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WELL CONTROL MANUAL
Table of Contents
Introduction and Responsibilities
Section A
Basic Calculations and Terminology
Section B
Causes and Detection of Kicks
Section C
Tripping Procedures
Section D
Shut-In Procedures
Section E
Well Killing Procedures
Section F
Pre-recorded Data Sheet
Section G
Driller’s Method
Section H
Engineer’s Method
Section I
Volumetric Control
Section J
Equipment Requirements
Section K
Maintenance and Testing Requirements
Section L
Diverting Operations and Equipment
Section M
Training and Well Control Drills
Section N
Hydrogen Sulfide ( H 2S) Considerations
Section O
Stripping and Snubbing
Section P
Tables and Charts
Section Q
Well Control Equations
Section R
Well Control Policies
Section S
Supplemental References
Vertical/Deviated Well Kill Sheets
Horizontal / Highly Deviated Well Kill Sheets
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INTRODUCTION AND RESPONSIBILITIES
Table of Contents
Introduction.......................................................................................................... 2
1.0
Responsibilities of Drilling Staff ........................................................ 3
1.1
1.2
1.3
1.4
1.5
1.6
1.7
1.8
1.9
1.10
1.11
1.12
1.13
1.14
1.15
1.16
1.17
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Well Planning...................................................................................
Drilling Program...............................................................................
Geological Information.....................................................................
Area Drilling Experience ..................................................................
Casing Design and Depths of Setting ..............................................
Equipment Selection........................................................................
Hiring Contract Rigs. ........................................................................
Specification of Rig Equipment .......................................................
Contract Responsibilities.................................................................
Training of Company and Contract Personnel .................................
BOP Equipment ...............................................................................
BOP Testing .....................................................................................
Well Control .....................................................................................
Pre-recorded Data Sheet .................................................................
Slow Pump Rate Data.......................................................................
Blowout Prevention Training ...........................................................
Information to be Posted..................................................................
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INTRODUCTION AND RESPONSIBILITIES
Introduction
The single most important step to blowout prevention is closing the blowout preventers when the
well kicks. The decision to do so may well be the most important of your working life. It ranks with
keeping the hole full of fluid as a matter of extreme importance in drilling operations.
The successful detection and handling of threatened blowouts (‘kicks’) is a matter of maximum
importance to our company. Considerable study and experience has enabled the industry to
develop simple and easily understood procedures for detecting and controlling threatened
blowouts. It is extremely important that supervisory personnel have a thorough understanding of
these procedures as they apply to Saudi Aramco operated drilling rigs.
The reasons for promoting proper well control and blowout prevention are overwhelming. An
uncontrolled flowing well can cause any or all of the following:
•
•
•
•
•
•
•
•
Personal injury and/or loss of life
Damage and/or loss of contractor equipment
Loss of operator investment
Loss of future production due to formation damage
Loss of reservoir pressures
Damage to the environment through pollution
Adverse publicity
Negative governmental reaction, especially near populated areas
This manual describes Saudi Aramco’s policies and equipment standards for well control/blowout
prevention. It has been designed to serve as a reference for company and contractor personnel
working in drilling and workover operations.
rd
Changes in this 3 Edition of the Saudi Aramco Well Control Manual are indicated by a bold
vertical line in the right margin, opposite the revision.
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INTRODUCTION AND RESPONSIBILITIES
1.0
Responsibilities of Drilling Staff
The Drilling and Workover Organization includes an office drilling staff comprised of the
Drilling Operations Manager(s), Drilling Engineering Manager, Drilling Superintendent(s),
and Drilling Engineer(s) in addition to the onsite Drilling Foreman. Their responsibilities
include:
1.1
Well Planning
Planning for maximum efficiency and safe operations is primarily the office drilling
staff's responsibility. They must, with concurrence of the Drilling Operations
Manager, use all known information and good judgment to make the best possible
well plan for a particular area.
1.2
Drilling Program
This program should include the casing program, mud program, consideration of
special equipment that will be required and specific well problems that may be
encountered, and any other information pertinent to the safe and efficient drilling of
the particular well. The drilling program is written by the Drilling Engineer (assigned
to the rig) and approved by the Drilling Superintendent and/or Drilling Operations
Manager.
A directional program is also required to avoid existing holes, or when the target
location is different than the surface location, or in case a relief well is needed. The
amount of detail required depends on the depth, pressure, presence of H2S,
crookedness, etc. In high angle holes, singleshot readings should be taken on two
instruments, and an ellipse-of-uncertainty calculated. It is very important, especially
in offshore operations, to know accurately the surface and subsurface locations of
the well. In directionally drilled wells, the well course should be pre-planned, and
horizontal and vertical sections should be maintained continuously during drilling, to
insure that the well course is accurate. Deviations should be corrected early to avoid
excessive doglegs.
Often multi-shot readings are made prior to setting surface casing, so its position is
accurately known. All reasonable effort must be made to know accurately the well
position and course, from the surface to total depth. The degree of effort required
varies with the drilling operation.
1.3
Geological Information
The Drilling Engineer needs all available geological information for the area to
prepare a good drilling program. This requires good communication with the
geologists to explore possible drilling problems, and preparing a method of handling
each.
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1.4
Area Drilling Experience
Each area has characteristic drilling problems that experienced personnel can
handle most efficiently and safely. The Drilling Superintendent and Manager should
be primarily responsible for seeing such assignments are filled with qualified Drilling
Foremen.
1.5
Casing Design and Depths of Setting
Compliance to proper casing design and setting depths, calculated from expected
formation pressures and fracture gradients, is vital, particularly in high-pressure
areas. Isolation of fresh water aquifers must also be considered in the casing
program.
1.6
Equipment Selection
Proper equipment is necessary for an efficient and safe operation. Considerable care
must be exercised in selecting equipment with the pressure rating and design for the
specific job. This should be primarily the Drilling Superintendent’s responsibility, with
concurrence of the Drilling Operations Manager and Drilling Engineering Manager.
1.7
Hiring Contract Rigs
The Drilling Superintendent and Drilling Operations Manager will usually provide the
proper rig for the job. The rig’s experience in the area could be a factor, and rig
evaluations should include past performance and condition of equipment. Where
crews change seasonally, the decision could be based on the general performance
of the contractor.
1.8
Specification of Rig Equipment
Selecting the proper equipment to do a particular job is very important. The Drilling
Superintendent’s closeness to the operation makes him best qualified to recommend
equipment.
1.9
Contract Responsibilities
The Drilling Superintendent and Drilling Operations Manager have the responsibility
to see that the contracts between Saudi Aramco and the drilling contractor are
written clearly, defining the obligations of both contracting parties.
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INTRODUCTION AND RESPONSIBILITIES
1.10 Training of Company and Contract Personnel
The Drilling Superintendent and Drilling Operations Manager should maintain a
training program for the less experienced drilling employees. The program should
pair the newer employees with experienced Drilling Foremen at the wellsite, and
include attendance at company-sponsored and external schools/seminars. Drilling
Superintendents should periodically review well control procedures with the Drilling
Foreman. The contractor shall be required to train his men in well control, either by
contract or by direction from the Drilling Superintendent and Foremen.
1.11 BOP Equipment
The Drilling Foreman must ensure that the proper BOP equipment is available and
installed correctly and in good working order. He must also verify that the equipment
is in compliance with all Saudi Aramco requirements and API specifications. ALL
SECTIONS of the BOP Test and Equipment Checklist must be completed upon
initial nipple-up.
1.12 BOP Testing
Saudi Aramco requires that the blowout preventer stack be tested once every two
weeks and before drilling out each new casing string. Accurate and complete testing
of the BOP equipment is the responsibility of the Drilling Foreman on location. The
BOP Test and Equipment Checklist should be completed after each test.
1.13 Well Control
The Drilling Foreman is primarily responsible for keeping the well under control. This
responsibility includes maintaining the proper mud properties, recognizing indicators
of abnormal pressure and executing the proper well control procedures after the well
kicks.
1.14 Pre-recorded Data Sheet
The pre-recorded data sheet should be filled out as completely as possible at all
times on drilling and workover wells. The data sheet lists critical wellbore information,
which will be needed in nearly all well control situations.
1.15 Slow Pump Rate Data
The Drilling Foreman must make sure that slow pump rates and pressures are
recorded:
•
•
•
•
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After a mud weight change
After a bit nozzle or BHA change (after breaking circulation gels)
After each 500 ft depth interval
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•
•
After a drilling/completion, or workover fluid type change
Whenever mudflow properties change significantly
Slow pump pressure measurements should not be taken at the following times:
•
•
•
If the mud flow properties are contaminated
Hydrostatic imbalance exists between drill/work string and annulus
During times of loss of circulation or washouts in the drill/work string
1.16 Blowout Prevention Training
The finest equipment and the best procedures are of little use unless the rig crews
are properly trained to use them. The Drilling Foreman must see that the crews are
properly trained and respond immediately in all well control situations. The Drilling
Foreman should make sure that the shut-in procedures while tripping and drilling are
clearly posted at several locations around the rig, and that every crewmember knows
his shut-in responsibilities.
1.17 Information to be Posted
The Drilling Foreman should know and post the following information:
•
•
•
•
•
Current Edition:
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Maximum allowable initial shut -in casing pressure to fracture shoe
Maximum allowable casing pressure
Maximum number of stands pulled prior to filling the hole (collars,
HW, and DP)
Volume required to fill the hole on trips (collars, HW, and DP)
Crew responsibilities for well control drills
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SECTION A – BASIC CALCULATIONS AND TERMINOLOGY
Table of Contents
1.0
Understanding Pressures................................................................. A-2
1.1
1.2
1.3
1.4
1.5
1.6
1.7
1.8
1.9
1.10
2.0
3.0
4.0
5.0
Hydrostatic Pressure .................................................................... A-2
Pressure Gradient......................................................................... A-2
Formation Pressure ...................................................................... A-3
Surface Pressure .......................................................................... A-3
Bottomhole Pressure .................................................................... A-4
Equivalent Circulating Density...................................................... A-4
Differential Pressure ..................................................................... A-5
Choke Pressure ............................................................................ A-5
Swab and Surge Pressures........................................................... A-5
Fracture Pressure ......................................................................... A-6
Relationship of Pressure to Volume .............................................. A-7
2.1
Liquids .......................................................................................... A-7
2.2
Gases............................................................................................ A-7
Relationship of Pump Pressure to Mud Weight .......................... A-8
Relationship of Pump Pressure to Circulating Rate .................. A-8
Capacity Factors and Displacement .............................................. A-9
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SECTION A – BASIC CALCULATIONS AND TERMINOLOGY
1.0
Understanding Pressures
1.1
Hydrostatic Pressure
All vertical columns of fluid exert hydrostatic pressure. The magnitude of the
hydrostatic pressure is determined by the height of the column of fluid and the
density of the fluid. It should be remembered that both liquids and gases could exert
hydrostatic pressure. The hydrostatic pressure exerted by a column of fluid can be
calculated using Equation A.1. While drilling ahead, the hydrostatic pressure exerted
by the drilling mud is our number one defense against taking kicks.
Equation A.1
Hydrostatic Pressure
HP
=
MW x 0.007 x TVD
HP
MW
TVD
=
=
=
Hydrostatic Pressure (psi)
Mud Weight (pcf)
True Vertical Depth (ft)
where:
1.2
Pressure Gradient
When comparing fluid densities and hydrostatic pressures, it is often useful to think
in terms of a pressure gradient. The pressure gradient associated with a given fluid
is simply the hydrostatic pressure per vertical foot of that fluid. Heavier (more dense)
fluids have higher-pressure gradients than lighter fluids. The pressure gradient of a
given fluid can be calculated with the formula given in Equation A.2.
Equation A.2
Pressure Gradient
PG
=
MW x 0.007
PG
MW
=
=
Pressure Gradient (psi/ft)
Mud Weight (pcf)
where:
As you can see from the above equation, the pressure gradient can be thought of as
an alternate way of describing a fluid’s density. This is useful because other
parameters, such as reservoir pressure, are often expressed in terms of pressure
gradients as well.
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SECTION A – BASIC CALCULATIONS AND TERMINOLOGY
1.3
Formation Pressure
Formation pressure is the pressure contained inside the rock pore spaces.
Knowledge of formation pressure is important because it will dictate the mud
hydrostatic pressure and therefore the mud weight required in the well. If the
formation pressure is greater than the hydrostatic pressure of the mud column, fluids
(gas, oil or salt water) can flow into the well from permeable formations. Normal
pressure gradients for formations will depend on the environment in which they were
laid down in and will vary from area to area.
Consider a formation located at a vertical depth of 5000’ and with a reservoir
pressure of 2325 psi. The pressure gradient of this formation can be easily figured
with the following formula:
Pressure
PG =
Vertical Depth
2,325 psi
=
= 0.465 psi/ft
5,000 ft
In order to keep this formation from flowing into the well, the mud in the hole must
also have a pressure gradient of at least 0.465 psi/ft. This condition could be
achieved by filling the hole with 67 pcf salt water.
1.4
Surface Pressure
We use the term surface pressure to describe any pressure that is exerted at the top
of a column of fluid. Most often we refer to surface pressure as the pressure, which
is observed at the top of a well. Surface pressure may be generated from a variety of
sources including downhole formation pressures, surface-pumping equipment, or
surface chokes.
Some surface pressures are conveyed throughout the wellbore while others are not.
For example, circulating an open well with 1,000 psi pump pressure will not increase
the bottomhole pressure by 1,000 psi. The reason for this is that the pump pressure
is due primarily to internal drillpipe friction, which acts opposite to the direction of
flow. In a similar way, the annular friction loss generated while circulating will
increase the bottomhole pressure but will not increase the annular surface pressure.
The key to understanding frictional pressure losses is to remember that they only
increase the pressures in the fluids, which are upstream of the point of friction.
Under static conditions (not pumping or flowing) frictional pressure losses are equal
to zero. Therefore, under static conditions, any pressure which we observe at
surface will also be conveyed downhole.
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1.5
Bottomhole Pressure
Bottomhole pressure is equal to the sum of all pressures acting in a well. Generally
speaking, bottomhole pressure is the sum of the hydrostatic pressure of the fluid
column above the point of interest, plus any surface pressure, which may be exerted
on top of the fluid column, plus any annular friction pressure. This concept is
expressed mathematically in Equation A.3.
Equation A.3
where:
Bottomhole Pressure
BHP
=
BHP
HP
SP
FP
=
=
=
=
HP + SP + FP
Bottomhole Pressure (psi)
Hydrostatic Pressure (psi)
Surface Pressure (psi)
Friction Pressure (psi)
When the hole is full and the mud column is at rest with no surface pressure, the
bottomhole pressure is the same as the mud hydrostatic pressure. However, if
circulating through a choke or separator at the surface, the annular surface pressure
and friction pressure (back pressures) will be conveyed downhole and must be
added to the mud hydrostatic pressure to obtain the total bottomhole pressure. If the
well is shut in, under static conditions, the bottomhole pressure will be equal to the
sum of the hydrostatic pressure and any observed surface pressure. In this static
case, the bottomhole pressure will also equal the formation pressure.
1.6
Equivalent Circulating Density
When circulating fluid in a wellbore, frictional pressures occur in the surface system,
drill pipe, bit and in the annulus, which in turn are reflected in the standpipe pressure.
As also discussed, these frictional pressures always act opposite to the direction of
flow. When circulating conventionally, or the “long way”, all the frictional pressures,
including annular friction, act against the pump. The annular friction, or annular
pressure loss as it is sometimes referred to, acts against the bottom of the wellbore,
which results in an increase in bottomhole pressure. This is known as Equivalent
Circulating Density, or ECD. ECD is normally expressed as a pound per cubic foot
equivalent mud weight and is shown mathematically in Equation A.4.
