved geosteering and
optimum well placement. This paper describes the geosteering capabilities of a newly released 6 3/4-in.
sensor in different formations.
In a single run, the gamma-at-bit-inclination sensor system successfully delivered a hole section of 4,952
ft (2,248 to 7,200 ft) in 43.5 drilling hr, with an average rate of penetration (ROP) of 114 ft/hr in depleted
shale and sandstone formations on the Gulf of Mexico (GOM) continental shelf, eliminating additional
bottomhole assembly (BHA) changes; a 4,043-ft (7,442 to 11,485 ft) lateral in 23.5 drilling hr with an ROP
of 172 ft/hr in Oklahoma City (OKC), Oklahoma; and 4,781 ft (479 to 5,260 ft) in 37.75 drilling hr at an ROP
of 127 ft/hr in the Woodford shale of the Mississippi Lime, with zero non-productive time (NPT) or health,
safety, and environment (HSE) incidents.
The use of near-bit, instrumented motors allows remaining in the zone of unconventional plays longer. To
date, a total of more than one million feet has been drilled using a smaller near-bit, 4 3/4-in. instrumented
motor, and running with larger-sized tools has proven successful. Instrumented motors previously
had limited drilling application; however, with the geosteering requirements for unconventional well
placement, a greater range of applications for the measurements provided by the near-bit, instrumented
motors has been identified.
Introduction
Precise geosteering requires high-quality tools with azimuthal sensitivity for optimal well placement.
Near-bit, instrumented motors provide near-bit gamma ray with azimuthal sensitivity, and inclination
sensor information. This new generation of motors allows drilling to remain in the sweet spot once
the formation boundaries are defined. These tools are also instrumental for choosing the formation
tops as each new boundary is drilled. Additionally, the benefit created by the capability to azimuthally
log gamma ray sections while sliding eliminates the need to relog a section once it has been drilled
during a slide operation.
A smaller 4 3/4-in. gamma-at-bit-inclination sensor was designed to fulfill the
need for near-bit, instrumented motors (Pitcher et al. 2009; Burinda et al. 2009).
The 4 3/4-in. gamma-at-bit-inclination sensor was the industry’s first real-time
imaging, azimuthal gamma and inclination tool at bit, and has successfully drilled
This paper describes the application of the
6 3/4-in. gamma-at-bit-inclination sensor system
in different formations using geosteering
application. The 6 3/4-in. gamma-at-bit-inclination
sensor system has been run in depleted shale and
sandstone formations on the continental shelf in
GOM, on a lateral section with no concerns of
fault zones in OKC, and the Woodford shale in
the Mississippi Lime.
Tool Configuration and Measurements
The 6 3/4-in. gamma-at-bit-inclination sensor
system consists of two sections. An upper
electronics sub located above the power section of
the mud motor contains the necessary electronics
to support the through motor short-hop telemetry.
The upper electronics sub communicates with
the logging/measurement while drilling (L/MWD)
tool, and provides sufficient memory to store
binned data from the lower electronics sensors.
This design also requires a mechanical connection
to the top of the rotor for signal propagation
(Pitcher et al. 2009).
The lower electronics sub contains four sodium
iodide-thallium [NaI(Tl)] scintillation detectors
mounted 90° radially around the circumference of
Figure 1. – 6 3/4-in. gamma-at-bit-inclination sensor system.
31
RE A L - T I ME G EOS T EER ING WIT H GABI™ MO TOR
the tool, as well as a triaxial inclinometer package
and associated electronics for data acquisition,
processing, and short-hop telemetry. Memory
is also included for data storage. A driveshaft
extension running through the center of the tool
transfers torque from the power section to the drill
bit (Pitcher et al. 2009).
The 6 3/4-in. gamma-at-bit-inclination sensor
is mounted below the power unit of specially
configured motors to deliver real-time feedback
on directional trends and formation changes.
Locating the gamma sensors closer to the bit, and
viewing measurements in all four quadrants of
the wellbore even while sliding the motor, makes
it possible to detect formation changes sooner,
thus eliminating drilling of non-productive footage.
Inclination readings from directly behind the bit
contribute to flatter, longer horizontals and more
accurate well placement. By providing immediate
feedback about unexpected trajectory changes
due to faults, stringers, changes to dip angle, and
T R B L T
T R B L T
Figure 2. – Top, right, bottom, left, top (T – R – B – L – T) quadrant log image.
Figure 3. – Base approach log image.
T R B L T
Figure 4. – Top approach log image.
T R B L T
Figure 5. – Bottom tag log image.
T R B L T
Figure 6. – Top tag log image.
32
T R B L T
Figure 7. – Bottom scrape log image.
other formation related issues, the 6 3/4-in. gammaat-bit-inclination sensor system can ensure the
trajectory is corrected immediately so that the well
remains on target. Figs. 2 through 7 show log
responses of the 6 3/4-in. gamma-at-bit-inclination
sensor system.
Woodford Shale (Mississippi Lime). The 6
3/4-in. gamma-at-bit-inclination sensor system
was used to find the top of a known formation to
accurately core a section in the Woodford shale
of the Mississippi Lime for a vertical exploration
well. The core was to provide valuable information
about this reservoir for use in surrounding wells.
wellbore placement. The 6 3/4-in. gamma-at-bitinclination sensor system is a powerful tool for
drilling long horizontal sections and remaining
in the pay zone for both conventional and
unconventional reservoirs.
In previous wells, the operator drilled passed the
coring point and missed a crucial target zone.
Therefore, the operator desired to drill within 10 ft
of a certain formation and stop to core the section.
This information would be used to better plan
extended-reach wells for this particular reservoir.
To maintain the proper data density to facilitate
the identification of certain formation boundaries,
ROP was slowed near known zones to accurately
select formation identifiers. Once the formations
had been accurately identified, ROP was increased
to improve overall drilling performance efficiency.
The authors acknowledge Jason Pitcher and
Jeremy Greenwood for their insight. The
authors additionally thank Jason LeClair for
providing log responses.
Geosteering Applications
GOM Continental Shelf. A pilot hole in depleted
shale and sandstone formations on the GOM
continental shelf requiring a high-angle build and
hold (>60°) section for a 9 7/8-in. well was drilled.
The job required a high-quality, smooth wellbore
to improve running of liners and completion strings
and avoidance of NPT associated with searching
for a good pay zone. In addition, it was critical to
avoid nearby wells on the pad while drilling.
A 4,952-ft (2,248 to 7,200 ft) hole section was
delivered in a single run, eliminating additional
BHA changes. The pilot well was drilled in 43.5
drilling hr with an average ROP of 114 ft/hr. The
6 3/4-in. gamma-at-bit-inclination sensor system
demonstrated an enhanced capability for landing
the curve.
Inclination and azimuthal gamma readings from
directly behind the bit helped deliver a flatter,
longer horizontal and reduced the reaction time
for making critical geosteering decisions. A
smooth lateral wellbore was precisely positioned
in the pay zone, capturing more of the reservoir,
and overall drilling efficiency was improved by
receiving immediate feedback on any changes in
gamma ray and inclination. Time was saved by
not having to relog sections that were drilled
while sliding.
Midcontinent USA (OKC). The 6 3/4-in. gammaat-bit-inclination sensor system was used on a
lateral in which there were no fault zone concerns.
For this well, the operator did not require the realtime information, but instead desired to evaluate
the recorded data after the job to determine future
use of the 6 3/4-in. gamma-at-bit-inclination sensor
system applications in laterals with known faults.
The services provided were the 6 3/4-in. gamma-atbit-inclination sensor, L/MWD sensors, and drilling
optimization. All services were used to monitor
the drilling performance from the remote operating
center (ROC) located in OKC. A 4,043-ft lateral was
delivered in a single run in 23.5 drilling hr with an
average ROP of 172 ft/hr.
A 4,781-ft (479 to 5,260 ft) lateral was delivered
in a single run in 37.75 drilling hr with an average
ROP of 127 ft/hr. The 6 3/4-in. gamma-at-bitinclination sensor system was instrumental to
finding the top of a zone without drilling too far
into the target formation and potentially exiting
before it was visible on the logs. It was possible
to detect a formation top that had been previously
drilled through with other tools. This allowed for
drilling precisely to the designated total depth (TD)
desired by the operator.
Summary and Conclusion
The 6 3/4-in. gamma-at-bit-inclination sensor
system was successfully used to geosteer
different wells in real-time in GOM, OKC, and the
Mississippi Lime, USA. In all of the applications,
the 6 3/4-in. gamma-at-bit-inclination sensor
system demonstrated zero NPT or HSE incidents.
In addition, there was no need to relog sections
while sliding.
The 6 3/4-in. gamma-at-bit-inclination sensor
system delivers full wellbore coverage, even
in sliding mode, without the need to orient the
motor for up, down, left, and right readings by
providing four independent gamma ray readings
simultaneously in four quadrants around the
tool. Locating the sensors close to the bit makes
it possible to detect adjacent bed boundaries
before exiting the pay zone, and avoid wasting
time drilling non-productive footage. Inclination
readings from directly behind the bit contribute
to flatter, longer horizontals and more accurate
Acknowledgements
References
Burinda, C., Pitcher, J., and Lee, D. 2009.
Geosteering Techniques in Thin Coal Reservoirs.
CSPG CSEG CWLS Convention. Calgary, Alberta,
Canada, 9–13 May.
Pitcher, J., Schafer, D., and Botterell, P. 2009. A
New Azimuthal Gamma at Bit Imaging Tool for
Geosteering Thin Reservoirs. Paper SPE 118328
presented at the SPE/IADC Drilling Conference
and Exhibition, The Netherlands, 17–19 March.
http://dx.doi.org/10.2118/118328-MS.
Authors
Anthony “Tony” Wright began
his career with Halliburton in
2008 in the Sperry Drilling product
service line (PSL) as an L/MWD
field engineer in Alaska. He later
transferred to Gulf of Mexico and
worked offshore. He has work in the Sperry Technology
group as a product engineer, in Operations Technology
as a technical advisor, and his most current role as a
product champion for the Directional Drilling sub-PSL.
Tony honorably served in the United States Navy for six
years aboard the USS Enterprise (CVN-65) as a nuclear
qualified engine room mechanic. He attended Purdue
University for both his bachelor and master degrees in
mechanical engineering. He is currently working on his
professional master of business administration (MBA) at
Rice University, and will graduate in May 2015.