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SECTION A – BASIC CALCULATIONS AND TERMINOLOGY
Equation A.4
Equivalent Circulating Density
Annular Pressure Loss
ECD
=
+ Present Mud Weight
0.007 x TVD hole
ECD is a result of annular friction and is affected by such items as:
•
•
•
Clearance between large OD tools and the ID of the wellbore
Circulating rates (or annular velocity)
Viscosity of the mud
An accurate value for annular pressure loss, and subsequently ECD, is very difficult
to arrive at for any particular situation and, once calculated, would change with
increasing hole depth and changes in hole geometry (hole washout, etc.). Thus,
attempting to keep up with ECD in the field would be an effort in futility. The
important thing to remember is that while circulating, bottomhole pressure will be
higher than when the well is static due to the presence of annular friction.
1.7
Differential Pressure
In well control, differential pressure is the difference between the bottomhole
pressure and the formation pressure. The differential is positive if the bottomhole
pressure is greater than the formation pressure, which creates what is called an
‘overbalanced’ condition.
1.8
Choke Pressure
Choke pressure is the pressure loss created by directing the return flow from a shutin well through a small opening or orifice for the purpose of creating a backpressure
on the well while circulating out a kick. The choke or back pressure can be thought of
as a frictional pressure loss which will be imposed on all points in the circulating
system, including the bottom of the hole.
1.9
Swab and Surge Pressures
Swab pressure is the temporary reduction in the bottomhole pressure that results
from the upward movement of pipe in the hole. Surge pressure is the opposite effect,
whereby wellbore pressure is temporarily increased as pipe is run into the well. The
movement of the drilling string or casing through the wellbore is similar to the
movement of a loosely fit piston through a vertical cylinder. A pressure reduction or
suction pressure occurs as the piston or the pipe is moved upward in the cylinder or
wellbore and a pressure increase occurs as the piston, or pipe, is moved downward.
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Swab and surge pressures are mostly affected by the velocity of upward or
downward movement in the hole. Other factors affecting these pressures include:
•
•
•
•
•
Mud gel strength
Mud weight
Mud viscosity
Annular clearance between pipe and hole
Annular restrictions, such as bit balling
In order to prevent the influx of formation fluids into the wellbore during times when
the pipe is moved upward from bottom, the difference between mud hydrostatic and
swab pressure must not fall below the formation pressure.
1.10 Fracture Pressure
The formations penetrated by the bit are under considerable stress, due to the
weight of the overlying sediments. If additional stress is applied while drilling, the
combined stresses may be enough to cause the rock to fail or split, allowing the loss
of whole mud to the formation. Fracture pressure is the amount of borehole pressure
that it takes to split or fail a formation.
Rock strength usually increases with increasing depth and overburden load. As load
is increased the rock becomes highly compacted, giving it the ability to withstand
higher horizontal and vertical stresses. Therefore, fracture pressure normally
increases with depth. Fracture pressure is normally expressed as a gradient or an
equivalent density with units of psi/ft or pcf, respectively.
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2.0
Relationship of Pressure to Volume
All fluids under pressure will change in volume as the pressure changes. As pressure
increases, the volume of the fluid will decrease (i.e., the fluid will compress). As pressure
decreases the volume will increase (i.e., the fluid will expand). Volume of a fluid is related
to a lesser extent to its temperature. In general, volume will increase with an increase in
temperature and decrease with a decrease in temperature.
Fluids will compress or expand differently depending on their compressibility. Liquids have
a low compressibility compared to gas. The relative compressibility of liquids and gases is
an important factor in well control.
2.1
Liquids
Liquids of concern in well control include mud, salt water, oil, or any combination of
these liquids. Since the compressibility of these liquids is low, little change in volume
due to pressure or temperature changes should be expected as liquids are circulated
from the wellbore. Therefore, liquid expansion due to pressure and temperature
changes is considered negligible for nearly all well control calculations.
2.2
Gases
Gases, on the other hand, are very compressible and are subject to large changes in
volume as they migrate or are circulated from the wellbore. The expansion of a gas
bubble while circulating out a kick displaces large volumes of mud from the annulus,
which lowers the hydrostatic pressure. In order to maintain the bottomhole pressure
at a constant value equal to formation pressure, the choke must be decreased which
increases the surface pressure. The expanding gas also causes the pit level to
increase, which must be considered. With constant surface pressure, the volume of
the gas bubble will roughly double each time the bubble depth of an open well is
halved. If ‘V’ is the volume of a gas and ‘P’ is the pressure then, disregarding
temperature effects, the relationship between volume and pressure of a gas is given
by Boyle’s Law in Equation A.5.
Equation A.5
where:
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Boyle’s Law
P1 x V1
=
P2 x V2
P1
V1
P2
V2
=
=
=
=
Pressure of gas at depth 1
Volume of gas at depth 1
Pressure of gas at depth 2
Volume of gas at depth 2
A- 7
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SECTION A – BASIC CALCULATIONS AND TERMINOLOGY
3.0
Relationship of Pump Pressure to Mud Weight
The relationship between mud weight and pump pressure is given by the following formula:
Equation A.6
New Pump Pressure = Old Pump Pressure x New Mud Weight
Old Mud Weight
where:
New Pump Pressure & Old Pump Pressure (psi)
New Mud Weight & Old Mud Weight (pcf)
Example:
Old Pump Pressure = 2800 psi
Old Mud Weight
= 97 pcf
New Mud Weight
= 105 pcf
Calculate the pump pressure required to circulate the well with the new
mud weight?
New Pump Pressure = 2800 x (105/97) = 3030 psi
4.0
Relationship of Pump Pressure to Circulating Rate
The relationship between pump pressure and circulating rate is given by the formula below:
2
Equation A.7 New Pump Pressure = Old Pump Pressure x ( New Circ. Rate/Old Circ. Rate )
where:
New Pump Pressure & Old Pump Pressure (psi)
Circulating Rate (spm, gpm, or bpm)
Example:
Old Pump Pressure = 2800 psi
New Pump Speed = 60 spm
Old Pump Speed
= 80 spm
Calculate the new pump pressure for the slower pump rate?
2
New Pump Pressure = 2800 x (60/80) = 1575 psi
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5.0
Capacity Factors and Displacement
In well control and in routine drilling operations, frequent calculations of capacity and
displacement must be made. A brief review of the mechanics involved is provided below.
The capacity factor is defined as the volume of fluid held per foot of container. The
container may be any number of things including a mud pit, an open hole, the inside of a
drill string, or an annulus. Capacity factors change as the dimensions of the container
change. The internal capacity factor is used to calculate internal drillstring volumes and the
annular capacity factor is used to calculate annular volumes. The formulas for calculating
these capacity factors are given in Equations A.6 and A.7. In lieu of these equations,
Tables P.1 - P.4 can be used to determine internal and annular capacity factors for several
wellbore configurations.
Equation A.8
Internal Capacity Factor
ID2
CF
=
1029
where:
CF
ID
= Capacity Factor (bbl/ft)
= Internal pipe diameter (inches)
Equation A.9 Annular Capacity Factor
OD2 - ID2
CF
=
1029
where:
CF =
OD =
ID
=
Capacity Factor (bbl/ft)
Inside diameter of larger pipe (inches)
Outside diameter of smaller pipe (inches)
Capacity is the volume of fluid held within a specific container. Internal (drillstring)
and annular capacities are some of the most important parameters, which are
calculated in a well control situation. Capacity is determined by multiplying the height
(or length) of the container by its capacity factor.
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Displacement is the volume of fl uid displaced by placing a solid, such as drill pipe,
tubing etc., into a fixed volume of liquid. Total displacement of drillpipe, casing,
tubing, etc. can be determined by multiplying the length of pipe immersed times the
displacement factor (bbls/ft) as determined from Tables P.1 - P.4.
The volume of mud in the hole is always equal to the capacity of the entire hole,
minus the displacement of the pipe in the hole (assuming the pipe and annulus are
full). The annular capacity between drillstring components and the casing or hole can
be calculated by subtracting both the capacity and displacement of the drillstring
component from the capacity of the hole.
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SECTION B – CAUSES AND DETECTION OF KICKS
Table of Contents
1.0
Causes of Kicks................................................................................... B-2
1.1
2.0
Low Density Drilling Fluid............................................................. B-2
1.1.1 Gas Cutting ........................................................................ B-2
1.1.2 Oil or Saltwater Cutting........................................................ B-3
1.2
Abnormal Reservoir Pressure ....................................................... B-4
1.3
Swabbing ...................................................................................... B-6
1.3.1 Balled-Up Bottomhole Assembly .......................................... B-7
1.3.2 Pulling Pipe Too Fast .......................................................... B-7
1.3.3 Poor Mud Properties ........................................................... B-7
1.3.4 Heaving or Swelling Formations ........................................... B-7
1.3.5 Large OD Tools .................................................................. B-7
1.4
Not Keeping Hole Full................................................................... B-8
1.4.1 Use of Mud Log Unit ........................................................... B-8
1.4.2 Stroke Counter ................................................................... B-8
1.4.3 Pit Volume Monitoring ......................................................... B-8
1.4.4 Flowline Monitors ................................................................ B-9
1.5.
Lost Circulation ............................................................................ B-9
1.5.1 High Mud Weight ................................................................ B-9
1.5.2 Going into Hole Too Fast..................................................... B-9
1.5.3 Pressure Due to Annular Circulating Friction ......................... B-9
1.5.4 Sloughing or Balled-Up Tools ............................................ B-10
1.5.5
Mud-Cap Drilling............................................................... B-10
Detection of Kicks ............................................................................. B-13
2.1
Positive Indicators of a Kick ....................................................... B-13
2.2
Secondary Indicators of a Kick ................................................... B-13
2.3
Indicators of Abnormal Pressure ................................................ B-13
2.4
Increase in Pit Volume ............................................................... B-14
2.5
Increase in Flow Rate ................................................................ B-14
2.6
Decrease in Circulating Pressure ............................................... B-14
2.7
Gradual Increase in Drilling Rate ............................................... B-15
2.8
Drilling Breaks ........................................................................... B-16
2.9
Increase in Gas Cutting .............................................................. B-17
2.9.1 Drilled Gas ....................................................................... B-17
2.9.2 Connection Gas ................................................................ B-17
2.9.3 Trip Gas ........................................................................... B-17
2.10
Increase in Chlorides.................................................................. B-18
2.11
Decrease in Shale Density .......................................................... B-18
2.12
Change in Cuttings Size and Shape............................................ B-18
2.13
Increasing Fill on Bottom after Trips........................................... B-18
2.14
Temperature................................................................................ B-18
2.15
Increasing Rotary Torque ........................................................... B-19
2.16
Tight Hole on Connections ......................................................... B-19
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SECTION B – CAUSES AND DETECTION OF KICKS
1.0
Causes of Kicks
A kick is defined as any undesirable flow of formation fluids from the reservoir to the
wellbore, which occurs as a result of a negative pressure differential across the formation
face. Wells kick because the reservoir pressure of an exposed permeable formation is
higher than the wellbore pressure at that depth. There are many situations, which can
produce this unfavorable downhole condition. Among the most likely and recurring are:
•
•
•
•
•
Low Density Drilling Fluid
Abnormal Reservoir Pressure
Swabbing
Not Keeping the Hole Full on Trips
Lost Circulation
These causes will be examined in detail in this section with emphasis placed on the human
elements of avoidance.
1.1
Low Density Drilling Fluid
The density of the drilling fluid is normally monitored and adjusted to provide the
hydrostatic pressure necessary to balance or slightly exceed the formation pressure.
Accidental dilution of the drilling fluid with makeup water in the surface pits or the
addition of drilled-up, low density formation fluids into the mud column are possible
sources of a density reduction which could initiate a kick. Diligence on the mud pits is
the best way to insure that the required fluid density is maintained in the fluids we
pump downhole.
Most wells are drilled with sufficient overbalance so that a slight reduction in the
density of the mud returns will not be sufficient to cause a kick. However, any
reduction in mud weight during circulation must be investigated and corrective action
taken. A major distinction must be drawn between density reductions caused by gas
cutting and those caused by oil or saltwater cutting.
1.1.1
Gas Cutting
The presence of large volumes of gas in the returns can cause a
drop in the average density and hydrostatic pressure of the drilling
fluid. However, the appearance of gas cut mud at the surface usually
causes over concern, and many times results in unnecessary and
sometimes dangerous over-weighting of the mud. The reduction of
bottomhole pressure due to gas cutting at the surface is illustrated in
the Table B.1.
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Table B.1
Effect of Gas-Cut Mud on Bottomhole Hydrostatic Pressure
Pressure Reduction (psi)
75 PCF Cut to
135 PCF Cut to
37 PCF
121 PCF
51
72
86
97
31
41
48
51
Depth (ft)
1000
5000
10000
20000
135 PCF Cut to
67 PCF
60
82
95
105
Notice that the total reduction in hydrostatic pressure at 20,000 feet is only about 100
psi even though mud density is cut by 50 percent at the surface. This is because gas
is very compressible and a very small volume of gas, which has an insignificant
effect on mud density downhole, will approximately double in size each time the
hydrostatic pressure is halved. Near the surface, this small volume of gas would
have expanded many times resulting in a pronounced reduction of surface density.
It is interesting to note that most gas cutting occurs with an overbalanced condition
downhole. For example, if a formation containing gas is drilled, the gas in the pore
space of the formation is circulated up the hole along with the cuttings. The
hydrostatic pressure of the gas in a cutting is greatly reduced as it moves up the
annulus, allowing the gas to expand and enter the mud column. The mud will be gas
cut at the surface, even though an overbalanced condition exists downhole. If the
amount of ‘drilled gas’ is large enough, it is even possible that a well could be flowing
at the surface as the gas breaks out and still have an overbalanced condition
downhole. However, a flowing well is always treated as a positive indication
that the well has kicked, and the well should be shut in immediately upon its
discovery.
In a balanced or slightly overbalanced condition, gas originating from cuttings could
reduce the bottomhole pressure sufficiently to initiate a kick. Gradual inc reases in pit
level would be observed at first, but as the influx of gas caused by the
underbalanced condition arrives at the surface, rapid expansion and pit level
increase will occur. The well should be shut in and the proper kill procedure initiated.
When gas cut mud causes a hydrostatic pressure reduction large enough to initiate a
kick, the density of the mud being pumped downhole will usually not have to be
increased to kill the well. This can be verified by shutting-in the well and confirming
that the shut-in drillpipe pressure is zero.
1.1.2
Oil or Saltwater Cutting
Oil and/or salt water can also invade the wellbore from cuttings
and/or swabbing, reduce the average mud column density, and
cause a drop in mud hydrostatic pressure large enough to initiate a
kick. However, since these liquids are much heavier than gas, the
effect on average density for the same downhole volumes is not as
great.
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Also, since liquids are only slightly compressible, little or no
expansion will occur when circulating out these liquids. However, a
given mud weight reduction measured at the surface due to oil
and/or saltwater invasions will cause a much greater decrease in
the bottomhole pressure than a similar mud which is cut by gas.
This is because the density reduction is uniform throughout the
entire mud column when it is cut by a liquid.
1.2
Abnormal Reservoir Pressure
Formation pressure is due to the action of gravity on the liquids and solids contained
in the earth's crust. If the pressure is due to a full column of salt water with average
salinity for the area, the pressure is defined as normal. If the pressure is partly due to
the weight of the overburden and is therefore greater, the pressure is known as
abnormal. Pressures below normal due to depleted zones or less than a full fluid
column to the surface are called sub normally pressured.
In the simplest case, usually at relatively shallow depth, the formation pressure is
due to the hydrostatic pressure of formation fluids above the depth of interest. Salt
water is a common formation fluid and averages about 67 pcf or 0.465 psi/ft.
Therefore, 0.465 psi/ft is considered the normal formation pressure gradient.
Normally pressured formations are usually drilled with about 70 to 75 pcf mud in the
hole.
For the formation pressure to be normal, fluids within the pore spaces must be
interconnected to the surface. Sometimes a seal or barrier interrupts the connection.
In this case, the fluids below the barrier must also support part of the rocks or
overburden. Since rock is heavier than fluids, the formation pressure can exceed the
normal hydrostatic pressure. During normal sedimentation the water surrounding the
shale is squeezed out because of the addition of overburden pressure. The available
pore space, or porosity, will decrease and, therefore, the density per unit volume will
increase with depth. However, if a permeability barrier, or if rapid deposition prevents
the water from escaping, the fluids within the pore space will support part of the
overburden load, which results in above normal pressure. This scenario is depicted
in Figure B.1.
Figure B.1 Abnormally Pressured Sand Formation
Figure B.1 Abnormally Pressured Sand Formation
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Another common cause of abnormal pressure is faulting. As can be seen in Figure
B.2, a formation originally deposited under normal pressure conditions is uplifted
2,000 ft. The pressure within the uplifted section is trapped in the formation. The
pressure in the formation is now abnormal for that depth. There may be no rig floor
warning prior to drilling into an abnormal pressure zone of this nature.
Figure B.2
Abnormal
Pressure
Due To Due
Faulting
Figure
B.2 Abnormal
Pressure
To Faulting
Abnormal pressure can also occur as the result of depth and structure changes
within a reservoir. As shown in Figure B.3, at 3,000 ft, the formation pressure at the
gas-water contact is normal and equal to (0.465 psi/ft x 3,000 ft)=1,395 psi.
However, at the top of the structure (2,000 ft) the formation is overpressured and
approximately equal to 1,295 psi.
Figure B.3 Abnormal Pressure Due To Folding
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Example: The pressure at 3,000 ft (1,395 psi) less a 1,000 ft gas column (1,000' x .1
psi/ft) equals 1,295 psi. The mud weight required at 2,000 ft to balance this
formation is 1,295/(0.007 x 2,000') = 93 pcf.
Prior to drilling a particular well, all information regarding abnormally pressured
zones should be gathered and on hand for the drilling engineer. Seismic data can
often be helpful. Logs on nearby wells, along with the drilling reports of these wells,
should be studied. If the well is a rank wildcat in a new area, no knowledge of
pressures to be encountered may exist. In these cases pressure determination from
techniques such as plotting the ‘dc ’ exponent while drilling, and pore pressure
calculations from electric logs run in the well are invaluable. Other warning signs are
available while drilling and are discussed later in this section.
Usually, abnormally pressured formations give enough warning that proper steps can
be taken. As noted elsewhere in this guide, low mud weights provide the best
indication of abnormal or high-pressure zones. Once these zones are detected, it is
normally possible to drill into them a reasonable distance while raising the mud
weight as necessary to control formation fluid entry. However, when pressure due to
mud weight approaches the fracture gradient of an exposed formation, it is good
practice to set casing. Failure to do this has been the cause of many underground
blowouts and lost or junked holes.
If abnormal pressure zones are drilled with mud weights insufficient to control the
formation, a kick situation develops. This occurs when the pressure in the formation
drilled exceeds the hydrostatic head exerted by the mud column. A pressure
imbalance results and fluids from the formation are produced into the wellbore.
1.3
Swabbing
Swabbing is a condition, which arises when pipe is pulled from the well and
produces a temporary bottomhole pressure reduction. In many cases, the
bottomhole pressure reduction may be large enough to cause the well to go
underbalanced and allow formation fluids to enter the wellbore. By strict definition,
every time the well is swabbed in, it means that a kick has been taken. While the
swab may not necessarily cause the well to flow or cause a pit gain increase, the
well has produced formation fluids into the annulus, which have almost certainly
lowered the hydrostatic pressure of the mud column. Usually, the volume of fluid
swabbed in to the well is of an insignificant amount and creates no well control
problems (e.g., a small amount of connection gas). Many times however, immediate
action will need to be taken to prevent a further reduction in hydrostatic pressure,
which could cause the well to flow on its own.
It can be very difficult at times to recognize swabbing. The most reliable method of
detection is proper hole filling. If a length of drillpipe composed of five barrels of
metal volume is pulled from the well and the hole fill-up is only four barrels, a barrel
of gas, oil, or salt water has possibly been swabbed into the wellbore. If swabbing is
indicated, even if no flow is seen, the pipe should be immediately run back to bottom
the mud circulated out, and the mud densified or conditioned before making the trip.
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A short trip is often made to determine the combined effects of bottomhole pressure
reductions, which are due to the loss of equivalent circulating density and swabbing.
When drilling under or near balanced conditions, a short trip is particularly important
since it would quickly indicate a need to raise mud density or slow pulling speeds.
Expansion of swabbed gas or flow from the formation later during the trip can be
much more difficult to overcome, possibly requiring stripping back to bottom to kill
the well.
Many downhole conditions tend to increase the likelihood that a well will be
swabbed-in when pipe is pulled. Several of these are discussed below.
1.3.1
Balled-Up Bottomhole Assembly
The drill string becomes a more efficient piston when drill collars,
stabilizers and other bottomhole assembly components are balledup. This causes a greater bottomhole pressure reduction, which can
swab more fl uids into the wellbore. If the well is almost at balance,
only a few vertical feet of fluid swabbed-in can cause the well to flow
on its own.
1.3.2
Pulling Pipe Too Fast
The piston action is also enhanced when pipe is pulled too fast. The
driller should be sure that the pipe is pulled slowly off bottom for a
reasonable distance. However, the hole should be watched closely
at all times to be sure it is taking the correct amount of mud.
1.3.3
Poor Mud Properties
Swabbing problems are compounded by poor mud properties, such
as high viscosity and gels. Mud in this condition tends to cling to the
drill pipe as it moves up or down the hole, causing swabbing coming
out and lost circulation going in.
1.3.4
Heaving or Swelling Formations
Swabbing can result if the formations exposed either heave or swell,
effectively reducing the diameter of the hole and clearance around
the bit or stabilizers. In these formations even a clean bit acts like a
balled bit or stabilizer.
1.3.5
Large OD Tools
Drill stem testing tools, fishing tools, core barrels, or large drill collars
in small holes enhance swabbing by creating a piston action when
the pipe is pulled too fast. Extra care should be taken whenever
pulling equipment with close tolerances out of the hole.
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Good practices to prevent or minimize swabbing are aimed at keeping the mud in
good condition, pulling pipe at a reasonable speed, and using some type of effective
lubricant mud additive to reduce balling. Additives such as blown asphalt, gilsonite,
detergent, and extreme pressure additives are effective in many cases. Good
hydraulics will often help clean a balled-up bit or bottomhole assembly.
1.4
Not Keeping Hole Full
Blowouts that occur on trips are usually the result of either swabbing or not keeping
the hole full of mud. Much progress has been made in prevention, but constant
vigilance must be maintained. As drill pipe and drill collars are pulled from the hole
during tripping operations, the fluid level in the hole drops. In order to maintain fluid
level and mud hydrostatic pressure, a volume of mud equal to the volume of steel
removed must be pumped into the annulus. An accurate means of measuring the
amount of fluid required to fill the hole must be provided.
The volume of steel in a given length of collars can be as much as five times the
volume for the same length of drill pipe. The fluid level in the hole will also drop five
times farther, and the reduction in bottomhole pressure will be five times as great. If
the hole is normally filled after pulling fives stands of drill pipe, it may be necessary
to fill the hole after pulling each stand of drill collars. As a general rule, the hole
should always be filled on trips before the reduction in hydrostatic pressure
exceeds 75 psi .
It is the responsibility of the Drilling Foreman to see that the rig crews are thoroughly
trained in the necessity of keeping the hole full. Many mechanical devices have been
developed to aid in the task of keeping the hole full. These include:
1.4.1
Use of Mud Log Unit
These units are equipped with pump stroke counters, normally used
for correlating well cuttings with depth. Counters can also be used
during trips to aid in determining the proper amount of mud to keep
the hole full and to detect swabbing. However, the mud log crews
must be alerted to the need for this service during trips, when there
is no logging.
1.4.2
Stroke Counter
These counters mounted near the driller’s position enable him to
easily check his filling volume requirements. As the driller himself
operates them, there should be no communication problem.
1.4.3
Pit Volume Monitoring
Bulk mud volume checking is also very helpful, but large pits will not
show small changes; these can best be seen in a trip tank. The trip
tank should be near the rig floor and calibrated so the driller can
easily see and compare the volumes pumped into the hole vs. steel
pulled out. If the trip tank cannot be monitored from the floor, an
experienced crew hand should man it.
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1.4.4
Flowline Monitors
Besides monitoring flow while drilling, these devices detect fluid
immediately when the hole fills, so that a good comparison is
possible between pump strokes and returning fluid flow rate. Also,
these devices detect no-flow when lost circulation occurs. Their
proper use, in combination with other means, should prevent
blowouts due to not keeping the hole full or swabbing. As flowline
monitors can detect flow while the drill string is out of the hole, they
should be left on continuously.
1.5
Lost Circulation
An important cause of well kicks is the loss of whole mud to natural and/or induced
fractures and to depleted reservoirs. A drop in fluid level in the wellbore can lower
the mud hydrostatic pressure across permeable zones sufficiently to cause flow from
the formation. Some of the more common causes of lost circulation include:
1.5.1
High Mud Weight
If the bottomhole pressure exceeds the fracture gradient of the
weakest exposed formation, circulation is lost and the fluid level in
the hole drops. This reduces the effective hydrostatic head acting
against the formations that did not break down. If the mud level falls
far enough to reduce the BHP below the formation pressure, the well
will begin flowing. Thus, it is important to avoid losing circulation.
Should returns cease, loss of hydrostatic pressure can be minimized
by immediately pumping measured volumes of water into the hole.
Measuring the volumes will enable the drilling supervisor to calculate
what weight of mud the formation will support without fracturing.
Upon gaining returns, verify that the well is not flowing on its own.
1.5.2
Going into Hole Too Fast
Loss of circulation can also result from too rapid lowering of the drill
pipe and bottom assembly (drill collars, reamers, and bit). This is
similar to swabbing, only in reverse; the piston action forces the
drilling fluid into the weakest formation. This problem is compounded
if the string has a float in it and the pipe is large compared to the
hole. Particular care is required when running pipe into a hole having
exposed weaker formations and heavy mud to counter high
formation pressure.
1.5.3
Pressure Due to Annular Circulating Friction
Another item to be considered when drilling with a heavy mud near
the fracture gradient of the formation is the pressure added by
circulating friction. This can be quite large, particularly in small holes
with large drill pipes, or stabilizers inside the protective casing.
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It is sometimes necessary to reduce the pumping rate to lower the
circulating pressure. This problem can become acute when trying to
break circulation with high gel fluids.
1.5.4
Sloughing or Balled-Up Tools
Partial plugging of the annulus by sloughing shale can restrict the
flow of fluids in the annulus. This imposes a back pressure on the
formations below and can quickly cause a breakdown if pumping
continues. Annular plugging is most common around the larger
drillstring components such as stabilizers, so efforts to reduce
balling will also diminish the chances of this type of lost circulation.
1.5.5
Mud-Cap Drilling
In general, good operating practice calls for regaining circulation before
drilling ahead. However, in Saudi Aramco drilling operations there is one
notable exception, mud-cap drilling. Mud-cap drilling permits continued
drilling despite the presence of a pressured formation and a lost-circulation
zone in the same interval of open hole. Although mud-cap drilling has been
employed in a limited manner in other oil producing regions of the world,
Saudi Aramco is unique in the routine application of this methodology.
Drilling with a floating mud-cap involves drilling ahead blind (i.e., without
returns) by pumping different fluid densities down the drill string and annulus
simultaneously. All fluid is lost to the thief zone, the Shu’aiba. Figure B.4
illustrates this procedure, indicating the intervals exposed during the mudcap drilling operation. Employing a mud-cap in this manner provides the
option of cotinued drilling to the next casing point, if circulation cannot be
regained.
Note:
The practice of drilling with a mud cap through hydrocarbon bearing
reservoirs is not recommended, as a kick may not be controlled
from surface (resulting in an underground blowout).
Mud-cap drilling is utilized because the troublesome Cretaceous interval,
Wasia group and Shu’aiba must be penetrated before reaching pay in the
Jurassic Arab formation, Sections A, B, C, and D. The Wasia group consists
of a series of limestones, shales and sands. Some of these shales can be
extremely water sensitive. In addition, some permeable members of the
Wasia can be abnormally pressured. Compounding these drilling
complications is the Shu’aiba limestone, which underlies the Wasia group
and is subnormally pressured and extremely permeable. Given this situation,
conventional drilling practice would suggest running and cementing casing at
the top of the Shu’aiba, but employing mud-cap drilling permits drilling to
continue to the top of pay.
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As noted above, the shale members of the Wasia can be extremely water
sensitive. Contact with water or high fluid loss mud can cause them to swell
rapidly and slough, resulting in stuck pipe. Therefore, it is a drilling
imperative that water not be permitted to contact the Wasia shales. An
added complication is that some permeable sand members of the Wasia can
be abnormally pressured, requiring mud densities ranging between 75 pcf
and 100 pcf to contain them, with the norm around 90 pcf. This abnormal
pressure is evidenced by massive water flows. If unchecked, water flows
from the Wasia would produce sloughing of water sensitive shales situated
above and below the Wasia sand members. Since the Shu’aiba is
subnormally pressured, an inexpensive low-density fluid is all that is required
to drill it. In practice, fresh water (drill water) is used to drill through the
Shu’aiba, and a low-solids, non-dispersed mud is used to mud-cap the
Wasia. The mud-cap mud is virtually untreated and is thus relatively
inexpensive for its density. Ideally then, in mud-cap drilling water is the only
fluid to contract the Shu’aiba and mud-cap fluid is the only fluid to contact
the Wasia.
A brief description of the typical mud-capping procedure follows. As drilling
progresses, water is pumped down the drill pipe to remove cuttings from
beneath the bit and around the bottomhole assembly. These cuttings and
the water are lost to the lost circulation zone. Meanwhile, mud of a density
just sufficient to kill the pressured zone is pumped slowly into the annulus.
Thus, a critical balance of pressure control is maintained. In practice, 50
barrels of premixed mud-cap mud is pumped down the annulus as soon as
circulation is lost to the Shu’aiba. Drilling proceeds blind (i.e., no returns),
pumping water down the drill string and adding 10 barrels of mud-cap mud
down the annulus every hour. If either partial or complete returns are
regained while drilling, the pumps are shut down to determine whether the
Wasia is flowing or if partial circulation has been restored. If it is determined
that partial circulation is the case (i.e., the Shu’aiba is not taking all of the
drill water), the Shu’aiba is intentionally broken down by squeezing mud-cap
mud down the annulus to avoid drill water contacting any water sensitive
shales. On the other hand, if the well is flowing, the mud-cap is not providing
sufficient hydrostatic pressure on the Wasia. The remedy is either to
increase the density of the mud-cap mud or increase the frequency of
addition of mud down the annulus. This assumes the reduction of hydrostatic
pressure is due to greater losses of mud per hour into the Shu’aiba than
originally anticipated. Prior to any trip, the drill pipe is displaced with mudcap mud. During a trip, 10 barrels of mud-cap mud are added every 10
stands or every 30 minutes, whichever is less. While pipe is out of the hole,
10 barrels of mud-cap mud are pumped down the hole every hour.