John Snyder is a Sr. PSL manager
for Sperry Drilling’s West Coast
operations. John has more than
30 years of industry experience in
operations, technical and strategic
business leadership roles. A
business and technology professional with experience
in design, manufacturing and application of complex
systems, he is considered a leader in the development
of novel drilling technologies and processes. John holds
a BSc in technology management from the University
of Houston; AS in manufacturing engineering; business
management certificate from the University of Texas; and
attended Halliburton’s business leadership program at
Texas A&M University. He has published and presented
a number of technical papers and articles, has numerous
patents, and is a member of SPE.
33
E N H A N CE D O I L RECO V ERY PRO J EC T MA LA YSIA
Optimized Platform Placement to Cover All
Geological Targets in Baronia Field
M. Anas Sofian, Christophe Leuranguer, and Noor Farhana Musiran,
PETRONAS Carigali; Afiqah Fathiah Ahmad Saifuddin, Thomas Wong, and
Ilen Kardani, Halliburton
Copyright 2014, Offshore Technology Conference
This paper was prepared for presentation at the Offshore Technology Conference Asia held in Kuala Lumpur, Malaysia, 25–28
March 2014.
This paper was selected for presentation by an OTC program committee following review of information contained in an
abstract submitted by the author(s). Contents of the paper have not been reviewed by the Offshore Technology Conference
and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology
Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the
written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an
abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment
of OTC copyright.
Reproduced with permission of the copyright owner. Further reproduction prohibited without permission.
Abstract
Platform placement and sizing are critical steps for enabling subsequent operations, such as well
construction, logistics, and facilities installation to be performed efficiently and safely. This paper
introduces the most economical, yet efficient, solution for an enhanced oil
recovery (EOR) project in which 25 wells were to be drilled in the Baronia
field, offshore Sarawak, Malaysia. Collaborative teamwork from drilling,
reservoir, facility, geology, and production groups was required to develop the
best solutions to minimize construction work, simplify well trajectories, and
use all available resources to help minimize the overall budget. In addition,
this paper evaluates the drillability of each well based on available drilling
technologies and rig capabilities in the market.
During the initial design stage, all 25 wells were planned to be drilled from
two new wellhead platforms (WHPs) to intercept all geological targets.
Major well collision problems were encountered against adjacent wells in
the congested Baronia field; however, after several iterations of surface
nudging and slots designation, all wells were drillable, with a total footage of
227,527.1 ft drilled.
Introduction
The Baronia field is located about 40 km offshore,
northwest (NW) of Lutong, Sarawak, Malaysia, in
block SK15 of the Baram Delta area (Fig. 1). It was
discovered in 1967 (Pratap et al. 2000) by Well
BN-1 and production commenced in May 1972
from two isolated appraisal/development wells,
BN-4 and BN-5. To date, 72 wells have been drilled
in this field. To gain more productivity, horizontal
wells were introduced in the Baronia field some
22 years after its first production. During those
years, horizontal well drilling technology was just
introduced “within the operating company and
the Baronia field was the first to be implemented
(Jadid and Mustapah 2007).
Structurally, the Baronia field is characterized by
a simple, internally faulted, relatively flat, low
relief domal anticline structure elongated toward
the south-southwest (SSW) and the anticline is
resulted from a rollover associated with growth
Figure 1. – Location Map of Baronia field.
The first iteration was performed by placing one new single WHP at an
optimized location and using spare slots and sidetracking from an existing
platform. This optimized design reduced/saved 39,868.61 ft compared to the
initial stage and eliminated the requirement for another new platform. The
second iteration was performed by shifting the new WHP 300 ft closer to
the production platform to enable bridge linking and help reduce construction
work on the pipelines. The total footage to be drilled from this location
was reduced again by 3,622.63 ft. Finally, the setup was further optimized
by equipping the new platform with splitter wells, which reduced the number
of conductor pipes required without decreasing the number of wells to
be drilled.
Overall, the platform placement and sizing optimizations saved USD millions
during the planning stage by eliminating one platform, decreasing drilling
footage, minimizing construction work, and helping reduce health, safety, and
environmental (HSE) risks.
34
Figure 2. – Baronia field spider plot shows four drilling platform (BNDP-A,
BNDP-B, BNDP-I, and BNDP-J) and five jackets (BNJT-C, BNJT-D, BNJT-E,
BNJT-F1, and BNJT-H1).
faulting combined with Pliocene compressional
folding. The main prospective sequences are
comprised of interbeded sandstones and shales
with minor siltstones of Late Miocene (Jadid and
Mustapah 2007).
There are four drilling platforms in the Baronia
field; two 12-slot drilling platforms (BNDP-A and
BNDP-B), two 15-slot drilling platforms (BNDP-I
and BNDP-J), and five 3-slot jackets (BNJT-C,
BNJT-D, BNJT-E, BNJT-F1, and BNJT-H1) (Fig. 2).
The first field development started from the drilling
platform BNDP-A in 1974, and continued to 1979
from a second drilling platform, BNDP-B.
Drillability Criteria
The following criteria are given to ensure that each
well is drillable from a given location and reach
the geological targets as shown in Fig 11:
• Drilling risks
• Anti-collision
• Dogleg severity
• Hydraulic
• Torque and drag
• Rig capability
• Technology availability
• Cost efficiency
A number of significant drillability criteria were
taken into account in the well design for a cost
efficient planning and to alleviate any drilling
risks. Study from the offset wells will give useful
information regarding the drilling problems
which may have happened in the past so that
the mitigation plans can be clearly defined. All
anti-collision risks and mitigation plan should
be lay up in detail and communicate to all parties
during the planning and execution phase. Correct
geographic system, geodetic datum and map
zone need to be established and agreed upon
in order to have an accurate coordinate system.
All anti-collision policies were followed in the
planning stage especially on meeting the criteria
of clearance factor of more than 1.5 and the
sigma value was set to 2.445 as per the operating
company’s requirement. The formula for calculating
the clearance factor ratio is:
Distance between Centres
Distance between Centres - Distance between
Ellipsoids + Combined Casing & Hole Radii
Actual survey and planned trajectories need to be
updated in the database before commencing any
close approach analysis. The anti-collision scans
were run against all wells with wellheads within
15km of the reference well or as per company’s
policy. In this analysis, numbers of iterations
were made to come up with optimum wellbore
trajectory including shifting the targets after
thorough discussions with the subsurface team to
meet anti-collision criteria. All the EOR wells in
Baronia field were planned with clearance factor
of more than 1.5 and anti-collision procedures
were generated and must be adhered to by the
directional drillers offshore.
Dogleg severity (DLS) is defined as the change
in the inclination, and/or azimuth of a borehole,
usually expressed in degrees per 100 feet of
course length. In the metric system, it is usually
expressed in degrees per 30 meters or degrees
per 10 meters of course length. There are various
factors in determining the dogleg severity but
the best practice is to keep it as mild as possible.
However, since the Baronia field is very congested,
some of the wells have to be kept at certain
dogleg severities to avoid collision with proximity
wells and this scenario is called anti-collision DLS.
Excessive DLS will affect the other measurements
such as torque, drag, casing wear, buckling limit,
drillstring sideforces, cyclic fatigue, hole cleaning
efficiency, casing running, and placement of
completion tools.
compression and tension. Total value of the
hook load during pulling out of hole needs to be
calculated and compared against the rig’s hoisting
system.
Moreover, directional drilling hydraulics plays
an important role in determining the drillability
of a well for a successful hole cleaning. Failure
in hole cleaning can cause excessive overpull on
trips, high rotary torque, stuck pipe, hole pack-off,
excessive equivalent circulating density (ECD),
cuttings accumulation, formation breakdown, slow
rate of penetration, and difficulty running logs and
casing. Therefore, it was important that the wells
were simulated to ensure they met the hydraulics
requirements. It was desirable to avoid planning
wells with a tangent section within the critical
hole inclination range, between 45° to 65°. There
were instances that the critical range for hole
cleaning was unable to be avoided, the tangent
section was planned as short as possible instead.
The flow rates were also selected for good hole
cleaning for each hole sections for example 10001200 gallons per minute for 17-1/2” and 12-1/4” hole
sections. Execution of the hydraulics analysis took
into account the rig’s capability in terms of the
mud pump efficiency. It was ensured that the total
stand pipe pressure was limited to the rig’s liner
pump’s availability and the total pressure loss to
provide hydraulics energy to downhole tools were
below the pop-off pressure.
Besides that, the severity of the mechanical
loads imposed on drill string elements namely
All these criteria were optimized to come up with
the torque and drag, tensile strength reduction
the most feasible and cost efficient well designs,
due to bending stress in doglegs need to be
which supported by the available technology in the
considered. The drill string experiences both
market as well as the rig’s capability.
torque and drag since the drill pipe is in rotational
as well as performs
linear motion. Drag is
the increase in string
weight when pulling
out of the hole or the
reduction in string
weight while tripping
in the hole while torque
is the force required
to turn the drill string.
More severe doglegs
will cause higher torque
and drag. Torque and
drag simulation was
performed to ensure the
rig’s drill pipes would
not reach the buckling
limit and tensile strength
Figure 3. – Spider plot shows 25 EOR wells planned from two WHPs, BNIT-A
limit due to excessive
and BNIT-B.
35
E N H A N CE D O I L RECO V ERY PRO J EC T MA LA YSIA
depths to avoid collision. It is imperative to kick off the inner slot wells at the
shallowest depth first, and then progress to the deepest kickoff for the best
option of well dispersion of the outside platform (Fig. 5).
Additionally, full use of four spare conductor slots and two wells sidetracking
from the existing BNDP-J platform was achieved at this stage. Six wells
for targets located southwest of the field were replanned from BNDP-J to
replace the eliminated BNIT-B WHP (Fig. 6).
Figure 4. – 3D view of 25 EOR wells planned from BNIT-A and BNIT-B.
Summary and Findings. Because of more stringent constraints of
directional planning, this exercise triggered several iterations of optimization
cycles between drilling and reservoir engineering, in which “well creaming”
was performed thoroughly to eliminate the low economic value wells. In
addition, horizontal targets were realigned to simplify the well profile.
Five wells were dropped from the initial plan of 25 wells with a very
minimum impact on reserves, and hence improved the overall project
economic tremendously.