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Mud-capping a well is a mix of art and science, requiring deligent monitoring.
If the pump rate down the drill string is too low, stuck pipe could result. Also,
if pump rates down either side are excessive, mud losses and mud
expenses can become prohibitive. Conversely, if either injection rate is
insufficient, the well could kick. Fortunately, experience has defined the
general range of applicable pump rates for Saudi Aramco’s drilling
operations, as indicated in Fig. B.4.
Figure B.4 Mud Cap Drilling
During mud-cap drilling, all kicks or suspected kicks are handled by
increasing the injection rate of mud-cap mud down the annulus, squeezing if
necessary. If the well is still not dead at surface, the density of the mud-cap
mud is increased until the well is killed at surface. Naturally, any water flows
(i.e. kicks) simply flow into the Shu’aiba lost circulation zone. This practice
has been used extensively over the years and has been demonstrated to be
quite safe.
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2.0
Detection of Kicks
It is highly unlikely that a blowout or a well kick can occur without some warning signals. If
the crew can learn to identify these warning signals and to react quickly, the well can be
shut in with only a small amount of formation fluids in the wellbore. Smaller kick volumes
decrease the likelihood of damage to the wellbore and minimize the casing pressures.
Kick indicators are classified into two groups; positive and secondary. Any time the well
experiences a positive indicator of a kick, immediate action must be taken to shut in the
well. When a secondary indicator of a kick is identified, confirmation steps should be taken
to verify if the well is indeed kicking.
2.1
Positive Indicators of a Kick
The “Positive Indicators of a Kick” are shown to
the left. Immediate action should be taken to
shut-in the well whenever these indicators are
experienced. It is not recommended to check
for flow after a positive indicator or has been
identified.
Positive Indicators of a Kick
→ Increase in Pit Volume
→ Increase in Flow Rate
2.2
Secondary Indicators of a Kick
The “Secondary Indicators of a Kick” are shown
to the left. The occurrence of any of these
indicators should alert the Drilling Foreman that
the well may be kicking, or is about to kick.
These indicators should never be ignored.
Instead, once realized, steps should be taken to
determine the reason for the indication
(indicating a flow check if necessary).
Secondary Indicators of a Kick
→
→
→
→
→
Decrease in Circulating Pressure
Gradual Increase in Drilling Rate
Drilling Breaks
Increase in Gas Cutting
Increase in Water Cutting or Chlorides
2.3
Indicators of Abnormal Pressure
Indicators of Abnormal Pressure
→
→
→
→
→
→
“Indicators of Abnormal Pressure” are shown to
the left. Observance of any of these indicators
often means that the well is penetrating an
abnormally pressured formation. Remedial
action may range from increasing the mud
weight to setting casing.
Decrease in Shale Density
Change in Cuttings Size and Shape
Increasing Fill on Bottom After a Trip
Increase in Flow Line Temperature
Increase in Rotary Torque
Increasing Tight Hole on Connections
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The following describe these indicators in detail and prescribe the proper remedial
action to take in the event of their occurrence.
2.4
Increase in Pit Volume
A gain in the total pit volume at the surface, assuming no mud materials are being
added at the surface, indicates either an influx of formation fluids into the wellbore or
the expansion of gas in the annulus. Fluid influx at the bottom of the hole shows an
immediate gain of surface volume due to the incompressibility of a fluid, (i.e., a barrel
in at the bottom pushes out an extra barrel at the surface). The influx of a barrel of
gas will also push out a barrel of mud at the surface, but as the gas approaches the
surface, an additional increase in pit level will occur due to gas expansion. This is a
positive indicator of a kick and the well should be shut in immediately any time
an increase in pit volume is detected.
All additions to the mud system should be done with the driller's knowledge. He
should also be told of each change in addition rate, particularly of water or barite.
Any change in valve settings, which could affect fluid into or out of the system,
should be noted and relayed to the driller. This is the only way to prevent
unnecessary shut in of the well. Again, the driller should always shut the well in first
and determine the reasons for a pit gain second.
2.5
Increase in Flow Rate
An increase in the rate of mud returning from the well above the normal pumping
rate indicates a possible influx of fluid into the wellbore or gas expanding in the
annulus. Flow rate indicators like the "FloSho" measure small increases in rate of
flow and can give warning of kicks before pit level gains can be detected. Therefore,
an observed increase in flow rate is usually one of the first indicators of a kick. This
is a positive indicator of a kick and the well should be shut in immediately any
time an increase in flow rate is detected.
Positive readings of a shut-in drillpipe pressure indicate that the well will have to be
circulated using the driller's or engineer's kill procedure. If the increase in flow was
due to gas expansion in the annulus, the shut-in drillpipe pressure will read zero
because no drillpipe underbalance exists.
2.6
Decrease in Circulating Pressure
Invading formation fluid will usually reduce the average density of the mud in the
annulus. If the density of mud in the drillpipe remains greater than in the annulus, the
fluids will U-tube. At the surface, this causes a decrease in the pump pressure and
an increase in the pump speed.
The same surface indications can be caused by a washout in the drillstring. To
verify the cause, the pump should be shut down and the well checked for flow.
If the flow continues, the well should be shut in and checked for drillpipe pressure to
determine whether an underbalanced condition exists.
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SECTION B – CAUSES AND DETECTION OF KICKS
2.7
Gradual Increase in Drilling Rate
While drilling in the normal pressured shales of a well, there will be a uniform
decrease in the drilling rate. This assumes that bit weight, RPM, bit types, hydraulics
and mud weight remain fairly constant. This decrease is due to the increase in shale
density. When abnormal pressure is encountered, the density of the shale is
decreased with a resultant increase in porosity. These higher porosity shales will be
softer and can be drilled faster. Therefore, the drilling rate will almost always
increase as the bit enters abnormally pressured shale. This increase will not be rapid
but gradual. A penetration rate recorder simplifies detecting such changes. In
development drilling, this recorder can be used with electric logs for the area to
pinpoint the top of an abnormal pressure zone before any other indicators appears.
In areas where correlation with other wells may be difficult, calculation and plotting of
the “d” exponent can be helpful in detecting abnormal pressure. The “d” exponent is
obtained from the basic drilling equation shown below. As penetration rate is affected
by mud weight, a correction for actual mud weight must be made. This correction is
made as shown in Equation B.1.
Equation B.1
‘d’ Exponent Equation
( )
R
Log
dexp
=
Log
60N
(
12W
1000 db
)
where:
R = Penetration Rate (ft/hr)
W = Weight on Bit (m-lbs)
Db = Bit Diameter (in)
N = Rotary Speed (rpm)
dexp = Drilling Exponent
Corrected
‘d’ Exponents
67
dc
=
x dexp : for Saudi Aramco
Actual Mud Weight
62
dc
=
x dexp : for Hard Rock
Actual Mud Weight
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Figure B.5 dc versus Depth
Plotting dc versus depth would result in a plot similar to the one shown in Figure B.5.
Where the plot shifted left would be where abnormal pressure was encountered. If a
mud logger is on location, he normally maintains a plot of this type.
2.8
Drilling Breaks
Abrupt changes in the drilling rate without changes in weight on bit and RPM are
usually caused by a change in the type of formation being drilled. A universal
definition of a drilling break is difficult, because of the wide variation in penetration
rates, types of formations, etB. Experience in the specific area is required. In some
sand-shale sequences, a break may be from 10 ft/hr to 50 ft/hr, or perhaps from 5
ft/hr to 10 ft/hr. In any case, while drilling in expected high-pressure areas, if a
relatively long interval of slow (shale) drilling is suddenly interrupted by faster
drilling, indicating a sand, the kelly should be picked up immediately, the
pump is shut off, and the hole observed for flow.
Very fast flow from the wellbore can result if permeability is high and mud weight is
low. Then the well must be shut in immediately. If the permeable sand formation has
only slightly higher pressure than the mud, flow may be difficult to detect. If there is
doubt and drilling is in an expected pressure area, it may be best to circulate the
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SECTION B – CAUSES AND DETECTION OF KICKS
break to the surface. If the sand is abnormally pressured, the gassy mud nearing the
surface will expand, causing a rise in pit level. It may be necessary to control this
expansion through the choke manifold, with the blowout preventer closed, then
increase the mud weight before drilling ahead.
2.9
Increase in Gas Cutting
A gas detector or hot wire device provides a valuable warning signal of an impending
kick. These instruments measure changes in the relative amounts of gas in the mud
and cuttings, but do not provide a quantitative value. Increases in the gas content
can mean increase in gas content of the formation being drilled, gas from cavings
and/or an underbalanced pressure condition. Gas in the drilling mud is reported in
several different ways.
2.9.1
Drilled Gas
This is the gas, which is entrained in the rocks, which are drilled. The drilled
(or background) gas will usually increase as the bit penetrates abnormally
pressured shale. Abnormally pressured shale gas will continue to feed in
after all drilled-up gas has been removed from the mud. Occasionally drilled
gas will be slow to drop out, but will finally do so if the mud weight is high
enough to control the formation pressure.
2.9.2
Connection Gas
Connection gas is a measure of gas, which is either swabbed into
the hole while pulling up for a connection or as a result of the loss in
ECD while shutting the pumps off for a connection. It is reported in
total units observed. Connection gas can be identified by estimating
the time to pump mud from the bottom of the hole to the surface and
checking the gas detector recording at that time. The connection gas
will almost always increase when an abnormal pressure zone is
penetrated. At low mud weights, the gas increase will be gradual.
That is, one connection may show 20 units; the next, 30 units; and
the third, 40 units. Mud weight increases may be necessary, even
though there may be little or no change in background gas.
2.9.3
Trip Gas
The trip gas is very similar to connection gas except that it is a
measure of swabbed gas over an entire trip. Often a short trip of 1520 stands is made in order to circulate bottoms up and measure
units of swabbed gas. Excessive units of trip gas could indicate the
need for increasing the trip margin and/or reducing swab pressure.
Failure to fill the hole on trips may also cause an increase in trip gas.
The trip gas will generally increase when an abnormal-pressure
section has been penetrated and the mud weight has not been
raised. This alone is not a good indicator for abnormal pressure but
is useful with the other indications. Trip gas should be reported as
the total units observed.
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SECTION B – CAUSES AND DETECTION OF KICKS
2.10 Increase in Chlorides
Invasion of the drilling mud by formation water can sometimes be detected by
changes in the average density or the salinity of the mud returning from the annulus.
Depending on the density of the mud, dilution with formation water will normally
reduce average density. If the density of the invading fluid is close to that of the mud,
the density would be unaffected, but perhaps a change in salinity will be apparent.
This would depend on the salinity contrast between the formation fluid and the mud.
Usually formation fluids are saltier than drilling muds and an influx can be detected
by marked increases of chloride content of the mud filtrate. Chloride changes alone
are not a good indicator of abnormal pressures but can be used in conjunction with
other indicators to present a clearer picture.
2.11 Decrease in Shale Density
The shale density will generally decrease when an abnormal pressure zone is
penetrated. This indicator would be good if it were possible to consistently select
cutting samples and accurately measure their bulk densities. This decrease in
density is a result of an increase in the water content within the shale.
2.12 Change in Cuttings Size and Shape
The amount of shale cuttings will usually increase, along with a change in shape,
when an abnormal pressure zone is penetrated. Cuttings from normal pressured
shales are small with rounded edges and are generally flat, while cuttings from an
abnormal pressure often become long, splintery with angular edges. As the
differential between the pore pressure and the drilling fluid hydrostatic pressure is
increased, the pressured shales will explode into the wellbore rather than being
drilled up. This change in shape, along with an increase in the amount of cuttings
recovered at the surface, could be an indication that the mud hydrostatic pressure is
too low and that a kick could occur while drilling the next permeable formation.
2.13 Increasing Fill on Bottom After Trips
Increasing fill on bottom after a trip, accompanied by an increase in trip gas, may
indicate abnormally pressured shale. This condition can also be created by not filling
the hole or poor mud properties during a trip, so it is not conclusive by itself.
2.14 Temperature
Flow line temperature often increases before an abnormal pressure zone is
penetrated. This has been observed in many parts of the world, but can be tricky.
Temperature also increases temporarily with the addition of barite or caustic, and by
changes in hydraulics, such as hole size. Sharp, stable increases in temperature,
possibly indicating abnormally pressured shale, are best seen on a relatively largescale depth vs. temperature plot.
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SECTION B – CAUSES AND DETECTION OF KICKS
2.15 Increasing Rotary Torque
Torque sometimes increases when an abnormal shale section is penetrated due to
the pressured shales above the bit continuing to explode into the hole.
2.16 Tight Hole on Connections
A tight hole when making connections can indicate that abnormally pressured shale
is being penetrated with low mud weight. Often the hole must be reamed several
times before a connection can be made. Failure to suspect abnormal pressure when
this occurs could lead to the drill pipe sticking or a blowout if drilling is continued
without taking some corrective action.
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SECTION C – TRIPPING PROCEDURES
Table of Contents
Introduction ................................................................................................ C-2
1.0 Pulling Out of Hole (Tripping Out) .................................................... C-2
1.1
1.2
2.0
3.0
4.0
General Information .........................................................................................C-2
Procedures .......................................................................................................C-3
Running in the Hole (Tripping In)...................................................... C-4
2.1 General Information .........................................................................................C-4
2.2 Procedures .......................................................................................................C-4
Trip Sheet............................................................................................ C-6
Capacities and Displacements.......................................................... C-7
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SECTION C – TRIPPING PROCEDURES
Introduction
When running in and out of the hole with drill pipe (Tripping In and Out), it is essential to
monitor the volume of fluid that is put in or removed from the hole through use of the trip
tank. By comparing the drill pipe displacement volume with the mud volume, loss
circulation or formation influx (kick) can be identified. See Section J of this manual for
further information on trip tanks.
1.0
Pulling Out Of Hole (Tripping Out):
Prior to Tripping Out, ensure that the trip tank is about 75% to 85% full and note the
volume on the gauge. Also, have a trip sheet available and ready to be filled out. All
calculations of drill pipe and collar displacements should be done in advance of
pulling operations. The major concern in pulling drill pipe out of hole is the possibility
of taking a kick as a result of swabbing or not filling the hole properly.
1.1
General Information
1) When pulling the drill string out of hole, be aware of the hole fill-up
difference between the drill pipe and the drill collars.
2) As a general rule, industry standards and various government regulations
call for checking the trip tank volume after 5 stands for drill pipe, 3 stands
for heavy weight drill pipe and every stand for drill collars or when the
hydrostatic mud column pressure is reduced by 75 psi.
3) Leave drill pipe wiper rubber off pipe for first five stands to observe hole.
4) Since most fluid influxes or kicks occur during pulling the first 10 stands, it
is important for the Drilling Foreman or Contract Toolpusher witness the
operation. For more critical tripping out operations in high angle wells, the
supervisors should be on the rig floor until the drill pipe is pulled into the
casing.
5) If the well kicks at any time during the tripping operations, immediately
shut in the well using the correct shut-in procedures and record the
pressure build-up on the drill pipe and casing. Do not run back to bottom if
a kick is suspected or detected. Industry experience has shown that this
practice is unsafe and can result in losing the rig.
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SECTION C – TRIPPING PROCEDURES
Note: 5 stands of 5” 19.5#/ft. drill pipe pulled from 9-5/8”, 53.5 #/ft. casing will lower
the fluid level 56’ if there is no loss to or gain from the hole and the float is
working properly. For example: 0.007645 bbl/ft. displacement in 0.070765
bbls/ft. capacity, (0.070765 – 0.007645)/0.007645 = 8.26’ of drill pipe pulled
per foot of fluid drop in casing and inside drill pipe.