Initial Scenario: Two New WHPs. At the initial stage of the project, the
EOR wells were planned from two new wellhead platforms (WHPs), BNIT-A
and BNIT-B, to intercept all geological targets given (Fig. 3). A 3D view of the
25 EOR wells from BNIT-A and BNIT-B is shown in Fig. 4.
Initially, there were 25 wells planned to be drilled from WHPs BNIT-A and
BNIT-B, to consist of the following:
• Oil producer: 11 wells.
• Gas producer: 7 wells.
• Water injector: 6 wells.
• Gas injector: 1 well.
Although major collision problems were experienced within the proximity
wells of this congested Baronia field, after several surface nudging iterations,
effective slots designation, and proper planning, all the wells from these two
platforms were achievable and the total measured depth (MD) was 227,527.11
ft. Further evaluation with respect to a drillability check (torque and drag,
hydraulics, casing, and cementing design) confirmed the feasibility.
Figure 5. – BNIT-A conductor plot shows surface separation by proper
nudging at specific gyro azimuth for all the wells.
Optimized Scenario 1: One New WHP and Use of Four Spare Conductor
Slots from Existing Platform. The new single WHP, BNIT-A, was placed
in one optimized location, which was 2000 ft away. The optimization of the
location of BNIT-A was performed on one centralized platform based on
placement of horizontal drainage; the two outermost horizontal drainage
alignments emphasized two wells to be two-dimensional (2D), while the rest
of the horizontal wells were to be mid to quite severe three-dimensional (3D)
horizontal profiles. Based on a 2000-ft radius to obtain a maximum of 3°/100 ft
dogleg for the horizontal wells, the optimized platform coordinates for BNIT-A
were selected.
The outer conductors’ well designation was performed effectively to kick off
below the shoes at 600 ft MD at 2.3°/100 ft along specific gyro azimuth to
disperse the bottomhole location outside the platform to avoid collision.
With respect to the inner conductors’ well designation, the planning was
performed by true vertical depth (TVD) separation kicking off at different TVD
36
Figure 6. – BNDP-J conductor plot shows four wells are planned from
four spare slots (marked in red) and two wells are sidetracking
from existing wells.
All of the wells again were proven to be achievable with a total MD of
187,658.50 ft. The optimized location and the use of the spare conductor slots
as well as the well creaming exercise saved the total footage by 39,868.61 ft;
this is a massive savings with respect to drilling (Fig. 7). The most significant
outcome from this, however, was the ability to reduce the number of new
WHPs to a single new WHP, hence a significant reduction to facilities costs.
This has potentially saved the overall project (Project CAPEX) approximately
USD 250 million at the conceptual stage.
Optimized Scenario 2: One New WHP at Bridge Linking Location
to Existing Platform BNDP-I. Further optimization work was undertaken
to achieve greater cost savings for the project. The idea was to place the
new platform at a site, which is 300 ft from the existing complex, BNDP-I,
to enable bridge linking (Fig. 8). No live wells were ensured underneath the
proposed location within a safe radius of 150 ft and the wells were set to kick
off deeper, alleviating collision risk.
Figure 7. – Spider plot shows 14 wells are planned from an optimized location of
BNIT-A, and six wells are planned from existing platform, BNDP-J.
At this stage, there were 20 wells planned to be drilled from platforms BNIT-A
and BNDP-J, to consist of the following:
• Oil producer: 5 wells.
• Gas producer: 7 wells.
• Water injector: 7 wells.
• Gas injector: 1 well.
Summary and Findings. This bridging of the platform enabled the operating
company to share platform facilities, such as personnel living quarters, and
achieve significant cost reduction on pipelines, which greatly contributed
to lowering the budget of the overall project (Project CAPEX) as well as
future projects (Project OPEX) (Fig. 9). The total footage to be drilled from
this location was 184,035.90 ft. This, again, further shortened the total MD
by 3622.63 ft. Additionally, significant reduction to project costs of USD 63
million was achieved through this optimization process.
Figure 8. – Plan view shows the shifting of the platform 2700 ft east-south (ES)
for bridgelinking with BNDP-I.
Optimized Scenario 3: Hybrid Platform Design with Splitter Wells at
Four Corners. A more optimized platform design was created to incorporate
a 36-in. dual splitter system, with 2 × 13 3 /8-in. surface casing, to be deployed
with no restriction with regard to the surface casing deviation and kickoff
depth (Fig. 10). The selection of wells for splitters was the first kickoff
below the conductor shoes for wells with higher dogleg and complexity. The
second kickoff was by 200 ft TVD separation. Surface dispersion of wells to
be collision-free was important. Therefore, nudging of all wells for the best
possible kickoff position was imperative.
Summary and Findings. With this hybrid platform design, less conductors
were necessary to be installed while retaining the number of wells. This
significantly reduced time and cost for conductor installation. Additionally, it
left less platform footprint, which enabled the use of a jackup rig instead of a
tender assisted rig; hence, a lighter platform could be designed. The platform
was then renamed BNDP-K.
Conclusion
Figure 9. – Spider plot shows all 20 EOR wells planned in the Baronia field
from BNDP-J and BNIT-A.
The success achieved for this EOR project at the conceptual well planning
stage was largely contributed to a synergy of collaboration between all
parties involved. Early engagement and technical input from specialized
37
E N H A N CE D O I L RECO V ERY PRO J EC T MA LA YSIA
service providers from conceptual planning was vital to put the project on
the correct path during the beginning stage.
The optimized outcome was also a clear example of effective
interdisciplinary teamwork between sections within the project team, such
as drilling, subsurface and surface facilities, for agreement on the best
tradeoffs between tapping the maximum hydrocarbon reserves and the
“drillability” of the options based on sound engineering considerations.
This work involved navigating through a considerable iterative process to
optimize well planning that eventually led to the best optimized case with a
bridge link to a single WHP option (Fig. 11).
Figure 10. – Comparison of the previous platform and splitter wellhead
platform design.
In terms of economic savings associated with these solutions, the reduction
to the number of new WHPs from two platforms to one central platform
as well as enabling a bridge link option demonstrated huge savings to the
overall project (Project CAPEX); an estimated value of approximately USD
315 million was saved compared to the original base case scenario (Fig. 12).
In addition to all of the risk factors being reduced with all these solutions
in place, the net benefits to the operating company have been positive in
terms of financial (CAPEX and OPEX) as well as intangible risk reduction
benefits. The collaboration between different parties with a single common
objective for an economically efficient solution will be the way forward to
achieve such success in the future.
Acknowledgements
The authors thank the management of Petroliam National Berhad
(PETRONAS), PETRONAS Carigali Sdn. Bhd. (PCSB), and Halliburton for
support and permission to publish this paper.
Figure 11. – EOR project flow chart.
References
Pratap, M., Ibrahim, Z.B., and Karim, M.G. 2000. Reservoir Simulation Study
of Baronia Field, Offshore Sarawak, Malaysia Indicates Higher Reserves
and OIIP. Paper SPE 64442 presented at the SPE Asia Pacific Oil and Gas
Conference and Exhibition, Brisbane, Australia, 16–18 October. http://dx.doi.
org/10.2118/64442-MS.
Jadid, M. and Mustapah, M.F. 2007. A Performance Review of 14 Horizontal
Wells in Baronia Field After 12 Years of Production. Paper SPE 107630 presented
at the SPE Latin American & Caribbean Petroleum Engineering Conference,
Buenos Aires, Argentina, 15–18 April. http://dx.doi.org/10.2118/107630-MS.
Nomenclature
EOR = Enhanced oil recovery
WHP = Wellhead platform
TVD = True vertical depth
TVDSS = True vertical depth subsea
Figure 12. – Total reduction of Project CAPEX.
CAPEX = Capital expenditure
OPEX = Operational expenditure
ft = feet
in = inch
DF = Derrick floor
DLS = Dogleg Severity
38
Authors
Noor Farhana Musiran is a well
engineer for Baram Delta & North
Sabah EOR Center (EORC), an
incorporated joint-venture between
PETRONAS and Shell. She graduated
from Universiti Teknologi PETRONAS
(UTP) in 2011 as a holder of BSc (Hons) of petroleum
engineering major in reservoir studies. She has been in
the industry for 2.5 years, focusing on the development
concept of EOR projects since then. This is her paper of
many to come, Inn Syaa Allah.
Afiqah Fathiah Ahmad Saifuddin
is a drilling engineer for JX
Nippon Oil and Gas Exploration
(Deepwater Sabah) Limited. She
holds a first class honors BSc in
chemical engineering from the
Universiti Teknologi Malaysia. She has been in the oil
and gas industry for three years. She started her career
with Halliburton Sperry Drilling services as a well
design engineer where she was involved in a variety
of challenging projects such as the congested Baronia
brown field. This is her first SPE technical paper and she
is looking forward to writing and contributing more to the
industry in future.
Thomas Wong is a technical
advisor for Halliburton Sperry
Drilling in Malaysia. An experienced
oil rigger, Thomas joined SperrySun International as a borehole
survey engineer in 1981, evolving
simultaneously with the oil and gas industry in drilling
technology applications. He is an expert in gyroscopic and
magnetic surveying techniques, passionate in directional
well planning and platform site optimization, and
possesses invaluable experience in measurement-whiledrilling and directional drilling onshore, offshore and in
deep water. He quotes, “Pour into our younger generation
the priceless experience we had and constitute them with
the knowledge to excel”.
Ilen Kardani graduated in 1994
as a petroleum engineer from
Bandung Institute of Technology
(ITB), Indonesia. He has been in the
oil and gas industry for more than 19
years, starting from field operations
as a directional driller (DD). Ilen then moved on to
positions of DD coordinator and operations manager, and
is now focusing on business development and competency
coordinator for Halliburton, Central Asia. One of his
philosophies is to add more value to people, so he likes to
share his experiences by writing papers. Ilen is published
in SPE, OTC, IADC and is becoming a guest lecturer/
speaker for some campuses in Malaysia and Indonesia.
39
AL A S K A F I EL D I MPRO VES D RI LL ING ECO NOM ICS WIT H MP D
Overcoming Extreme Weather Conditions
by Drilling With MPD Offshore in the Arctic
R. Lovorn, D. Lewis, S. Allen, I. Poletzky, Halliburton Energy Services, USA
Copyright 2013 RAO/CIS Offshore.