1.2
Procedures
1) Prior to pulling out of hole,
a) Ensure suitable safety valves and crossovers are available on the rig
floor, including a closing/opening wrench.
b) Condition the mud and perform a flowcheck to ensure the well is dead.
Duration of the flowcheck will vary according to formation and mud
characteristics but should be long enough to ensure the well is dead.
If the hole is taking fluid and is open to a potential hydrocarbon
producing zone, obtain approval from the Superintendent prior to
pulling out of hole.
2) Pull out of hole with the drill string and record the Trip Tank gauge data on
the Trip Sheet (Page C-7) every 5 stands for drill pipe, 2 stands for heavy
weight drill pipe and every stand for the drill collars. The hole is
continuously and automatically being filled by the trip tank pump.
3) Check the Trip Sheet data often to ensure the well has not taken a kick.
This is done by comparing the amount of mud required to fill the hole with
the displacement volume of the pulled string.
4) While tripping out, refill the trip tank with mud and record the new volume
when the trip tank mud volume becomes low or when there is a break in
the operations. Do not trip pipe while filling the trip tank.
5) Perform a flowcheck at the casing shoe and just before pulling into the
BOPs with the bottom hole assembly.
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SECTION C – TRIPPING PROCEDURES
2.0 Running into the Hole (Tripping In):
Prior to Tripping In, ensure that the trip tank is empty and that the trip tank gauge is
functioning properly, set at “0”. Also, have a trip sheet available and ready to be
filled out. All calculations of drill pipe and collar displacements should be done in
advance of tripping operations. The major concerns in running drill pipe in hole are:
1) The possibility of breaking the formation down due to surging, losing mud
column and thus taking a kick, and
2) If a small gas bubble is slowly moving up the hole, the running of drill
collars through it will cause the bubble to string out, displace mud out of
hole, lower the hydrostatic pressure and cause a kick.
2.1
General Information
1) When running the drill string into the hole, be aware of the hole fill-up
difference between the drill pipe and the drill collars.
2) As a general rule, industry standards and various government regulations
call for checking the trip tank volume after every 5 stands for drill pipe, 3
stands for heavy weight drill pipe and every stand for drill collars.
3) If the well kicks at any time during the tripping operations, immediately
shut in the well using the correct shut-in procedures and record the
pressure build-up on the drill pipe and casing. Do not run back to bottom if
a kick is suspected or detected. Industry experience has shown that this
practice is unsafe and can result in losing the rig.
2.2
Procedures
1) Run into hole at approximately 1 stand per minute while filling the drill
string every 10 to 20 stands or when there is a break in the operation. For
casing, fill hole every joint while running in hole and top off every 10 joints.
2) Control tripping speed to prevent excessive surge pressure. If potential for
loss circulation or excessive fluid loss exists, break circulation (as often as
required) prior to reaching the potential loss zone.
3) While running in hole, record the Trip Tank gauge data on the Trip Sheet
every 5 stands for drill pipe, 2 stands for heavy weight drill pipe and every
1 stand for drill collars, and ensure the absence of loss circulation or kick
every 10 stands. The mud in the hole is continuously unloaded as the drill
string is run in hole.
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SECTION C – TRIPPING PROCEDURES
4) While tripping in, empty the trip tank when getting full or when there is a
break in the operations. Do not trip pipe while emptying the trip tank.
5) Check the Trip Sheet data often to ensure the well does not lose
circulation or kick. This is done by comparing the amount of mud filling the
trip tank with the displacement volume of the string in hole.
6) Once on bottom, circulate mud only if hole conditions dictate.
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3.0
TRIP SHEET
RIG:__________ Well No: ______________
________________________________________________________________________________________________________________________
________
Tripping:
In
Out
Depth: ____________
String Size &
Type
Total
Stands
Driller: _____________________ Date: ___________
Hole Size: __________
Displacement
Bbls/foot
Dry
Wet
Start Time: __________
Trip Tank Increments: _____bbls/inch
Displacement/Std.
Bbls/93 feet
Dry
Wet
Displacement/5 Stds.
Bbls/465 feet
Dry
Wet
Capacity
Bbls/ft.
3-1/2” DP
5”
DP
5-1/2” DP
3-1/2” HWDP
5”
HWDP
5-1/2” HWDP
4-3/4” DC
6-1/4” DC
8-1/2” DC
9-1/2” DC
COMPARISON BETWEEN ACTUAL AND CALCULATED STRING DISPLACEMENT
(A)
Stands
(B)
String Size
& Type
(C)
Trip Tank Gauge
Reading (bbls)
(D)
Actual Mud from
Trip Tank
(bbls)
(E)
Calculated
(bbls)
(F)
Difference
(D) – (E)
(bbls)
(G)
Running
Total
(bbls)
TOTAL
Tripping In or Out: If column (F) is negative, well is taking a kick (influx). If column (F) is positive, well is losing
circulation.
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4.0 Capacities and Displacements
Pipe
Tubular
Type
Size
inches
Weight
lbs/ft.
Capacities and Displacements
Displacement
bbl./ft.
Coupling & Thread
Displacement
bbls/93. ft. stand
Tubing *
Capacity
bbl./ft.
2-3/8
4.7
8rd, EUE
0.0016
0.1488
0.0039
2-7/8
6.5
8rd, EUE
0.0022
0.2046
0.0058
3-1/2
9.3
8rd, EUE
0.00320
0.2976
0.0087
3-1/2
12.95
L-80, PH-6
0.00455
0.4232
0.0074
Drill Pipe
2-3/8
6.65
0.0028
0.298
0.0032
3-1/2
13.3
0.0049
0.456
0.0072
5
19.5
0.0076
0.707
0.0177
5
26.5
0.0098
0.911
0.0153
5-1/2
24.7
0.0095
0.8835
0.0208
HWDP
3-1/2
25.6
0.0092
0.8556
0.0042
5x3
50
0.0184
1.710
0.0087
5-1/2
64.2
0.0203
1.888
0.0091
Drill Collars
3-1/2 x 1-1/2
0.0097
0.0022
4-3/4 x 2
0.0181
0.0039
6-1/4 x 2-7/8
0.0330
0.0080
7-1/4 x 2-1/4
0.046
0.0049
8-1/4 x 2-1/2
0.0583
0.0061
8-1/2 x 2-7/8
0.0613
0.0080
9-1/2 x 2-1/2
0.0884
0.0061
10 x 3
0.0884
0.0087
Casing *
24
176
X42,RL4S
0.0616
0.4971
24
97
GR-B, SJ
0.0344
0.5251
18-5/8
115
K55, BTC
0.0418
0.2953
18-5/8
87.5
K55, BTC
0.0307
0.3062
13-3/8
86
95HS, NS-CC
0.0302
0.1399
13-3/8”
72
95HS, NS-CC
0.0257
0.1480
13-3/8
68
J/K55,BTC
0.0241
0.1497
13-3/8”
61
J/K55,STC
0.0216
0.1521
9-5/8
58.4
110HS, NS-CC
0.0209
0.0691
9-5/8
53.5
90HSS, NS-CC
0.0192
0.0707
9-5/8
47
L-80,LTC
0.0168
0.0732
9-5/8
43.5
L80, LTC
0.0155
0.0744
9-5/8
40
J/K55, L80 LTC
0.0142
0.0758
9-5/8
36
J/K55, LTC
0.0127
0.0773
7
35
L-80, LTC
0.0126
0.0350
7
35
L-80, New VAM-MS
0.0126
0.0350
7
32
C-95VTS, New VAM-MS
0.0115
0.0361
7
32
NT-95HSS, NS-CC
0.0115
0.0361
7
26
J/K55, New VAM-MS
0.00934
0.0382
7
26
J/K55, LTC
0.00934
0.0382
7
23
J55, LTC
0.00823
0.0393
5-1`/2
20
95HSS,NS-CC
0.00721
0.0221
5
15
L80, 13CR, BTC
0.00541
0.0188
5
15
K55, BTC
0.00541
0.0188
4-1/2
13.5
95HSS, NS-CC
0.00474
0.0149
4-1/2
11.6
J-55, OLD VAM
0.00413
0.0155
4-1/2
11.6
J-55, STC
0.00413
0.0155
Open Hole
34
1.1230
30
0.8743
28
0.7616
24
0.5595
22
0.4702
17-1/2
0.2975
17
0.2807
12-1/4
0.1458
12
0.1399
10-3/4
0.1123
8-1/2
0.0702
8-3/8
0.0681
6-1/8
0.0364
6
0.0350
5-7/8
0.0335
* Displacement figures for tubing and casing do not include connections. Displacement figures for DP and HWDP include tool joints.
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SECTION D – SHUT-IN PROCEDURES
Table of Contents
1.0
2.0
3.0
Minimize the Size of the Influx ........................................................... D-2
Shut-In Procedure while Drilling ....................................................... D-3
Post Shut-In Procedure while Drilling ............................................. D-3
3.1
3.2
3.3
3.4
3.5
4.0
5.0
6.0
7.0
8.0
9.0
Shut-In Casing Pressure (SICP) ...................................................... D-3
Shut-In Drillpipe Pressure (SIDP).................................................... D-4
Pit Gain ........................................................................................... D-4
Time ................................................................................................ D-4
Closing Pressure ............................................................................ D-4
Shut-In Procedure while Tripping ..................................................... D-4
Post Shut-In Procedure while Tripping ........................................... D-6
5.1
Shut-In Casing Pressure (SICP) ...................................................... D-6
5.2
Pit Gain ........................................................................................... D-6
5.3
Time ................................................................................................ D-6
5.4
Bit Depth ......................................................................................... D-6
5.5
Well Control Options for Ki ck w/Bit off Bottom .............................. D-7
Bumping the Drillpipe Float................................................................ D-8
Understanding SICP and SIDP........................................................... D-9
Differential Pressure Sticking .......................................................... D-10
Failure of Blowout Prevention Equipment ................................... D-10
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SECTION D – SHUT-IN PROCEDURES
1.0
Minimize the Size of the Influx
Early recognition of a kick and rapid shut in are the keys to effective well control. By taking
action quickly, the amount of formation fluid that enters the wellbore and the amount of
drilling fluid expelled from the annulus are minimized. As Figure D.1 illustrates, smaller
kicks provide lower initial shut-in casing pressure and lower maximum casing pressures
while circulating out the kick. This translates to lower casing shoe pressures at all points
during the circulation and reduces the chance of formation breakdown and an underground
blowout.
Note: The larger the influx, the higher the casing pressures; therefore, minimize
the size of the influx.
Figure D.1
Effect of Influx Size on Casing Pressure
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SECTION D – SHUT-IN PROCEDURES
2.0
Shut-In Procedure while Drilling
Drilling crews must be alert while drilling ahead and be on the lookout for indicators that the
well is kicking or that the bit is penetrating abnormal pressure. (These items were
discussed in detail in Section C). The well must be shut in immediately when there is a
positive indicator of a kick in the form of an increase in pit volume or flow rate. If a
secondary indicator of a kick is recognized then the well should be checked for flow
before shutting in.
Shut-in Procedure while Drilling
(1)
SPACE OUT
Pick up drill string and spot tool joint.
(2)
SHUT DOWN
Stop the mud pumps.
(3)
SHUT IN
Close the annular preventer or uppermost pipe ram
preventer. Confirm that the well is shut in and flow has
stopped. Open HCR valve.
The person most likely to shut in the well is the Driller. The Saudi Aramco Drilling Foreman
must make sure that the driller is trained and will be able to take the initiative to perform
this important function on his own without prompting or assistance. After the well is
securely shut in, the Driller should notify the Drilling Foreman and Contract Tool pusher. At
this time, all members of the drilling crew should be at their pre-determined stations
awaiting further instructions.
Saudi Aramco requires a Hard Shut-in Procedure. This means that the choke line
valves on the drilling spool are in the closed position while drilling and remain
closed until after the preventer is sealed and well shut-in. In the ‘soft shut -in’
procedure, the choke line valves are opened to allow the well to flow through the surface
choke. After the preventers are sealed, the choke is then closed to stop the flow. The ‘soft
shut-in’ procedure gives the well additional time to flow before shut-in. Therefore, it is not
recommended because it doesn’t minimize the size of the influx.
3.0
Post Shut-In Procedures while Drilling
After the well has been shut in, the Drilling Foreman has several items to read and record.
These include:
3.1
Shut-In Casing Pressure (SICP)
Read and record the shut-in casing pressure. Valves on the drilling spool and choke
manifold will need to be lined-up so that wellbore pressure is transmitted to the
closed drilling choke. The shut-in casing pressure should be read from a gauge
installed upstream of the closed choke.
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SECTION D – SHUT-IN PROCEDURES
3.2
Shut-In Drillpipe Pressure (SIDP)
Read and record the shut-in drillpipe pressure. If no float is in the drillstring, this
pressure can be read directly from a pressure tap on the standpipe manifold. Since it
is recommended practice however, most drillstrings should have floats installed,
which will require bumping in order to determine the SIDP. The float bumping
procedure is given later in this section.
3.3
Pit Gain
Read and record the pit gain. The amount of influx is important for accurate
calculation of the maximum casing pressure. Pit level charts or other volume
totalizers can be examined to determine the pit gain.
3.4
Time
Make a note of the time the kick occurred. Also, keep an accurate log of the entire
kill operation as it progresses.
3.5
Closing Pressure
The proper amount of closing pressure will depend on the size and make of the
preventer and the wellbore pressure underneath. The closing pressure should be
high enough to prevent wellbore fluid from leaking by the element.
After this information has been gathered, the Drilling Foreman should notify his supervisor
to discuss the appropriate method for killing the well.
4.0
Shut-In Procedure while Tripping
Statistics indicate that the majority of kicks occur while tripping. Pulling out of the hole is a
critical operation, which warrants extra well control diligence by the drilling crews. This is
not the time to be lax about well control! Hole filling and hole monitoring equipment should
be in top condition so that a kicking well can be detected as early as possible. You should
prepare for a trip with the same intensity as you prepare to penetrate a known abnormal
pressure zone. Be prepared for the well to kick on every trip.
Every time a well is swabbed-in, it takes a mini-kick; formation fluids enter the wellbore as
a result of a negative pressure differential generated by the swabbing effect. The well may
not continue to flow after the pipe is stopped, but formation fluids have entered the annulus
and reduced the hydrostatic pressure. If the well continues to swab-in on successive
stands, then the hydrostatic pressure in the annulus may be sufficiently reduced to allow
the well to flow when the pipe is stationary. For this reason, any time swabbing is
indicated during a trip, the drillpipe should be run back to bottom and the well
circulated at least to bottoms-up.
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SECTION D – SHUT-IN PROCEDURES
Furthermore, any time the well is detected to be flowing during a trip, it must be shut in
immediately using the following "Three S" Shut-In Procedure:
Shut-In Procedure while Tripping
(1)
STAB VALVE
(2)
(3)
SPACE OUT
SHUT- IN
Install Full-Open Safety Valve (open position) in drill string.
Close Safety Valve.
Spot tool joint.
Close the annular preventer or uppermost pipe ram
preventer. Confirm that the well is shut-in and flow has
stopped. Open HCR valve.
Shut-In Procedure with BHA across Stack
(1)
(2)
(3)
(4)
(5)
(6)
SET SLIPS
INSTALL XO
STAB VALVE
Set slips on drill collars across BOP stack.
Install crossover to Full-Open Safety Valve.
Stab Full-Open Safety Valve (open position) in drill
string. Close Safety Valve.
SHUT –IN
Close annular. Confirm well is shut-in and flow is
stopped.
INSTALL INSIDE BOP Install inside BOP. Open Safety Valve.
MU DRILL PIPE
Make-up a stand of drillpipe. Reduce closing
pressure on annular and strip-in stand of drill pipe.