This paper was prepared for presentation at the RAO/CIS Offshore 2013 (International Conference and Exhibition for
Oil and Gas Resources Development of the Russian Arctic and CIS Continental Shelf) held in St. Petersburg, Russia,
10-13 September 2013.
Reproduced with permission of the copyright owner. Further reproduction prohibited without permission.
Abstract
section of the service and engineering company
that was assisting in delivery of the well were
tasked with finding another drilling method that
would improve drilling efficiency in both the
intermediate and producing phases where lost
circulation and narrow ECD windows were being
experienced.
Upon award of the contract, the operator wanted
to have all associated equipment on this
manmade island in the Arctic to meet a tight barge
shutdown timeline (Fig. 1). This was imperative
due to the weight of the equipment and the fact
Managed Pressure Drilling (MPD) is gaining acceptance as a viable tool for optimizing
drilling and managing bottom hole pressure (BHP) in wells with narrow pressure
margins, unconventional resources, high pressure/high temperature, and harsh
environments. Consequently, an articulate MPD automated system for BHP control
during job execution will ensure successful MPD results in such challenging drilling
environments. Such a system must include the ability to do pre-job planning, have
dependable equipment, and perform with a high level of precision.
In this case, wells were initially drilled conventionally but were not successfully
completed due to drilling problems such as stuck pipe, lost circulation, and the
associated high mud costs which translated into a very costly operation. Initially, the
application of MPD in the intermediate holes and laterals started as a technique to
solve mainly lost circulation problems and differential sticking when traversing both
weak (with high collapse pressures) and highly tectonically stressed formations. The
main objective was to optimize drilling especially in narrow margins to minimize
drilling problems, reduce Non-Productive Time (NPT), and therefore drilling costs.
The automated MPD equipment includes a rotating control device (RCD), a choke
manifold, a back pressure pump (BPP), flow meters, associated surface piping, and the
automated control and data gathering system.
Figure 1. – Resource basins in the Arctic Circle region (Source: U.S.
Geological Survey).
Background
MPD has been defined by IADC as ‘an adaptive drilling process used to precisely control the annular
profile throughout the wellbore. The objectives are to ascertain the downhole pressure environment limits
and to manage the annular pressure profile accordingly’.
that the barge was the only form of transportation
available to move the equipment to the island.
There was also a need to determine what
equipment was necessary to perform the
job in accordance with the guidelines of the
operator and the AOGCC (Alaska Oil and Gas
Conservation Commission).
Introduction
MPD is considered an enabling technology because of the ability to provide accurate and precise
downhole pressure control ‘on demand.’ Nowadays, MPD systems provide the ability to operate in
tight operational envelopes, provide dynamic real-time well-event detection, and control capabilities
while continuing with drilling operations. These abilities give operators access to assets that were
previously considered ‘undrillable’ by either physical or economic limitations. One of the main reasons for
the success of MPD is in the automation features which provide levels of dynamic functional
control and precision that are difficult, if not impossible, for human operators to achieve and maintain.
MPD’s inherent closed-loop setup, coupled with conventional methodology, naturally lends itself to
automated applications.
Early in this project, a large amount of NPT and excess costs were experienced due to the well
conditions. These conditions were affecting the service company’s ability to deliver the proposed wells
with conventional drilling methods. The drilling problems centered on the very narrow equivalent
circulating density (ECD) window, which was approximately 0.7 ppg. On the low end of the ECD window,
hole collapse could result, and on the high end, fluid loss would be a problem. This would negatively
impact the economics of the project and delay the recovery of reserves. Thus, the personnel in the MPD
40
The common reservoir structure for the region
contains two different sand packages and is
highly susceptible to overpressure, under
pressure, and skin damage. The entire structure
is tectonically stressed and contains several
unconformities throughout. This geological
scenario has created a drilling environment that
is prone to losses, bore hole collapse, and NPT
while drilling conventionally. In some formations,
there is only a 0.2 ppg drilling window between
collapse pressures and fracture gradient. To cross
this boundary, a mud weight was designed, which
was statically underbalanced to the collapse
pressure, and automated chokes were used to
maintain a BHP just above the collapse and below
the fracture pressure.
When drilling these wells conventionally, there
was typically a difference of 1 to 1.5 ppg between
the static mud weight (MW) and the ECD. As the
MW was increased for wellbore stability, the
additional increase in ECD resulted in fluid losses
when drilling through the narrowest pressure
windows. The objective was to maintain a
constant BHP by using a lower MW, usually below
collapse pressure, and applying surface back
pressure (SBP) to navigate through the different
pore/collapse pressures, thus eliminating the
pressure cycling experienced during connections.
While drilling the intermediate section, there was
a maximum SBP that could be imposed to avoid
fracturing shallower weaker formations.
installation. Even with all this protection, the lines
have to be blown down when no fluid is flowing in
the lines, if not they will freeze, thus, all lines must
be fitted with blow-down points.
HAZID/HAZOP
The initiation of the first winterized MPD project
brought forward very specific needs based
on the harsh conditions encountered on this
manmade island. With the equipment being
outside of the enclosed rig, spill containment was
one of the highest priorities placed on design
and choice of equipment. Since this was to be
the first Arctic MPD project, a comprehensive,
Equipment Winterization
As this was the first MPD project
to be performed in the Arctic where
temperatures can drop as low as
-70°F, an engineered solution for
winterization of the equipment was
required and had to be developed. A
design consisting of 3 x 20-ft joined
containers was developed with the
30,000 lb. choke manifold fitting in the
center container. This provided storage
and a workshop on opposing sides,
and an ample working area for choke
Figure 2. – Equipment in winterized containers.
maintenance. The RCD with its own
winterized container had a door added
and attached to the choke area, making the entire
step-by-step work method hazard identification
MPD system 20-ft long x 32-ft wide (Fig. 2).
(HAZID) and hazardous operation (HAZOP) was
conducted by a third party. This was to ensure
Large items like the choke manifold had to be
that all aspects of the project scope were covered
placed in the containers so personnel could still
with recommendations to safely and efficiently
work on the equipment as required without being
deliver a successful implementation of the MPD
subject to the cold weather. The containers were
services in these Arctic conditions. To ensure a
installed with two zone-rated air heaters. These
successful campaign, it was necessary to perform
units were set with a temperature differential
simultaneous operations between equipment
of only a few degrees, so if one failed, the other
transportation and building of winterization
would automatically start up to maintain the
containers so that project procedures were
internal temperature. The walls and the bottom
completed prior to the first well scheduled to begin
of the container were also insulated since a high
drilling one month after the deadline for equipment
percentage of the heat would be lost from the
mobilization.
bottom of the container. The containers were
placed on a large skid to facilitate moving around
Once a design was agreed upon, a rig visit was
the location. The Hydraulic Power Unit (HPU)
performed. The rig visit included a review of
for the RCD was installed on the same skid and
equipment placement and a confirmation of tie-in
winterized in the same way. The BPP that fits
points. Potential spill scenarios at all stages of
under the rig floor sub was also the same design
operations were considered with the goal of zero
as the rest of the containers. As outside pipework
spills. It was determined that blowout prevention
also required sufficient protection at all time, flow
(BOP) spill-containment equipment would be
lines were heat-traced, double-wrapped, and then
purchased. A ‘Katch Kan’ spill system was
covered with a waterproof jacket to protect the
sourced and added to the equipment list. This is a
discharge system for drilling and service rigs that
collects fluids for recirculation or proper disposal.
During the rig visit, the equipment was in
transport, and the winterized equipment was
being built by a local vendor; the Anchorage team
was developing detailed procedures. As soon
as the procedures were developed and agreed
upon by both parties, they were integrated into
a comprehensive valve numbering diagram
(VND). This ensured that all rig personnel would
understand the work method and the fluid-flow
process during each task. Once the procedures
and valve numbering diagram were completed,
both the drilling company and
the operator signed off on all
documentation. Any changes to
the procedures required a risk
assessment and a ‘Management of
Change’ (MOC) form.
After the preliminary engineering,
drawings, and equipment selection
was completed, a meeting was
scheduled for all parties involved
with the project to conduct the
HAZID/HAZOP review. The purpose
of this exercise was to thoroughly
investigate all operations and
ascertain the risk matrix was complete
and develop any additional procedures
needed. From the risk matrix, a critical path
timeline was constructed and items were assigned
to relevant companies with close-out dates.
The project would not go operational until all
outstanding items were closed even though some
outstanding items had completion dates up to the
day of commissioning the equipment.
Once the MPD equipment arrived at the service
company yard, a second temporary rig-up was
performed with the equipment installed in the
winterized containers. Four days were dedicated
to equipment testing and all aspects of the
MPD system testing were recorded. The testing
ensured that the MPD system was ready for
Arctic operations.
Upon completion of the testing, the equipment
was broken down and a third party was brought
in to shrink wrap all items in preparation for
the transport to Prudhoe Bay. The equipment
left in time to meet the barge bound to the
island as scheduled.
41
AL A S K A F I EL D I MPRO VES D RI LL ING ECO NOM ICS WIT H MP D
Initial MPD Installation
The compact layout of this manmade island drill
site and the specialized nature of the rig presented
several challenges as well as some advantages in
locating and installing the MPD system.
The drilling equipment consists of a mobile drilling
rig and a fixed rig support complex (RSC). The
rig is a fully enclosed, heated, and self-mobile
unit that was specifically modified to cantilever
the drill floor over closely spaced wellheads in
enclosed well bays, while occupying a minimum
footprint. The rig consists of two modules that
are mounted on walking-beam moving systems.
The sub-base module carries the cantilevered
drill floor, draw works, and derrick with an
enclosed suspended BOP ‘cellar.’ This basic rig
structure is counter-balanced on the off-drill floor
side of the walking beams by the rig powered
diesel electric generators, air compressors, and
heating steam boilers. The three-level service
module carries the rig pumps, the mud pits and
solids separation equipment, power distribution
controls, and the pipe shed. The service module
mates to the sub-base on the off-driller side and
is connected by an enclosed walkway that houses
high- and low-pressure flow lines, power, air, and
communications connections. The RSC houses
a bulk mud-mixing plant, mud-storage tanks, a
cuttings processing mill, and a cement mixing and
pumping facility. The RSC is connected to the rig
via an enclosed pipe rack, which runs the length
of the well bay buildings and carries mud, cement,
drill-water, power, and communication connections
to and from the rig. Depending on rig placement,
the distance of the cement pump to the ROC could
be 500 feet.