In the event of a failure in the annular (with BHA across BOP stack) and uncontrolled flow,
the emergency response should consist of dropping the BHA and shutting in the well with
blind rams.
Note:
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It is recommended that these Shut -In Procedures be followed even when the rig
is equipped with a top drive unit. The temptation would be to screw in the tope
drive unit instead of the safety valve hoping that it would be quicker and safer.
This can be problematic if it is necessary to strip and the float leaks. The manual
valve on the top drive unit will not necessarily be strippable and it may not be
possible to install the inside BOP on top of it.
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SECTION D – SHUT-IN PROCEDURES
5.0
Post Shut-In Procedures While Tripping
Taking a kick while tripping is a severe well control complication. Because there is no
steady-state while tripping, the data that was previously relied upon to kill the well may not
be valid. Nevertheless, after the well is securely shut in, the Drilling Foreman will need to
gather as much information about the wellbore condition as possible. These will include:
5.1
SICP
Read and record the shut-in casing pressure. Valves on the drilling spool and choke
manifold will need to be lined-up so that wellbore pressure is transmitted up to the
closed drilling choke. The shut-in casing pressure should be read from a gauge
installed upstream of the closed choke.
5.2
Pit Gain
Read and record the pit gain. The amount of influx is important for accurate
calculation of the maximum casing pressure. If a trip tank is in use and an accurate
trip log was being maintained, then the pit gain is simply the difference between the
present trip tank volume and the volume after the last fill-up, plus the volume of
metal pulled from the well since the last fill-up. If the hole was being filled out of the
active pits, which is not recommended, then determination of the kick volume is
much more difficult. Pit level charts or other volume totalisers can be examined in an
attempt to determine the pit gain in these instances.
5.3
Time
Make a note of the time the kick occurred. Also, keep an accurate log of the entire
kill and/or stripping operation as it progresses.
5.4
Bit Depth
Determine the bit depth from the Driller’s pipe figures. This number is important for a
variety of calculations and determinations discussed later in this section.
Note:
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It will usually not be necessary to record a value for the shut-in drillpipe
pressure. This is because the mud weight does not usually have to be
increased when a kick is taken during a trip unless the well is going to be
killed off-bottom. However, if a shut -in drillpipe pressure is taken, then
allowances must be made for the volume of drillpipe slug remaining in the
pipe. If this volume cannot be determined, then an accurate value for shutin drillpipe cannot be calculated.
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SECTION D – SHUT-IN PROCEDURES
5.5
Well Control Options for Kick with Bit Off Bottom
After the post shut-in information has been gathered, the Drilling Foreman should
consult with the Drilling Superintendent to determine the proper action to take in
controlling the well while off bottom. This will usually involve stripping, although
bullheading may be a consideration.
BULLHEADING
Consider bullheading if,
a)
b)
The kick was detected with the bit a considerable
distance off bottom.
Bullhead pressure does not exceed the MASP
(for casing burst, surface equipment limitations.
‘down weight’ of the drilling string in hole, or
leak-off pressure at casing shoe).
Bullheading will be discussed further in Section E.
STRIPPING
Consider stripping to bottom based on SICP, distance off
bottom, and available BOP stack as described below,
a)
SICP is 1000 psi or less, strip with annular
preventer.
b)
SICP is 1000-1500 psi and < 1000’ off bottom.
strip with annular.
c)
SICP is 1000-1500 psi and > 1000’ off bottom,
strip with annular and ram preventer combination.
d)
If SICP is 1500 psi or more, strip with ram
preventer combination.
Stripping procedure,
a)
b)
c)
Install Inside BOP
Open Safety Valve
Adjust hydraulic closing pressure to minimize
excessive wear in BOP elastomers.
d)
Bleed off appropriate annular volume per stand by
maintaining a constant SICP during stripping.
e)
f)
Fill drillpipe accordingly while stripping.
Kill well with Driller’s Method once on bottom.
Stripping will be discussed further in Section O.
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SECTION D – SHUT-IN PROCEDURES
6.0
Bumping the Drillpipe Float
If a drillpipe float is installed, the pressure gauge on the drillpipe will read near zero. In
order to obtain an accurate value for the shut -in drillpipe pressure, the float will have to be
bumped open by slowly pumping down the drillpipe. The correct procedure for bumping the
float is given below.
Float Bumping Procedure
(1)
Make sure the well is shut in and that the shut-in casing pressure is recorded.
(2)
Slowly pump down the drillpipe while monitoring both the casing and drillpipe
pressure.
(3)
The drillpipe pressure will increase as pumping is begun. Watch carefully for a
lull in the drillpipe pressure (a hesitation in the rate of increase) which will
occur as the float is pumped off of its seat. Record the drillpipe pressure when
the lull is first detected.
(4)
To verify that the float has been pumped open, continue pumping down the
drillpipe very slowly until an increase in the casing pressure is observed. This
should occur very soon after the lull was observed on the drillpipe gauge.
(5)
Shut down the pumps as soon as the casing pressure starts to increase and
record the shut -in drillpipe pressure as the previously recorded pressure at the
time of the lull in Step 3 above (not the final drillpipe pressure after the pumps
are stopped).
(6)
Check the shut-in casing pressure again. Any excess pressure may be bledoff in small increments until equal readings are observed after two consecutive
bleed-offs. Do not allow the casing pressure to drop below its original shut-in
value while bleeding back.
The float bumping procedure as described above can be difficult if the rig has big duplex
pumps which are compounded. It may be necessary to clutch the pumps in short bursts to
slowly build up pressure on the drillpipe. A drillpipe lull may never occur before the casing
pressure starts to increase when using this procedure. To determine the shut-in drillpipe
pressure in these instances, subtract the increase in shut-in casing pressure from the final
value of shut-in drillpipe pressure after the pumps have been stopped. Use this value as
the official shut-in drillpipe pressure.
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SECTION D – SHUT-IN PROCEDURES
7.0
Understanding SICP and SIDP
Shut-in surface pressures depend mostly on the amount of underbalance and the amount
and density of the influx of formation fluids. Shut-in drillpipe and casing pressure indicate
the difference between formation pressure and the hydrostatic pressures in the drillpipe
and annulus respectively. Both shut-in pressures are affected equally by the amount of
underbalance. More specifically, the greater the difference between formation pressure
and hydrostatic pressure, the larger will be the shut-in pressures.
Higher shut-in casing pressures can cause formation breakdown in this instance. In order
to decrease the likelihood of excessive downhole pressures and the resultant breakdown
at the casing seat, early detection and quick closure of the preventers are essential.
Normally, the shut-in casing pressure is greater than the shut-in drillpipe pressure because
of the low-density formation fluids in the annulus. In this case, the total hydrostatic
pressure in the annulus is less than that in the drillpipe, so it requires a higher shut-in
casing pressure to balance formation pressure. The difference in hydrostatic pressures
between the annulus and drillpipe depends not only on volume (height) of the influx, but
also on its density. The shut-in casing pressure for a gas kick is much higher than for a
saltwater and/or oil kick of equal volume.
Often, the shut-in drillpipe and casing pressures will read the same when the well is closed
in with the bit off bottom and all or most of the formation fluids are below the bit. In this
case, the reduction of hydrostatic pressure caused by the influx of low-density formation
fluids affects the drillpipe and casing pressures equally. A similar condition will occur with a
hole in the drillpipe and with all of the influx trapped below the hole.
When considering the effects of underbalance and size of influx on downhole pressure, the
position of the influx fluid in relation to the depth of interest must be considered. If the
depth of interest is above the kick, the full amount of the shut-in casing pressure must be
added to the mud hydrostatic pressure to that depth. If, however, the depth of interest is
within the interval of the kick or below, then the total effect of surface pressure on the depth
of interest is less. This also applies during the time that the kick fluid is circulated out of the
hole. For example, the shoe pressure at a shallow casing seat will normally increase while
circulating out a gas kick until the gas reaches the casing seat. At this point, the shoe
pressure will drop until the gas is in the casing. From this point, until all the gas is removed
from the annulus, the shoe pressure at the casing seat will be constant. The location of the
kick fluid in the annulus with respect to the depth of interest will determine the effect of
excessive casing pressure on the shoe pressure.
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SECTION D – SHUT-IN PROCEDURES
8.0
Differential Pressure Sticking
The drillstring can become stuck immediately after the well is shut -in on a kick. Sometimes
this can be attributed to collapse of the filter cake and/or wellbore caused by the presence
of formation fluids. More often, it is due to differential pressure sticking of the drillpipe in
lower pressured formations uphole.
Large shut-in casing pressures cause an increase in the wellbore pressures above the
influx. This serves to increase the pressure differential across permeable zones, which
leads to differential sticking. Do not work pipe during the kill operation in an attempt to
avoid differential sticking. Kill the well first and then address stuck pipe later, if required.
Reducing mud weight to pore pressure equivalent in order to free differentially stuck
pipe is against Saudi Aramco Policy. A minimum overbalance shall be maintained
during all operations as shown below,
•
•
•
9.0
100 psi overbalance on water reservoirs
200 psi overbalance on oil wells
300 psi overbalance on gas wells
Failure of Blowout Prevention Equipment
In case of a failure in the upper pipe rams, the bottom master pipe rams shall be
closed, repairs made to the upper rams, and well kill continued. Vulnerable rubber
parts (as bonnet seals, top seal, and ram packers) can fail under severe well conditions
(H2S, C02 and temperature). Replacement OEM parts must be on the rig site.
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SECTION E – WELL KILLING PROCEDURES
Table of Contents
1.0
2.0
Constant Bottomhole Pressure .................................................. E-2
The U-Tube Principle ................................................................... E-2
2.1
2.2
3.0
4.0
5.0
6.0
7.0
Basic Well Control Equations (Static Conditions) .............................E-3
Basic U-Tube Concept ..........................................................................E-4
The Driller’s Method .................................................................... E-6
The Engineer’s Method ............................................................... E-6
Comparison of the Methods ....................................................... E-8
Other Well Control Methods.......................................................E-10
6.1
The Volumetric Control Method.........................................................E-10
6.2
The Low Choke Pressure Method .....................................................E-10
6.3
Bullheading ..........................................................................................E-11
Underground Blowout ................................................................E-12
7.1
Barite Plugs .........................................................................................E-13
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SECTION E – WELL KILLING PROCEDURES
1.0
Constant Bottomhole Pressure
Saudi Aramco recommends two well killing methods; the Driller’s Method and the
Engineer’s Method. Both of these methods are discussed later in this section. These
methods are designed to remove the influx from the wellbore while maintaining a constant
bottomhole pressure equal to or slightly greater than the formation pressure. These
procedures prevent additional influx from entering the well while the kick is being circulated
out.
Constant bottomhole pressure is maintained by pumping at a constant kill speed and using
the drillpipe and casing pressure gauges to monitor the bottomhole pressure. The surface
pressures on both gauges are adjusted by manipulation of the drilling choke orifice size.
The constant bottomhole pressure method offers several advantages. It allows the person
controlling the kick to observe or to calculate pressures throughout the system. It provides
the minimum pressure needed to balance the reservoir pressure, which lessens the
chances for a second fluid influx, yet holds surface pressures low enough to prevent
formation breakdown and lost circulation.
All methods discussed in this guide, except for volumetric control, require circulation to
remove the influx and kill the well. In each case, efforts are made to maintain a constant
bottomhole pressure by adjusting the combination of surface and hydrostatic pressures. As
discussed in Section A 1.6, when circulating through a well, bottomhole pressure is
increased due to annular friction and is expressed as equivalent circulating density (ECD).
As the value of equivalent circulating density (ECD) is very difficult to calculate and can
vary greatly from one situation to another, the effect of equivalent circulating density (ECD)
is not taken into account in any of the methods. The point to remember is that equivalent
circulating density (ECD) will be in effect when performing these methods, thus holding
more back-pressure than required:
•
•
2.0
Is not necessary to prevent taking an additional influx
Could result in formation breakdown and lost circulation
The U-Tube Principle
A thorough understanding of the relationship between bottomhole pressure, casing
pressure and drillpipe pressure is necessary to effectively use the well control procedures
discussed in this volume. Perhaps the best way to illustrate this relationship is through the
concept of a U-tube.
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SECTION E – WELL KILLING PROCEDURES
Figure E.1 shows the cross section of two vertical tubes of the same size connected at the
base by a horizontal tube. When a fluid of uniform density is added to the system, the
levels will equalize in columns A and B. This assembly is often referred to as a U-tube
because its shape resembles the letter U. The U-tube is a convenient way to represent
conditions in the wellbore with drillpipe in the hole. The inside of the drillpipe can be
represented by column A and the annulus by column B. The opening at the base of the U
can be thought of as the opening through the nozzles in the bit. The pressure at the bottom
of column A is equal to the pressure at the bottom of column B, which can be thought of as
the bottomhole pressure.
Figure E.1
Simple U-Tube Analogy
2.1
Basic Well Control Equations (Static Conditions)
Two equations, provided earlier, are needed to understand and explain the concept
of the U-tube. These are shown again below.
Bottomhole Pressure = Hydrostatic Pressure + Surface Pressure
Hydrostatic Pressure = 0.007 x Mud Weight x True Vertical Depth
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SECTION E – WELL KILLING PROCEDURES
2.2
Basic U-Tube Concept
In all U-tubes where the fluid levels are static, the bottomhole pressure generated by
column A is equal to the bottomhole pressure generated by column B. This
relationship is stated mathematically as:
Basic U-Tube Concept
Hydrostatic Pressure (Column A) + Surface Pressure (Column A)
is equal to
Hydrostatic Pressure (Column B) + Surface Pressure (Column B)
is equal to
Bottomhole Pressure
U-tubes are rather boring when the same density fluid fills both columns. In this
instance, the hydrostatic pressure and surface pressure of both columns are equal.
Such is the case when a bit is run to the bottom of the hole and the drillpipe and
annulus are filled with the same weight drilling mud. The fluid levels remain static at
the top of the well, the surface pressure on both the casing and drillpipe side is zero,
and the hydrostatic pressure on the drillpipe side is equal to the hydrostatic pressure
on the casing side.
U-tubes get very interesting when fluids of different densities occupy both columns.
In these instances, both the hydrostatic pressure and surface pressure of both
columns are likely to be different. Such is the case when a kick is taken with the bit
on bottom. The well kicked because the bottomhole pressure was greater than the
hydrostatic pressure generated by the mud in the well. When the well is shut in, the
well stops flowing, and the amount of pressure under-balance is reflected as a
surface pressure on the drillpipe gauge. However, the fluid in the annulus is no
longer composed of drilling mud alone; it also includes lighter weight formation fluid,
which reduces the total hydrostatic pressure in the annulus. Therefore, the annulus
side is more under-balanced than the drillpipe side, so the resultant shut-in casing
pressure is higher than the shut-in drillpipe pressure. This effect is shown in Figure
E.2.
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SECTION E – WELL KILLING PROCEDURES
In Figure E.2, a 10,000 ft. well with 75 pcf mud has penetrated an over pressured
sand with a reservoir pressure of 5,740 psi and taken a 30 bbl kick. Since the
hydrostatic head of the 75 pcf mud is only 5,250 psi (10,000' x 75 pcf x 0.007 =
5,250 psi), the drillpipe is under-balanced by 490 psi which is reflected on the shut-in
drillpipe gauge and at the top of column A of the U-tube. The hydrostatic pressure on
the annulus side is equal to the sum of the hydrostatic pressure of the mud in the
annulus and the hydrostatic pressure of the gas in the annulus. Since 30 barrels of
annular mud has been displaced by the lighter weight gas, there is less total
hydrostatic pressure in the annulus than in the drillpipe. The hydrostatic pressure
generated by 30 barrels of mud is 140 psi more than the hydrostatic pressure
generated by 30 barrels of gas in this wellbore configuration. Therefore, the shut-in
casing pressure and the pressure at the top of column B is 140 psi higher than the
value indicated on the drillpipe gauge.