The MPD equipment is comprised of five
functionally distinct sub-sets. These are the
RCD, the choke manifold, BPP, flow meters
with associated piping, and the computerized
control system. Consideration of the rig lay out
and the need for freeze protection had significant
impacts on both the sizing and location of the
MPD equipment.
For optimum functionality, the RCD is mounted
directly to the rig BOP. Locating the BOP in the
heated cellar immediately below the drill floor
solved the enclosure issue, but less than 5 feet of
clearance between the spherical and the rotary
table mud box was left. As it was not feasible
to lower the BOP or raise the mud box, a singleelement RCD was specified. Associated high- and
42
low-pressure piping for the RCD was installed
beneath the floor and in the cellar. A suspended
walkway was fabricated to facilitate access to
the RCD from a mezzanine in the cellar. The ‘Katch
Kan’ system was installed and flow hoses were
run from the tray to an overflow container in the
well bay. This container was instrumented for
fluid-level monitoring.
As previously described, the choke manifold was
housed in a set of four containers set on the pad
next to the sub-base unit on the driller’s side,
opposite the service module. Several options for
attaching the containers to the sub-base (so that
they would move integrally with the rig) were
examined. It was decided that these were not as
cost effective as simply disconnecting the choke
house unit for rig moves. Rig electrical power, air
supply, and communications wiring were run to
this enclosure from the sub-base module. Both
high- and low-pressure flow lines connecting the
RCD, the choke, and the mud return flow line were
run through the BOP cellar.
In the early stages of the project, it became
evident that a new remotely controlled BPP could
not be manufactured within the barge season time
window. Various options for existing pumping
units were examined and discarded due to spacing
and winterization problems. Use of the existing
cement pump in the RSC was then investigated.
To maintain the closed loop circulation required for
accurate well flow monitoring, it was necessary
to feed the cement unit from the rig pits. A review
of the existing piping in the rig pits, the pipe rack
flow lines and the RSC mud plant revealed that
the discharge from an existing, but little used,
de-sander pump in the rig pits could be re-routed
through a mud return line to carry mud from the
active system to the mixing plant manifold. From
there, it was possible to rearrange the check
valves to allow this flow to feed the cement pump
suction. Hydraulic calculations were performed to
assure the adequacy of this equipment. Although
the equipment was deemed adequate, a remaining
concern was the need to man the cement pump. In
light of the time constraints and the trial nature of
the MPD project, it was decided to use this option.
The MPD input circulation flow meter was located
upstream of the cement pump suction due to the
long distance between the two. This distance
also necessitated an upgrade of fiber optical
cabling for communications. The pump output was
routed back to the rig cellar via the two-inch highpressure cement line. A tee and isolation valve
was inserted to direct the flow to either the RCD
inlet or a bypass line. This allowed for flushing and
pressure testing of the piping and choke manifold
without pressurizing the RCD, BOP, or wellhead.
Also housed in the cellar were the RCD outlet, HCR
valve, and the low-pressure return mud flow meter.
The constraints on equipment placement resulted
in a final system piping configuration with several
hundred feet of two-, three-, and four-inch highpressure piping and over one hundred feet of
six-inch low-pressure flow line. Approximately
two-thirds of the pipe work was enclosed since it
was inside heated structures and the remaining
third was external to the rig and RSC structures.
These lines were liberally supplied with blow
down ports and electrical heat tracing. They were
insulated with several layers of fiberglass bat
insulation, which was enclosed in a high strength
plastic wind sheath.
The final subsystem to be installed was the
MPD computer-control system. The configuration
selected was to locate the RCD operator’s panel
and the main human-machine-interface (HMI)
servers in the existing MWD/LWD enclosure
located at the rig floor level but external to the
drill floor.
The design concept for the project was to have
fully automated control of the bottomhole
pressure. The HMI interacts with the choke and
the BPP. External system data is received from
the measurement-while-drilling (MWD) log suite
and the rig-pit volume sensor. Internal system
data is received from the choke transducer, choke
position monitor, flow-rate monitor, and other MPD
instrumentation sensors. The cement pump was
manually operated during connections.
Crew Training and Equipment
Functional Check Out
Three levels of training were developed to prepare
the rig personnel for operations and to ensure
seamless conversion from conventional drilling
to MPD operations: Interoffice training for officebased engineers and management; classroom
training on-rig with equipment walk around; and
live training during acceptance test.
Initial preparation for MPD on-site began once
the major components arrived on the barge. The
bulk of the assembly of the MPD choke skid, RCD
hydraulics unit, high- and low-pressure four-inch
flow piping, two-inch high pressure cement pump
piping from the RSC cementing
pump, and the MPD system were
accomplished in September, 2008.
The equipment was left on standby,
when well schedule changes forced
a delayed startup. During September
and October, the drilling crews and
other involved service company
personnel were given training in the
MPD procedures.
Rig-up of the MPD equipment for
use on the first well in the MPD
program was completed in a week.
The 16-in. rig-flow riser air boot was
removed and replaced with a 20-in.
assembly. The suspension tree and
tubing hanger were then removed
from the well. The RCD was
Table 1. Comparison of Conventional vs. MPD wells.
suspended below the floor, and the
BOP was put in place beneath it on
MPD mode. Minor operational issues were
the wellhead riser. The flow lines, Katch Kan, RCD
encountered and these lessons were incorporated
walkway, split master bushings, and trip nipple
in subsequent well procedures.
were installed. While the rig picked up five-inch
drill pipe and began BOP testing, the MPD piping
BPP Installation and Full
was completed, and the heat trace and insulation
operation continued. The RCD and flow lines inside System Integration
Between November 2008 and February 2009,
the rig were also pressure tested. Pressure testing
MPD was successfully used on several
of the choke was completed with no failures.
high-angle intermediate and horizontal
During this interval, the surface casing shoe was
production well sections. Based on continued
drilled out, the well was displaced to sea-water
improvement in the performance of both MPD
mud, and a formation leak-off test was performed.
equipment and personnel, and with consequent
The MPD chokes were then calibrated. The MPD
improvement in project drilling performance,
trip nipple was pulled and replaced by the RCD.
the operator committed to a more permanent
Crew training and MPD acceptance testing was
integration of the MPD system into the rig.
conducted concurrently. MPD began upon drilling
out of the surface casing shoe. Efforts to minimize
The tasks identified were replacement of the
delays impacted by MPD rig up were successful.
cement pump with a permanent, automatically
The bulk of the mechanical and electrical rig-up
controlled BPP, installation of a dedicated pit
was also completed without delays. There were
suction and charge pump, and re-orientation of
delays setting and testing the RCD and associated
the choke manifold and piping to accommodate
equipment due to fine-tuning of the spill tray,
the new pump. Again, timing was critical as the
walkway, and leaks in the RCD piping. A total of 17 winter ice-road season was advancing, and it
critical path hours were consumed in these steps.
was necessary to mobilize the equipment by
An additional 12 hours critical path time was used
truck before mid-April. A constant speed pump
in hands-on crew training in MPD procedures.
with a 200-horse power electric motor and
Thus, the total time added to the rig-up on the
associated controls and skid was fabricated in
first well by the MPD rig-up was 29 hours. Several
Texas and mobilized to location. Meanwhile,
operational and equipment issues presented in the two 8x24-ft shipping containers were modified
rig-up were addressed in subsequent rig-ups and
in Anchorage. These containers were joined to
critical path time has been reduced to less than
house the pump. The initial design concept was to
four hours per rig move.
place the pump on carriers between the sub-base
walking beams. However, this plan was found to
The intermediate hole and production intervals
be impractical due to the height of the pump skid.
of the first well were successfully drilled in
Fortunately, it was found that there was sufficient
clearance, adequate structural capacity, and
moving-system power to suspend the unit beneath
the motor room cantilever. This location was not
optimal in terms of pipe routing but provided
simple access to the rig power.
Analysis of the pit system revealed that an
existing 12-in. pit interconnection line could be
tapped, and a charge pump could be installed in
the existing pump room with little disruption to
existing systems. For simplicity in rig inventory
management, a 3 x 2 x 13-in. centrifugal pump,
identical to others located in the rig mud system,
was selected.
To accommodate the BPP location with minimized
piping runs, the choke manifold was rotated 180°
inside its container. The entire 32- by 20-foot
building was then rotated 90° and brought closer
to the sub base. This reduced the extent of the
choke footprint beyond the sub from more than 40
ft to 24 ft.
External piping was completed with a combination
of fixed and removable sections. It was found
that the initial winterization with heat tracing
and soft insulation was adequate; thus, plans for
permanent hard insulation with metal sheathing
were cancelled.
The final mobilization and installation of the BPP
and full system integration was completed by
late March 2009, nine months after the original
contract award.
43
AL A S K A F I EL D I MPRO VES D RI LL ING ECO NOM ICS WIT H MP D
Results and Conclusions
One of the initial challenges was to have the equipment winterized
and ready for Arctic conditions, and then mobilized in a short period of
time due to the tight barge schedule shutdown. High importance was
also given to spill containment since the equipment was outside of the
enclosed rig. Rigorous and extensive HAZID and HAZOP meetings were
conducted to ensure a safe and successful implementation of MPD.
The results of using MPD in this project have seen a five-fold decrease
in mud cost, and overall improvement in the rate of penetration. More
importantly, MPD has made the field economical. The following is a fivewell comparison, two drilled conventionally and three drilled with MPD.
Thirty more wells have been completed since the first MPD well was
drilled in this manmade island in the Alaskan Arctic and MPD is still in
operation to date. The successful implementation of automated MPD has
resulted in a substantial reduction of cost-per-foot drilled compared to
conventional drilling, by reducing fluid losses, increasing ROP, minimizing
NPT, and efficiently navigating through the narrow pressure margins.
Acknowledgements
The authors wish to thank the management of Halliburton Energy Services for
permission and the encouragement to publish this paper.
References
Bernard, C.J., Lovorn, R., Lewis, D. et al. Managed Pressure Drilling – Automation
Techniques for Horizontal Applications. 2013 AADE National Technical Conference
and Exhibition held at the Cox Convention Center, Oklahoma City, OK, 26-27
February 2013.