Figure E.2
Example of U-Tube Effect
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SECTION E – WELL KILLING PROCEDURES
3.0
The Driller’s Method
The Driller’s Method of well control requires two complete and separate circulations of
the drilling fluid in the well. The first circulation removes the influx from the annulus
using the mud density in the hole at the time of the kick. Casing pressure is held
constant until the pump is at kill rate. Then drillpipe pressure is held constant to maintain
bottomhole pressure equal to, or slightly greater than formation pressure. If the kick
contains gas, it will expand in the annulus under controlled conditions as it nears the
surface. Therefore an increase in casing pressure and pit volume should be expected.
Drillpipe pressure and pump rate must be held constant. At any time during or
immediately after this first circulation, the well can be shut in and the drillpipe pressure will
read the same as it did originally.
After the kick fluid has cleared the choke, the well can be shut in. At this time, shut-in
drillpipe and casing pressures will be the same, assuming all of the influx has been
removed and mud hydrostatic is the same inside the drillpipe and the annulus. The original
shut-in drillpipe pressure is converted to an equivalent density at the bit, and the mud
density is increased accordingly.
During the second circulation, bottomhole pressure is held constant by first
maintaining casing pressure equal to the shut-in value while filling the drillpipe with
the kill mud. When the drillpipe is filled, as determined by the number of strokes pumped,
the drillpipe pressure is recorded and control shifts to maintaining a constant drillpipe
pressure while the annulus is filled with heavy mud. When the kill mud reaches the
surface, the pressure on the choke should be minimal. The pumps can be stopped while
holding casing pressure constant and the well checked for flow.
Any time a well under pressure is circulated, the start-up and shutdown procedures are
critical and should be done with exceptional care. Whenever the pump speed is increased
or decreased (including start-up and shutdown) the casing pressure must be held constant
at the value it had immediately before the pump speed change was initiated. This ensures
that bottomhole pressure remains constant. This procedure is valid because casing
pressure should be the same whether the well is closed-in or being pumped. However, the
drillpipe pressure must vary depending upon the circulating pressure loss in the system,
which is a function of the pump speed. The casing pressure cannot be held constant for
very long though due to the changing height of the influx caused by the irregular annulus
and gas expansion.
4.0
The Engineer’s Method
The Engineer’s Method of well control requires only one complete circulation. The kill
mud is circulated at the same time the influx is removed from the annulus. After the well
has been shut in, the pressures recorded, and pit volume increase recorded, the mud
density in the pits is increased and a drillpipe pressure schedule is created. The schedule
must be prepared in order that drillpipe pressure can be properly adjusted downward as kill
mud fills the drillpipe. A sample drillpipe schedule with an internal drillpipe volume of 800
strokes is provided in Table E.1.
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Table E.1
Sample Drillpipe Pressure Schedule for the Engineer's Method
Strokes
Pumped
Drillpipe
Pressure
0
100
200
300
400
500
600
700
800
540
520
500
480
460
440
420
400
380
Comment
Well is shut in
100 strokes of kill mud pumped
Kill mud halfway to the bit
600 strokes of kill mud pumped
Kill mud reaches the bit
Once the kill mud reaches the bit, the drillpipe pressure should be held constant until kill
mud reaches the surface. Bottomhole pressure will be equal to, or slightly greater than
formation pressure throughout the procedure as long as pump rate is maintained at the
predetermined rate.
If the kick contains gas, it will expand in the annulus, under controlled conditions, as it
nears the surface. Therefore, an increase in casing pressure and pit volume should be
expected. However, the drillpipe pressure and pump rate must be held at the
predetermined level.
As with the Driller’s Method, any time a well under pressure is circulated, the start-up and
shutdown procedures are critical and should be done with exceptional care. A prior
paragraph on this topic warrants repeating here. Whenever the pump speed is
increased or decreased, (including start-up and shutdown) the casing pressure must
be held constant at the value it had immediately before the pump speed change was
initiated. This ensures that bottomhole pressure remains constant. This procedure is valid
because casing pressure should be the same whether the well is closed-in or being
pumped. However, the drillpipe pressure must vary depending upon the circulating
pressure loss in the system, which is a function of the pump speed. The casing pressure
cannot be held constant for very long though due to the changing height of the influx
caused by the irregular annulus and gas expansion.
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5.0
Comparison of the Methods
Both the Driller’s and Engineer’s Methods provide relative advantages and disadvantages,
depending on the general conditions of the area of operation or the specific conditions in
the subject well. The choice of kill method is determined through discussions between the
Drilling Foreman on location and the Drilling Superintendent.
Figures E.3 and E.4 illustrate a gas kick being circulated to the surface using both the
Driller’s and the Engineer’s Methods. Observing both figures, it is noted that when the gas
bubble reaches the casing shoe the Driller’s Method results in a surface casing pressure
which is higher than the initial casing pressure, whereas the Engineer’s Method is less. In
the Driller’s Method, the hydrostatic pressure in the annulus is reduced as the gas bubble
expands while being circulated out of the well. The bottomhole pressure is being held
constant; therefore, the surface casing pressure must increase. Since the hydrostatic
pressure above the shoe is the same as it was when the well was initially shut in, as long
as the bubble is below the shoe, the pressure at the shoe will be increased an amount
equal to the increase in the surface casing pressure plus any circulating friction generated
in the annulus above the shoe. This increase in pressure could be sufficient to cause a
formation breakdown at the shoe. Consequently, the maximum pressure at the casing
shoe occurs when the top of the bubble reaches the shoe if the Driller’s Method is
used.
Conversely, when the Engineer’s Method is used, the maximum pressure at the shoe
will generally occur when the kill mud reaches the bit.
Figure E.3
Removing Gas Influx with the Driller's Method
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Figure E.4
Removing Gas Influx with the Engineer's Method
Three exceptions to this are:
1) When the kick volume fills the well above the shoe.
2) When a small kick volume does not increase the casing pressure as it rises
into a larger annular area at the top of the collars by the time kill mud reaches
the bit.
3) Any time the top of the bubble reaches the shoe before the kill mud reaches
the bit.
The introduction of kill mud into the annulus through the bit increases the hydrostatic
pressure. In order to maintain constant bottomhole pressure, the surface pressure must be
reduced; therefore, the pressure at the shoe is reduced.
In both methods, once the top of the bubble reaches the shoe, the shoe pressure is
decreased until the bottom of the bubble rises above the shoe. Once the bottom portion of
the bubble rises above the shoe, the shoe pressure remains constant with the Driller's
Method but continues to decline until the kill mud reaches the shoe with the Engineer's
Method (provided bottomhole pressure is constant). Therefore, the pressure at the shoe
when using the Engineer’s Method will always be less than or equal to the shoe pressure
when using the Driller’s Method.
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A summary of the advantages and disadvantages of both methods is provided in Table
E.2.
Table E.2
Kill Method Comparison
6.0
Method
Advantages
Disadvantages
Driller’s
Simplicity, few calculations
Can be used until barite arrives.
Circulate quickly, reduce
sticking and gas migration.
Requires two circulations
Higher surface pressures
Higher casing shoe pressures
Engineer’s
One circulation required
Lower surface casing pressures
Lower casing shoe pressures
More complex calculations
Waiting may stick pipe
Waiting allows gas to migrate
Mud mixing capabilities
Other Well Control Methods
6.1
The Volumetric Control Method
This method is used when the pumps are inoperative or when the drillpipe is either
out of the hole, plugged, or has a hole in it. This is not a kill method but simply a
method of controlling bottomhole and surface casing pressures as the gas
migrates up the hole. The gas is allowed to expand as it migrates up the hole. A
(relatively) constant bottomhole pressure is maintained by bleeding off mud with an
equivalent hydrostatic head equal to the rise in pressure caused by the migrating
gas. The basis of the method is equating pit volume change and annulus pressure.
This procedure is discussed in detail later in this volume.
6.2
The Low Choke Pressure Method
This method is used if pressures threaten to become excessive while a well is
being killed. Choke pressure must be reduced sufficiently to prevent casing burst or
formation breakdown while circulating out. In kick situations requiring weight
increases, the mud weight should be increased as soon as practical. Kicks occurring
while drilling tight formations or after trips where tight formations have been drilled
may be circulated out using this method without increasing the mud weight.
It is important to realize that the formation will continue to flow until the combined
effect of the new kill mud, of light weight mud, and low choke pressure all balance
the formation pressure. Formations with high permeability cannot be effectively
killed by this method; the influx will exceed that controllable by even the maximum
rate used to circulate out the kick. The corresponding reduction of hydrostatic
pressure will prevent the killing of the well and possibly cause loss of the hole.
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Numerical analysis of the Darcy Equation indicates that this method is of
questionable value where formation permeabilities are greater than 200
millidarcys. This method should not be used when there is uncertainty about
formation permeability, and is therefore, not generally recommended.
6.3
Bullheading
If normal well killing techniques with conventional circulation are not possible
or will result in critical well control conditions, bullheading may be considered
as a useful method to improve the situation. Mud/influx are displaced/squeezed
back downhole into the weakest exposed open hole formation.
When to consider bullheading:
Bullheading may be considered when the following well control situations occur:
(1)
(2)
(3)
(4)
(5)
Rig personnel and equipment cannot handle H2S or high-pressure gas influx
safely.
Normal circulation is not possible because:
- Pipe has been sheared or no pipe in the hole
- String is off bottom
- String is blocked
- String is washed out or parted
A combined kick and losses situation is experienced (downhole annulus
bullhead rates must exceed the gas migration rate to ensure the situation does
not deteriorate further).
Kick calculations show that casing pressure during conventional kill operations
will probably result in a detrimental well control situation. (in this case, only the
influx needs to be squeezed back).
The casing is set near the reservoir, avoiding other loss zones, and reservoir
permeability is high, enabling lower bullhead pressures, as in Arab-D wells.
Bullheading is not a routine well control method. In many cases, it will be doubtful
whether the well can be killed by squeezing back the influx into the formation and
lost circulation may be induced by bullheading kill weight fluid immediately below the
shoe into the formation. The method should in most cases be considered only as a
last resort.
In some instances, bullheading will be considered as the prime method; in such
case, the choice of bullheading should be made clear in the well plan. Examples of
such cases are high pressure/high temperature or H2S wells, wells in populated
areas, killing of well after a well test, or before workover operations.
Prior to Bullheading
-
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Consider using the volumetric method to eliminate the complication of
migrating gas. If the gas can be largely removed this way, the bullheading
operation is likely to be much easier and more effective in killing the well.
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7.0
-
Pressure limitations of pumping equipment, wellhead equipment and
casing must be kept in mind throughout.
-
If a gas influx is suspected (shut in pressures continue to rise indicating
migrating gas), pumping rate for bullheading must be fast enough to
exceed the rate of gas migration. If pump pressures increase instead of
decreasing, it is an indication that the pumping rate is too low to be
successful. This can be a problem in large diameter holes. Note that
increasing the viscosity of the kill mud may or may not be helpful in
controlling this problem, and could possibly even make it worse.
-
There is often a chance, particularly with relatively long open hole
sections beyond the last casing shoe, that bullheading could
breakdown the formation at the shoe rather than at the producing
formation. In this event, rather than killing the well, this procedure may
aggravate the development of an underground blowout, which could pose
risks to nearby wells in communication with the formations involved. It
could also increase risk of a blowout around casing in place with
subsequent obvious risks. Thus, bullheading should be considered
when these associated risks are the lesser of the potential evils.
-
A check valve is recommended between the pumping unit and the well to
act as a failsafe valve in the event surface equipment should fail during the
procedure. If possible, the cementing unit should be used for better
control and adequate pressure rating.
-
Large mud volume and LCM pills should be available in case major losses
are experienced during the operation.
UNDERGROUND BLOWOUT
An underground blowout occurs when the formation fluid from one zone flows into another
(see Figure E.5). The most common cause is the breakdown of a weak formation during a
kick, either at the instant the BOPs are closed or while heavy mud is being circulated to kill
the kick. This is common when drilling below uncased, depleted formations.
The method of killing an underground blowout depends on many factors. Stuck drill pipe
will complicate the situation. If an underground blowout is even suspected, the first thing
that should be done is to locate the zones kicking and taking fluid. This can normally be
done with a temperature survey inside the drill pipe.
If the drill pipe is free, normally its end is near the zone that is kicking, usually at the bottom
of the hole. Sometimes circulating a very heavy mud pill between the two zones can shut
off the flow. The pill’s volume should exceed the hole volume between the two zones. It is
sometimes desirable to simultaneously pump mud down the annulus.
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Figure E.5
Underground Blowout
7.1
Barite Plugs
The most successful method of controlling a high rate underground blowout is to
spot a barite plug (approx. 150 pcf) just above the flowing zone. Course-ground
barite is better suited for this application than finer grind because of faster settling.
In extreme cases, several barite pills may be required to shut off the flow.
The barite plug consists of barite, water and lignosulfonate, and caustic soda. The
lignosulfonate deflocculates the slurry and allows settling of the barite to form a
plug in the wellbore. The caustic soda provides a high pH (10-11) environment for
the lignosulfonate to be effective.
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A typical formulation for a 150 pcf barite plug is as follows,
0.54
690
8
1
bbl water
lbs/bbl barite
lbs/bbl lignosulfonate
lbs/bbl caustic soda
Slurry volumes will depend on the open hole interval and severity of the kick.
Typical volumes range from 40 bbls to 400 bbls.
The following flow chart summarizes the operations involved in controlling an
underground blowout with barite plug(s) and cement. This method involves
cementing a section of the drillstring in place.
Figure E.6
Underground Blowout Operation
PUMP BARITE SLURRY
1.
2.
3.
4.
5.
OVER DISPLACE THRU BIT
PUMP ¼ BBL THRU BIT @ 15
MIN. INTERVALS
WAIT 6-10 HOURS
RUN TEMPERATURE SURVEY
WAIT 4 HOURS. RUN SECOND
SURVEY
WELL IS NOT FLOWING
1.
2.
3.
WELL IS FLOWING
SQUEEZE CEMENT SLURRY THRU
THE BIT. LEAVE SOME CEMENT IN
THE PIPE OR SET BRIDGE PLUG
PUMP IN DP
WOC & PRESSURE TEST
PERFORATE NEAR THE TOP OF
THE BARITE PLUG. ATTEMPT TO
CIRCULATE
WELL CIRCULATES
1.
2.
3.
1.
PUMP SECOND
BARITE SLURRY
WELL WILL NOT CIRCULATE
CIRCULATE CLEAR OF INFLUX
SPOT CEMENT SLURRY THRU
PERFORATION CUT DISPLACEMENT
SHORT OR SET BRIDGE PLUG IN DP
WOC & PRESSURE TEST
1.
2.