Finley, D., Ansah, J., Gil, I. et al. Comparisons of Reservoir Knowledge, Drilling
Benefits and Economic Advantages for Underbalanced and Managed Pressure
Drilling. 2007 IADC/SPE Managed Pressure Drilling and Underbalanced Operations
Conference and Exhibition held in Galveston, Texas, 28-29 March 2007.
Williams, M., Lewis, D. and Bernard, C.J. A Safe Approach to Drilling
Underbalanced Starts with Project Management. 2003 SPE/IADC Middle East
Drilling Technology Conference and Exhibition held in Abu Dhabi, UAE, 20-22
October 2003.
Authors
Randy Lovorn joined Halliburton
in 1978 after graduating from the
University of Mississippi with a
BA in chemistry. Randy began
his career with Baroid Logging
Systems, which today is Sperry
Drilling, starting as a mud logger and then specializing
in drilling optimization. This experience allowed him to
work globally while in the field. From the field Randy then
worked in the development of products such as Real Time
Operation Centers; InSite® and InSite Anywhere® services;
and the Applied Drilling Technology service. Today Randy
is the product champion for Sperry Drilling’s GeoBalance®
service.
Derrick Lewis is the
strategic business manager for
GeoBalance® managed pressure
and underbalanced drilling
operations for Sperry Drilling.
He has published and presented
numerous papers, has several patent awards and has
co-chaired several IADC/SPE technical forums.
44
Stan Allen is MPD coordinator
for GeoBalance® managed
pressure drilling operations for
Sperry Drilling in Alaska. He has
been involved in the SPE paper
Overcoming Extreme Weather
Conditions, Drilling Offshore with Managed Pressure
Drilling in Arctic Conditions.
Isabel Poletzky is the
underbalanced drilling global
product champion for Halliburton
Sperry Drilling’s GeoBalance®
services. She earned BSc and MSc
degrees in petroleum engineering
from the Universidad Nacional de Colombia and the
University of Houston. Isabel has 15 years of industry
experience including drilling and production engineering,
directional and horizontal well planning and design, and
10 years of experience in underbalanced and managed
pressure drilling applications. She also spent two years
working as a drillsite petroleum engineer on the Kuparuk
field for ConocoPhillips in Alaska.
Isabel’s expertise includes reservoir characterization while
drilling, modeling of multi-phase flow, and candidate
selection for underbalanced and managed pressure drilling
projects. Recent responsibilities have included proposals,
well planning, engineering and design, training, and
coordination of underbalanced and managed pressure
projects worldwide. Isabel has co-instructed several UBD
and MPD courses and has also taught wellbore hydraulics
modeling. She has written and presented several papers
and served on technical program committees for SPE and
IADC. Isabel is a member of SPE and IADC.
M I LLR I T E ® SYS T EM PREM I UM REPL A CEME NT F OR CO NVE NTI O NAL M ILL ING
Are You on the Right Track with Casing
Milling? Innovative Precision-Milled
Windows Offer Improved Casing
Exit Reliability for Sidetracking and
Multilateral Completions
Calvin Ponton, Justin Roberts, Steven Fipke and Andy Cuthbert, Halliburton, SPE
Copyright 2010, IADC/SPE Drilling Conference and Exhibition
This paper was prepared for presentation at the 2010 IADC/SPE Drilling Conference and Exhibition held in New Orleans,
Louisiana, USA, 2–4 February 2010.
This paper was selected for presentation by an IADC/SPE program committee following review of information contained in
an abstract submitted by the author(s). Contents of the paper have not been reviewed by the International Association of
Drilling Contractors or the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not
necessarily reflect any position of the International Association of Drilling Contractors or the Society of Petroleum Engineers,
its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent
of the International Association of Drilling Contractors or the Society of Petroleum Engineers is prohibited. Permission to
reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must
contain conspicuous acknowledgment of IADC/SPE copyright.
Reproduced with permission of the copyright owner. Further reproduction prohibited without permission.
Abstract
Multilateral wells offer many benefits over conventional wells, including reduced overall drilling costs,
lower environmental effect, increased total recovery, greater access to production intervals, and
subsequently improved well production rates. However, it can be difficult to achieve a good quality
casing window through which an additional lateral branch can be successfully drilled and completed.
As bottomhole assemblies (BHAs) become more advanced, involving longer and stiffer strings of tools,
and as completion design becomes more intricate, more attention must be given to the way the casing
window is created because this is the foundation of multilateral well design. Track-guided milling
systems have emerged as effective and accurate methods by which to control casing window geometry,
and this paper will focus on recent advances in track-guided, precision window milling technology and its
effect on multilateral well design.
To avoid potential problems in running drilling assemblies or liner/completion strings, advanced milling
technology should be used to create the casing window. During conventional milling, it is commonly
difficult to control the action of the mill as it cuts through the casing; poor control creates a casing
window that could, as a result of right hand rotation during milling, rolling-off to one side, leading to
a skewed or shortened aperture. Uncontrolled and undefined window geometry introduces additional
risks when re-entering a lateral wellbore, such as nonproductive time (NPT) and equipment damage. A
good quality casing window, with precisely controlled length and width, helps ensure that drilling and
completion equipment can exit the aperture without problems and facilitates repeatable re-entry access
to both the mainbore and the laterals in future interventions. The quality of the casing window is just as
critical in multilateral wells as in conventional sidetracking or whipstock operations.
Advances in modern casing milling technology are pioneering improved multilateral well
designs. Multilateral wellbore junctions can now be placed in deep, high-angle wells without
compromising drilling or completion operations by using a track-guided milling system to create
improved casing windows.
Historical Background
What distinguishes a multilateral well from a simple sidetrack is the abilities to access both the mainbore
and the lateral and to produce from both, either separately or by co-mingling. The different types of
junction created can be defined by using the TAML
categories Levels 1 through 6. The traditional
method that was used to open a window in casing
has been accepted as an industry standard since
the practice began. Improvements in both the
design of mills and the whipstocks from which
they exit from have improved, but the basic
procedure has changed little over the years.
The assembly commonly used to mill a casing
window consists of a window mill behind which a
string or watermelon mill is run. The second mill
preferably presents a cross-section that is curved
and rectangular, thereby producing a substantially
flat center segment and arcuately curved end
sections. The assembly is stiff but necessary to
ensure that some measure of control is exerted
on the assembly and to replicate the drilling BHA
which will be subsequently run. The earliest
method used a starter mill to initiate the cut in
the casing which the window mill exploited in a
subsequent run; after improvements in window
mill design, however, this technique is no longer
required and an additional starter mill run is
no longer needed. The operation of milling the
window can last from several hours to several
days. The early designs suffered through either
lack of sufficient cutting structure on the mill or
a poorly engineered design, with the result that
the whipstock was milled up rather than the
steel of the casing that it was supposed to exit.
The current round nose and radial ground
designs makes it virtually impossible to mill up
the whipstock.
The current designs incorporate a variety of
cutting mediums, from thermally stable 3/8-in. to
¼-in. thick tungsten carbide inserts mounted to a
brass matrix by brazing, to diamond impregnated
mills. Some mills incorporate a metal-ceramic
composition reinforced by alloy plates that
enable high-speed milling and single or multiple
milling profiles, depending on the application.
The geometric disposition of blades on which the
cutting structure is mounted has an angular offset
with respect to the tool longitudinal axis, usually in
the range of 1° to 10° with an abutment of cutters
arranged in the direction of rotation of the mill.
Because the mill design necessarily relies on sidecutting forces, the concentration of the cutting
structure is on the flanks or gauge of the mill.
Because the primary function of the mill is to cut
through the steel of the casing, very little attention
was paid to the cutting structure on the nose of
45
M I LLR I T E ® SYS T EM PREM I UM REPL A CEME NT F OR CO NVE NTI O NAL M ILL ING
the mill. The nose was sufficient to begin the cut,
but otherwise ineffective when the gauge began
to contact the steel. More modern PDC designs
have evolved to drill enough openhole (rathole)
into the formation to allow for the length of some
rotary steerable tools, in particular the push-the-bit
systems, to exit far enough into the surrounding
formation to function as intended. Whichever
milling system is deployed, the aperture is always
drifted to ensure that the correct gauge of exit has
been constructed; this leads, however, to a false
impression that a long enough gauged section has
been created.
Maintaining Window and
Hole Geometry
The side forces imparted to the window mill by the
BHA, as it moves along the whipstock ramp from
the kickoff point, must remain within reasonable
limits throughout the milling operation. If this
cannot be achieved by assembly design, then there
is a risk that the window mill will suffer early
jump-off from the whipstock face at locations
along the whipstock ramp.
In areas where a positive side force is applied,
the window mill is urged against the ramp of
the whipstock and may preferentially mill the
whipstock face rather than the casing. Conversely,
negative side force will divert the mill away from
the ramp of the whipstock, causing the mill to
exit the casing prematurely. This situation leads
to a foreshortened full gauge window which can
adversely affect subsequent drilling operations
when it becomes problematic to exit the casing
aperture with a stiff BHA. After exiting, the
drilling assembly is forced to maintain a high
trajectory angle immediately outside the window,
which rapidly reduces TVD. It also creates a
high localized dogleg that is difficult to manage
because of increased drilling torque and drag that
creates higher concentrated stresses on tool string
components as they exit the casing into openhole.
Wireline and completion activity is similarly
affected, albeit to a lesser extent, as a result of
the more limber nature of the assemblies.
More specifically, before the gauge OD of the
window mill clears the casing, the cutting action
will tend to walk or move off the centerline of the
whipstock, creating a spiral shape in the direction
of the rotation of the mill. This uncontrolled
spiraling will create an aperture in the casing that
terminates 20 to 30° to the right of the intended
path, as indicated in Fig. 1. Because the casing
46
no longer provides a restraining force to the mill
and the side forces are maximized, the trajectory
of the lateral borehole created in the surrounding
formation invariably continues to spiral over the
top of the casing if the window is created high
side (typically between 0° to 35° left or right from
the highest point in the well), or will roll off the
whipstock as a result of the force of gravity acting
on the mill assembly as the exit approaches a
toolface exit of 55°, creating an undesirable
drop in angle.
Geometrically, the shape of the conventionally
milled window is full gauge at the top, but narrows
toward the bottom as the mill departs the casing
and penetrates into the formation outside the
window. This results in a relatively short sweet
spot (Sw in Fig. 1) or full bore ID through the
opening of the casing. The shape of the lowermost
area of the window, as a result of the narrowing at
the bottom, is inherently V-shaped and has been
referred to as the “wicked V” or “evil V” for its
damaging effect on casing centralizers.
The combined detrimental effects of the shorter
sweet spot result in excessive friction and buckling
forces upon longer and stiffer assemblies as they
attempt to depart through the window. If sand
control screens are used, then the potential for
damage to the surface of the screens is increased
proportionately to the drag induced transitioning
across the window surface, occasionally resulting
in the inability to push the liner to TD, leading to
major downtime. External components, such as
centralizers (Fig. 2 and Fig. 3), and external or
annular casing packers, often hang up, become
fragmented, or sliced into pieces (Peterson et al.
2007) when passing across the V-shaped window
area, which results in expensive fishing operations
and the accumulation of significant NPT.
Window geometry, specifically the geometrical
precision with which a window is created,
becomes increasingly important (Fipke et al. 2003)
and critical with regard to the ability to later
deploy and recover tools and systems through
the opening. Lateral, openhole (TAML Level 2)
liner assemblies often incorporate polished
bore receptacles or tieback receptacles near
the top to accommodate seal assemblies for
junction isolation during hydraulic stimulation
operations. The ability to create a competent,
robust seal at this point in well operations is
critical for several reasons:
• Effect upon production profile
• Isolation of junction from fracture pressure
• Cement integrity of mainbore casing
Isolation tieback assemblies are typically deployed
across the junction window and through a short
openhole interval before stinging into a polished
bore receptacle at the top of the lateral liner. The
Full gauge
‘sweet spot’ (Sw)
Figure 2. – Centralizer debris.
Roll-off effect
some 20 to 30 to
the right of the
intended path.
Figure 1. – Roll-off effect.
Figure 3. – Damaged centralizers.
© 2007 SPE
pathway of the seal stinger, when departing the
mainbore casing, should ideally be unrestricted
and should it encounter a reduced window
opening, as in the case of a conventionally
milled window with poorly defined geometry,
there is every risk that serious damage to the
seals may occur as they are dragged across
the narrowing aperture. If the isolation tie-back
assembly leaks due to damage to the seals
then the lateral wellbore cannot be fracture
stimulated as required.
If the formation is easier to mill than the steel of
the casing, which is typically the case, the lead
mill will tend to take the line of least resistance,
at which point it is subject to the nature of
the formation it is milling; strong formation
tendency or preferred bedding structure will
affect the direction that the mill takes. It becomes
increasingly more difficult to retain the lead and
string mill against the whipstock ramp and guide
them as intended; because an operator has no
control other than RPM or weight applied to the
mill, the direction the assembly takes becomes
more difficult to control the further in to the
formation it progresses.
With the lengthening of directional drilling BHA
designs to include sophisticated logging-whiledrilling equipment (LWD), they invariably become
stiffer and include components with a variety of
standoffs, all of which tend to hang up across
poorly milled apertures. The associated downtime,
sometimes leading to an additional milling run
to enlarge the exit, can run into days. Even when
a drilling assembly is gently eased over the
whipstock and past the casing window opening,
the subsequent poor hole quality can lead to slow
drilling for some time.
The completion technology now applied and
deployed across multilateral junctions steadily
increases in complexity, composition, and cost
each year as new techniques and subsequent
solutions evolve. Longer liner sections, including
premium screens, packers, stimulation sleeves,
and swellable and inflatable isolation tools,
in addition to post-completion lateral re-entry
requirements, require reliable and repeatable
access to the lateral.
Some whipstock anchoring tools have been
known to either set prematurely or to move after
they have been set. In worst case scenarios, the
whipstock cannot be recovered and the mainbore
is lost, or the whipstock is recovered and the
packer itself must be milled out. If the anchoring
system fails, the whipstock may slip downhole
during the milling procedure and the original
depth reference is lost or, just as seriously, the
whipstock may turn within the casing as a result
of the interference with the mill as it rotates. In
this scenario, more steel may be milled away from
the casing than designed and other issues then
come in to play.
In Fig. 4, the CAST images illustrate that the
whipstock has become unanchored and the mill
has been allowed to rotate, resulting in almost
360° of milled casing.
large volume of material; therefore, milling rates
should be kept to between 5 and 10 ft/hr while
maintaining high flow rates and interspersing
high viscosity sweeps to aid cuttings removal. The
ability of the mud system to ensure removal and
thereby clean the hole effectively also depends on
the shape and size of the cuttings. Cutters typically
produce 5-in3 of steel for every cubic inch of steel
milled. Consequently, the hole cleaning program
must be robust enough to ensure effective cuttings
removal. Furthermore, the surface system must be
able to effectively separate these cuttings from the
drilling fluid so that they do not congest equipment
or become recycled into the well.
If the milling operation occurs too quickly, the
steel tends to be milled away in an ‘orange peel’
fashion, creating long strings of swarf. These
tend to coalesce to form nests of steel that are
extremely difficult to remove from the well and can
create huge problems as the operation proceeds.
If the debris from the milling procedure is not
properly cleared from the well, enough steel may
remain in the vicinity of the window and in the
lateral to affect the quality of surveys while drilling
Figure 5. – Track-guided milling tool with milled
casing aperture.
Debris Management
Advances in mill design have enabled operators
to mill windows much faster; a 7- or 8-hour
operation was not an uncommon average milling
time, excluding the creation of the rathole. Today,
those milling times have been reduced by half,
yet this comes with a price even if a strict debris
management regimen is followed.
Figure 4. – CAST image of unanchored milling
operation.
The speed at which the milling operation can
proceed depends on the effective removal of the
metal cuttings produced. Speeds of up to 40 ft/hr
can be obtained, but it is impossible to ensure that
cuttings are effectively removed from the wellbore.
With a 9 5/8-in. casing weight of 47 lb/ft., 450 lb of
metal is produced for the average window length.
Enough time must be given to circulating out this
Figure 6. – Track-guided mill with mill guide.
47
M I LLR I T E ® SYS T EM PREM I UM REPL A CEME NT F OR CO NVE NTI O NAL M ILL ING
ahead for some time. This magnetic interference
attributable to metal debris in the well could mean
that drilling is blind to the actual trajectory of the
well, and at best could result in a prolonged period
of circulation to clean the well. In the worst case,
it could lead to an undesirable well course and
lengthy remedial action.
also has a unique feature by which the cuttings
are directed by internal barriers and caught in
an integral debris basket. The tool can also be
fitted with magnets to remove finer steel filings
when the tool is recovered from the well, which
eliminates the need for additional cleanup trips.
Track-Guided Milling Experience
Innovative PrecisionMilled Casing Exits
To contend with the inherent flaws associated
with conventional milling, the industry required the
advent of a precision milling tool. The MillRite®
system was just such a product (Fig. 5) and, at its
inception, was readily adopted as the premium
replacement for conventional milling for TAML
Level 2, 3, and 4 multilateral junction construction.
The first issue to be addressed, that of the method
used to create the window opening, was solved
by ensuring that the milling head is attached to a
track (Fig. 6) that precludes the jump-off effect. By
securing the mill to a rigid guide that is secured
in the well at a set depth and orientation, the mill
must follow the line of the rails as it proceeds
along the track. Therefore, it cuts a geometrically
precise aperture, defined by the length and width
of the track and the depth of cut of the mill. The
control of milling parameters is far more refined,
although the cutting speed is still limited by the
ability of the drilling fluid to transport cuttings out
of the well. Nevertheless, the milling parameters
can be far more easily read and adjusted for
optimum milling efficiency.
By the same means, the mill cannot spiral
along the course of the milling length; instead,
the aspect of the cut is maintained precisely
parallel to the axis of the casing, resulting in a
rectangular aperture of equal width. The sweet
spot is sustained along the complete 17 ft length
of the guide, eliminating the foreshortening effect
produced by conventional milling. Because the mill
is locked to the track, it cannot roll off, regardless
of the toolface angle of the cut, which eliminates
the roll-off issue.
The contact of the track-guided mill with the
steel casing differs from a conventional mill;
instead of being oblique to the casing at the same
angle as the whipstock, the mill meets the steel
horizontally and cuts square ends to the aperture.
This design eliminates the “evil V” effect and
renders a completion-friendly aperture geometry
48
Figure 7. – Steel cuttings from track-guided
milling system.
that is unlikely to tear away external liner/screen
components or damage the screens. To achieve
this, the mill design differs radically from the
traditional shape and includes the attributes of
a flat-bottomed mill and of a section mill. The
durable cutting structure incorporates integral
circulation paths to effectively remove milled
debris and cool the mill.
The length of milling machine produces a window
that is significantly longer than those achieved
with conventional whipstocks. The elongated
window enables a far smoother exit by stiff
variable OD drilling BHAs, lateral screens, or
completion tools. The resultant dogleg is much
lower than conventionally milled windows and
in one plane, as opposed to a spiral which, by its
nature, will always be 3D.
The anchoring method, by means of a unique
latch coupling that is integral to the casing string,
ensures that no inadvertent rotation of the milling
assembly occurs within the casing after it has
been locked in place. The latch coupling, which
has an impressive track record with more than 730
installations worldwide, ensures repeatable depth
and orientation of the multilateral assemblies
within the casing and provides the means for
subsequent lateral re-entry accuracy.
Milled Steel
The cutting structure of the track-guided mill is
radically different than that of conventional mills
which rely on the individual inserts to remain
intact to make progress. The cutting action of the
track-guided mill produces very thin and narrow
slivers of steel (Fig. 7) which are inherently easy to
remove from the well with the flow of the drilling
fluid and a regime of viscous sweeps. The tool
Recently, track-guided milling systems were
implemented in Saudi Arabia as a preferred
practice, particularly in the installation of TAML
Level 4 junctions. This implementation is primarily
because of the requirement of the laterals to
be completed with ICD screens and swellable
packers, and the mainbore to include intelligent
completion functionality. The following section
describes the operational steps performed for one
particular well.
The first step in operation was to install the
9 5/8-in. latch coupling as an integral part of the
casing string. The latch coupling was set at a
predetermined depth to place the subsequently
milled window at the center of the casing joint
directly above.
After the casing was set, a dual purpose landing
tool, combined with MWD equipment in the tool
string, was run to depth to jet the latch coupling
free of debris and latch into it to obtain a toolface
reading. This toolface reading was used to
calculate the alignment offset on the milling tools
for the window to be milled at the planned exit
angle. In accordance with the drilling program, this
exit angle was to be 25° right of highside.
The track-guided milling tool was then aligned
to 25° right of highside on the rig floor and run
and set into the latch coupling to begin milling
operations. The total milling time was 3 hours
and the final result was a 7.2-in. wide cut for
approximately 15 ft in length. The removal
of milling cuttings is essential for the proper
functionality of the mill and future operations
through and around the junction. At every 5 ft,
a 20-bbl high viscosity sweep was pumped, and
tandem 50 bbl high viscosity sweeps were pumped
as a final clean before pulling out of hole. To
save rig operating time, the running, setting, and
retrieving of this track-guided milling tool was
designed as part of the assembly. Thus, when
milling is complete, and the mill assembly engages
back into the tripping position, the assembly is
pulled out of hole.
The second step in creating the window was the
whipstock run. This assembly was fastened with a
shear bolt to a lead and watermelon mill tandem
assembly and run in the well as one assembly.
After the whipstock was set in the latch coupling,
the string was reciprocated to fatigue and shear
the bolt, freeing the mill assembly. This milling
assembly has three functions: to open the window
to full gauge, to dress the rough edges created
by the track-guided milling assembly, and to drill
a rathole into the formation that is adequate for
the subsequent direction drilling BHA to pass. The
window was opened to 8 ½ in. and the rathole
was drilled 10 ft into the formation in just over 2.5
hours. A 10-bbl high viscosity sweep was pumped
every 5 ft of milling and concluded with a 50-bbl
high viscosity sweep while final reaming.
The 8 ½-in. lateral section was subsequently
drilled with a rotary steerable and quad combo.
There was no resistance passing in or out of the
window throughout the drilling phase. The lateral
was landed and a 7-in. liner run and cemented
up to the junction. The 6 1/8-in. section was then
drilled to TD and ICD; swell packers were run
into the openhole and set by a liner hanger in the
7-in. liner.
The final mainbore completion consisted of one
9 5/8-in. feed-through packer set below the junction
with an interval control valve (ICV) hung below in
the tailpipe for mainbore flow control. Above the
lower feed-through packer is the ICV to control
the lateral flow. The upper 9 5/8-in. feed-through
packer is set above the junction and, from that
point, production tubing with control lines continue
up to surface.
Re-entry for Existing Wells
A typical scenario regarding the need for trackguided milling systems is in an existing well.
Conventionally milled windows are more suited to
openhole laterals that do not need to be accessed
in the future. It is primarily when these laterals
must be accessed or completed to a higher
complexity that a straight and extended window is
required (Lowson et al. 1999).
In a recent case in Saudi Arabia, the operator
requested that an offshore single lateral well be
worked over to be a dual lateral, using a TAML
Level 4 (cemented) junction. In addition, the
mainbore was to be completed with an intelligent
completion, using full gauge feed-through packers
above and below the junction. Summarizing the
primary requirements, the window had to be milled
in the 9 5/8-in. casing that has previously been
run and cemented in place. This window required
a precise geometry to enable a 7-in. liner and
the swellpacker combined with ICD completion
string to pass. Finally, the completed TAML Level
4 junction must enable full gauge tools to pass
through to the lower mainbore.
The solution was provided by a re-entry system
that included the track-guided precision milling
system. Based on the standard system for new
wells, the re-entry system indexed on a packer
and latch coupling assembly. After the packer
was set, the milling began and the subsequent
operations to complete the TAML Level 4 junction
were conducted. The junction was completed
in accordance with the program, enabling full
gauge tools to pass without obstruction. Since the
packer and latch coupling assembly remained as a
permanent fixture in the well, the upper lateral can
be accessed later by pulling the upper completion
and running a workover whipstock.
Completions
In recent Level 4 junctions in Saudi Arabia,
completion strings consisting of swellable
packers or external casing packers combined
with ICD screens have been installed in a variety
of configurations in both mainbore and upper
lateral sections; typically, these sections are
approximately 3,000 ft long.
In addition to the cumbersome length of the
completion string, the junction is often placed in
a near horizontal section, which increases the
difficulty of exiting the window smoothly and
landing on depth. Only a precision cut window
with notable length is acceptable in these
conditions. To date, 100% success has been
achieved when running the completion string
through a geometrically controlled window.
Case Study
Special Application: Multilateral For
Shale/Tight Gas
The Devonian of west Texas has been producing
since the first discovery wells were drilled in the
1950s. Since 1995, there has been considerable
success in drilling long horizontal wells though
the reservoir, which has increased production in
comparison to the vertical wells that were initially
drilled into this zone. The return on investment
(ROI) has been realized in a matter of months,
rather than years. Even with thousands of feet
of reservoir exposure, the natural permeability is
still insufficient for economical production without
production stimulation treatment.
The primary concern about treating a multilateral
well is the effect of high pressure on the formation
at the junction. If the fracture gradient is exceeded
and the formation breaks down, then fluid would
be pumped into the vicinity of the junction, rather
than the reservoir. Without protection from the
acid and pressure, the formation matrix could be
dissolved, causing further damage to the integrity
of the wellbore. A temporary Level 5 completion
was designed to isolate the junction from the
stimulation fluids. The junction isolation tool
(JIT) was designed to be installed on a
hydraulically set, retrievable packer with a very
high differential pressure rating of 10,000 psi.
The track-guided milling system was used to mill
the casing exit window because it creates a long,
straight window.
A latch coupling, which serves as an anchoring
point for the milling and drilling whipstocks, was
installed as a part of the mainbore 7-in., 26-lb,
P-110 casing string. It was positioned in the casing
string at approximately 11,800 ft, in vertical hole,
just below the depth at which the casing window
was to be milled. The latch coupling was designed
to have the same ID as the API drift of the casing
string to avoid creating a restriction. In older wells,
this latch coupling device can be installed on a
permanent anchor packer to latch the multilateral
drilling tools on depth and orientation.
This well was the world’s first selective, highpressure stimulation of a multilateral well using a
junction isolation system. It was finally completed
with 2-3/8-in. tubing landed just above the
junction on a 7-in. production packer. The well
is currently producing commingled gas and gascondensate from two different horizontal legs
that drain the northwest and southeast quadrants
of the acreage, respectively. Production rates
are satisfactory for the reservoir quality in the
area, and the combined dual-lateral production is
approximately twice that of conventional wells in
the region.
Conclusion
Despite advances made in mill and whipstock
technology, the method by which window
49
M I LLR I T E ® SYS T EM PREM I UM REPL A CEME NT F OR CO NVE NTI O NAL M ILL ING
apertures are constructed in multilateral wells
is inherently prone to poor geometric outline.
Problems exiting such windows have been
encountered on a plethora of occasions and have
led to significant NPT, as well as irreparable
damage to lateral completion and re-entry
components. The geometrically well defined
casing window produced by a track-guided
system will mitigate most, if not all, issues
encountered when using a conventional milling
system. The ease and accuracy of the window
construction and the repeatability provided by
means of the latch coupling are unique in the
industry, which is constantly striving for this
type of high quality solution.
References
Peterson, E.M., Greener, M.R., Davis, E.R.,
and Craig, D.T. 2007. How Much is Left of Your
Centralizer After Exiting a Casing Window in
an Extended Reach Horizontal Multilateral?
Modeling, Yard Tests and Field Results from
Alaska’s West Sak Development. Paper SPE
105766 presented at the SPE/IADC Drilling
Conference, Amsterdam, The Netherlands,
20-22 February.
Fipke, S. 2003. Isolation of a Multilateral
Junction for High-Pressure Stimulation - A West
Texas Case Study. Paper presented at the HighTech Wells Conference and Exhibition
Multilateral, Intelligent Completions and
Expandables, Galveston, Texas, USA,
11-13 February.
Lowson, B. 1997. Advanced Window Milling
Technology for Multi-Lateral Applications.
Paper presented at 6th One-Day Conference
on Horizontal Well Technology Organized by
the Canadian Section SPE and the Petroleum
Society of CIM, HWSIG held in Calgary, Alberta,
Canada, 12 November.
Authors
Calvin Ponton has a diverse
and extensive background in the
oilfield service industry. A 34-year
Halliburton employee, he is a global
technical advisor for Multilateral
Technology in Sperry Drilling.
Calvin’s technical background ranges from completions,
project management, business development and technical
support of project executions for multilateral technology.
Calvin attended Texas A&I University and the University
of Texas. He has co-authored and published numerous
technical papers and articles.
Justin Roberts is the Artificial
Lift manager at Rotating Right Inc.
in Calgary, Canada. He has a BSc
in mechanical engineering from
the University of Alberta and is a
registered professional engineer
in Canada. From 2003 to 2013 Justin worked in the
Multilateral Technology group for Halliburton. He started
as a design engineer in Nisku, Canada and moved into
operations and management roles based in the Middle
East and Asia Pacific regions.
50
Steven Fipke is the international
business development manager for
Tendeka in Houston. He has a BSc
in petroleum engineering from the
University of Alberta in Edmonton,
Canada and for more than 12
years Steven was part of the Halliburton organization
specializing in Multilateral Technology (Drilling and
Completions). Steven has been assigned to various roles
in technology, operations and business development for
Halliburton in Canada, Venezuela, Houston, and Dubai, has
authored a variety of industry publications, and holds a
number of patents on downhole technology.
Andy Cuthbert graduated from
the University of London with a
BSc (Hons) geology in 1981, and
went on to complete an MPhil
in geology before joining the oil
industry in 1984. He has 30 years
of oilfield experience; 10 years with Schlumberger as a
directional driller, and then moving to Halliburton where
he has been involved in projects of ever increasing
complexity concerning the introduction and coordination
of new technology.
Andy was team lead for the Multilateral Technology group
in Norway followed by project management and later as
regional manager for Directional Drilling and Multilateral
Technology in Southeast Asia operations. He subsequently
took on the role of Multilateral global product champion
in Houston and was to return to Consulting and Project
Management as senior project manager in Iraq before
joining Boots & Coots, where he is primarily involved in
risk management, well control technology and planning of
contingency well measures.
51
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