SQUEEZE CEMENT SLURRY THRU
PERFORATION. CUT DISPLACEMENT
SHORT OR SET BRIDGE PLUG IN DP
WOC & PRESSURE TEST
RUN FREEPOINT LOG. PERFORATE ABOVE FREEPOINT AND
CIRCULATE ANNULUS CLEAR
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SECTION F – PRE-RECORDED DATA SHEET
Table of Contents
1.0
2.0
Purpose of the Pre-recorded Data Sheet .......................................F-2
Using the Pre-recorded Data Sheet.................................................F-2
2.1
2.2
3.0
4.0
5.0
Well Data........................................................................................F-2
Hole Data ......................................................................................F-2
2.2.1 Hole Size Information...........................................................F-2
2.2.2 Hole MD and TVD................................................................F-3
2.2.3 Capacity Factor....................................................................F-3
2.3
Pump Data .....................................................................................F-3
2.3.1 Liners ..................................................................................F-3
2.3.2 Stroke .................................................................................F-3
2.3.3 Rod Size .............................................................................F-3
2.3.4 % Efficiency.........................................................................F-3
2.3.5 Bbl/stk.................................................................................F-3
2.4
Casing Data....................................................................................F-3
2.5
Wellhead or Casing Pressure Limitation........................................F-3
2.6
Liner Casing Data...........................................................................F-4
2.7
Drillstring Data ...............................................................................F-4
2.8
Internal Capacities.........................................................................F-4
2.9
Annulus Capacities........................................................................F-4
2.10
Maximum Initial SICP .....................................................................F-4
Well Data Sheet must be Current.....................................................F-5
3.1
Sections Fully Completed ............................................................F-5
3.2
Sections Partially Completed.........................................................F-5
3.2.1 Hole Data ............................................................................F-5
3.2.2 Internal Capacities ...............................................................F-5
3.2.3 Annulus Capacities ..............................................................F-5
Some Complicating Situations .........................................................F-6
4.1
Drilling Liner..................................................................................F-6
4.2
Tapered Drillstring .........................................................................F-6
Example Pre-recorded Data Sheet...................................................F-7
5.1
Vertical Well ...................................................................................F-7
5.2
Highly Deviated and Horizontal Well..............................................F-8
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SECTION F – PRE-RECORDED DATA SHEET
1.0
Purpose of the Pre-recorded Data Sheet
The Pre-recorded Data Sheet is an information reference, which lists the actual wellbore
capacities and volumes for a particular well. The data sheet is a critical well control
document, which must be kept as current and as accurate as possible. The Drilling
Foreman will need this information to complete the Engineer’s or Driller’s Method
worksheets should a kick occur.
The information displayed on the data sheet is used to calculate pumping volumes and
strokes and is therefore crucial to the successful completion of most well killing operations.
It is the expressed purpose of the data sheet to be filled-out when a gas kick is taken so
the information will be readily available in these situations. When the data sheet is filled out
ahead of time, the Drilling Foreman does not have to spend time figuring wellbore
capacities and volumes after a kick has occurred when time may be critical. Also, this gives
the Drilling Foreman extra time to double check the numbers for accuracy.
Note:
Therefore, it is strongly recommended that the data sheet be filled-out as
completely as possible at all times while drilling.
Much of the data on the data sheet does not change from day-to-day, so it is a simple
matter to keep the few changing items current. Many of the capacities and measurements
are easily memorized because they are used so frequently for other matters besides well
control. Nevertheless, memories can sometimes fail in pressure situations, so it is wise to
keep these numbers written down for everyone on the rig to refer to in a critical situation.
2.0
Using the Pre-recorded Data Sheet
The following descriptions relate important information about every entry blank on the data
sheet. Drilling Foremen should be guided by these descriptions to aid them in using the
form.
2.1
Well Data
The well data section is composed of the well name, field name, and rig name.
These items should be filled out completely.
2.2
Hole Data
2.2.1
Hole Size Information
Record the hole size as the diameter of the bit in the hole.
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2.2.2
Hole MD and TVD
These items are recorded after the well has kicked. It should take
only a short while to determine these values from the Driller’s pipe
figures and applicable survey data.
2.2.3
Capacity Factor
Record the capacity factor of the hole size listed above in bbls/ft.
(Use Ta ble P.4 for reference.) This is an approximation and does not
account for hole washout or actual casing diameter. Multiply this
number by the Measured Depth to determine the hole capacity
(bbls).
2.3
Pump Data
2.3.1
Liners
Record as the pump liner diameter (inches) for duplex or triplex
pumps.
2.3.2
Stroke
Record as the pump stroke (inches) for duplex or triplex pumps.
2.3.3
Rod Size
Record as the pump rod diameter (inches) for duplex pumps only.
2.3.4
% Efficiency
Record as the mechanical pump efficiency as determined by top
plug displacement during a cement job or by pumping into the trip
tank.
2.3.5
Bbl/stk
Use Table P.5 to determine the theoretical pump displacement and
multiply by % Efficiency above to determine the actual pump output.
2.4
Casing Data
Record the outside diameter, inside diameter, measured depth, and true vertical
depth of the last full string of casing in the ground.
2.5
Wellhead or Casing Pressure Limitation
Record as the lesser of:
a) 100% of wellhead pressure rating
b) 100 % of blowout preventer pressure rating
c) 80% of last casing string burst rating
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2.6
Liner Casing Data
Record the outside diameter, inside diameter, measured depth to top and vertical
depth to shoe of any liner casing in the ground.
2.7
Drillstring Data
Record the outside diameter (inches) and weight (lb/ft) of all drillpipe, heavyweight
drillpipe and drill collars in the string. This data should be reviewed and updated on
every trip in the hole.
2.8
Internal Capacities
Record the length of each drillstring component by its associated internal capacity
factor (bbl/ft). (Use Tables P.1 through P.3 for reference.) Treat bottomhole
assembly components (stabilizers, crossover subs, etc.) as drill collars for capacity
calculations. Calculate the total volume (bbls) for each component section by
multiplying the component length by its capacity factor. Since the length of drillpipe
will not be known until after the well kicks, the drillpipe capacity and total int ernal
capacity will have to be calculated after the kick. Check that the measured depth
indicated is equal to the sum of the individual component lengths.
Divide the total internal capacity (bbls) by the pump displacement (bbls/stk) to
determine these capacities in strokes.
2.9
Annulus Capacities
Record the length of each drillstring component and its associated annular capacity
factor in the given hole size. (Use Tables P.1 through P.3 for reference.) Treat
bottomhole assembly components (stabilizers, crossover subs, etc.) as drill collars
for capacity calculations. Calculate the annular capacity (bbls) opposite each
component section by multiplying the component length by the annular capacity
factor. Since the length of drillpipe will not be known until after the well kicks, the
annular capacity opposite the drillpipe and the total annular capacity will have to be
calculated after the kick. Check that the measured depth indicated is equal to the
sum of the individual component lengths. Finally, add the Total Internal Capacity to
the Total Annular Capacity to determine the Total System Capacity (not including the
active pit volume).
Divide the Total Annular Capacity (bbls) and the Total System Capacity by the pump
output (bbls/stk) to determine these capacities in strokes.
2.10 Maximum Initial SICP
The maximum casing pressure that will fracture the formation at the shoe upon shut
in can be determined by subtracting the present mud weight from the shoe test (in
pcf) and then multiplying this figure by the true vertical depth of the shoe and by
0.007. This formula is stated in equation form below:
MISICP = (Shoe Test, pcf EMW – Present Mud Weight, pcf) x TVDshoe, ft. x 0.007
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3.0
Well Data Sheet must be Current
The data sheet should be kept as current and as accurate as possible so that time is not
wasted looking-up routine capacity numbers after a kick has been taken. The data sheet
has been designed so that nearly all of the sections can be completed prior to a kick.
These sections include:
3.1
Sections Fully Completed
•
•
•
•
•
•
•
Well Data
Pump Data
Casing Data
Wellhead or Casing Pressure Limitation
Liner Casing Data
Drillstring Data
Maximum Initial SICP
However, some of the sections on the data sheet cannot be fully completed until
after the well has kicked. These include:
3.2
Sections Partially Completed
3.2.1
Hole Data
All items should be completed except the measured depth and true
vertical depth. These depths are recorded after the kick occurs.
3.2.2
Internal Capacities
All items should be completed except the drillpipe length (ft) and
volume (bbls). These items are recorded after the kick occurs.
3.2.3
Annulus Capacities
All items should be completed except drillpipe x casing or hole (ft)
and volume (bbls). These items are recorded after the kick occurs.
If the Pre-recorded Data Sheet is completed as described above, the only blank
entries remaining on the sheet will be those, which require the length of drillpipe in
the hole (which is constantly changing as you drill deeper). If a kick is taken, the
Drilling Foreman simply needs to determine the length of drillpipe in the hole and the
remaining capacities (hole, internal, and annulus) can be easily calculated.
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4.0
Some Complicating Situations
Sometimes, complicated wellbore and drillstring configurations combine to make
completion of the data sheet unclear. Some of these special situations (with remedies) are
described below.
4.1
Drilling Liner
A drilling liner is a complicating situation because the change in casing diameters at
the liner top changes the annular capacity figures. To resolve the situation, you will
need to add additional annular capacity figures to the Prerecorded Data Sheet.
The drillstring needs to have two separate annular capacity figures (one for the liner,
a second for the casing). Therefore, you need to include the annular capacity figures
for both the liner and the casing in the annulus capacity section. Make a note in the
left hand margin to indicate which capacity figure is for the liner and which is for the
casing. Remember, this need only be done for the drillstring component, which is
opposite the liner top.
If drillpipe is opposite the liner top while drilling, then the length of drillpipe x casing
can be determined and recorded on the data sheet. On the other hand, if the
heavyweight drillpipe is opposite the liner top while drilling, then the length of
heavyweight inside the liner and casing will be constantly changing as you drill
deeper. In these instances, it will not be possible to record the correct lengths until
after a kick has been taken and the measured depth determined.
4.2
Tapered Drillstring
A tapered drillstring changes both the internal and the external capacity figures at the
point of crossover. You need to include the capacity figures (bbl/stk) for both sizes of
drillpipe on the Pre-recorded Data Sheet. Compute the internal and annular
capacities opposite the smaller diameter drillpipe in the same manner as the drill
collars.
Current Revision:
Previous Revision:
October 2002
October 1998
F-6
3rd Edition
5.1
PRE-RECORDED WELL DATA
KEEP THIS DATA SHEET CURRENT AT ALL TIMES
(Vertical and Deviated Wells)
Well Name
HOLE DATA
Field Zuluf
Zuluf Well #1005
Size(actual)
8.5000
Liners (in.)
6.25
6.25
PUMP DATA
No. 1
No. 2
Hole MD
Stroke(in.)
16
16
CASING (LAST SET) DATA
9.6250
by
8.5000
(in. OD)
(in. Avg ID)
8,000
Rod(in. )
Shoe MD
Rig Nadrico #1
ft.
Hole TVD
% Eff.
96
96
bbl./stk
0.1458
0.1458
* X if used, empty if not
5,500
(feet)
Shoe TVD
5,500
(feet)
Limitation =
3160
psi.
WELLHEAD OR CASING PRESSURE LIMITATION
The lessor of: 100% BOP Rating
5,000
psi.
100% Wellhead Rating
5,000
psi.
80% Casing Burst
3,160
psi.
LINER CASING DATA
by
(in. OD)
(in. Avg ID)
DRILL STRING DATA
Drill Pipe 1
4.5000
Drill Pipe 2
HW Drill Pipe
4.5000
in. (OD)
in. (OD)
in. (OD)
INTERNAL CAPACITIES
Drill Pipe 1
7,220
Drill Pipe 2
HW Drill Pipe
330
Drill Collars
450
Drill Collars
ft.
ft.
ft.
ft.
ft.
Msrd Depth(bit)
ft.
8,000
Top @
41.5
x
x
x
x
x
0.0141
0.0074
0.0077
0.0000
Total Internal =
lb./ft.
lb./ft.
lb./ft.
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
107.7
(Note: Use other side for subsea)
ft.
x
0.0505 bbl./ft. =
ft.
x
0.0000 bbl./ft. =
ft.
x
0.0505 bbl./ft. =
ft.
x
0.0000 bbl./ft. =
ft.
x
0.0000 bbl./ft. =
ft.
x
0.0000 bbl./ft. =
ft.
x
0.0505 bbl./ft. =
ft.
x
0.0259 bbl./ft. =
ft.
x
0.0000 bbl./ft. =
Msrd Depth(bit)
ft.
Total Annulus =
MD(feet)
OD(in.)
6.75
ANNULUS CAPACITIES
DP1 x Csg.
5,500
DP1 x Liner
0
DP1 x Hole
1,720
DP2 x Csg.
0
DP2 x Liner
0
DP2 x Hole
0
HW DP
330
DC x Hole
450
DC x Hole
0
8,000
393.2
101.8
0.0
2.4
3.5
0.0
bbl.
bbl.
bbl.
bbl.
bbl.
bbl. =
277.9
0.0
86.9
0.0
0.0
0.0
16.7
11.7
0.0
bbl. =
739
Strokes
2,697
Strokes
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
500.9
bbl.
=
3,436
Strokes
Volume from Bit to Shoe =
86.9
bbl.
=
596
Strokes
Active Pit Volume
x 0.007 x
F-7
5,500
ft. =
(Shoe TVD)
TVD(feet)
DRILL COLLARS
ID(in.)
by
2.8125
by
System Volume (Internal + Annulus) =
MAX INITIAL SICP TO FRACTURE SHOE
[
127
pcf EMW 74
pcf MW]
(Shoe Test)
(Present Mud Weight)
ft.
ft. Shoe @
MD(feet)
16.6
8,000
*Use
For Kill?
X
500
bbl.
2041
psi.
Version 2.0 (4/15/00)
PRERECORDED WELL DATA
5.2
KEEP THIS DATA SHEET CURRENT AT ALL TIMES
(Highly Deviated and Horizontal Wells)
Well Name
Zuluf Well #1006
HOLE DATA
Size(avg)
8.5000
Hole Capacity: No pipe in hole
Field
Zuluf
Hole MD
8,300
0.0702
Rig Nadrico #1
ft.
bbls/ft x
Hole TVD
8,300
ft. =
6,000
ft.
582.8
bbl
*Use
For Kill?
X
(from BOP to MD)
PUMP DATA
No. 1
No. 2
Liners (in.) Stroke(in.)
6.25
16
6.25
16
CASING (LAST SET) DATA
9.6250
by
(in. OD)
Rod(in. )
8.5000
(in. Avg ID)
Shoe MD
WELLHEAD OR CASING PRESSURE LIMITATION
The lessor of: 100% BOP Rating
5,000
100% Wellhead Rating
5,000
80% Casing Burst
4,600
LINER CASING DATA
0.0000
by
(in. OD)
0.0000
(in. Avg ID)
DRILL STRING DATA
Drill Pipe 1
4.5000
Drill Pipe 2
HW Drill Pipe
4.5000
in. (OD)
in. (OD)
in. (OD)
Top @
16.6
41.5
% Eff.
96
96
bbl./stk
0.1458
0.1458
* X if used, empty if not
7,200
(feet)
Shoe TVD
6,000
(feet)
Limitation =
4,600
psi.
psi.
psi.
0
MD(feet)
lb./ft.
lb./ft.
lb./ft.
Shoe @
42.3
0.0
0.0
0.0
0.0
Section 1 Subtotal Internal Capacities =
Section 2 Subtotal Internal Capacities =
7,200
6,000
bbl.
bbl.
bbl.
bbl.
bbl.
42.3
290
3,000
3,000
INTERNAL CAPACITIES (Section 2 - Kickoff Point to Start of Hold)
Drill Pipe 1
3,500 ft.
x
0.0141
bbl./ft. =
49.4
Drill Pipe 2
ft.
x
0
bbl./ft. =
0.0
HW Drill Pipe
700
ft.
x
0.0074
bbl./ft. =
5.2
Drill Collars
ft.
x
0.0077
bbl./ft. =
0.0
Drill Collars
ft.
x
0.0000
bbl./ft. =
0.0
Start of Hold MD
Start of Hold TVD
0
0
MD(feet) TVD(feet)
DRILL COLLARS
OD(in.)
ID(in.)
6.75
by
2.8125
by
INTERNAL CAPACITIES (Section 1 - Surface to Kickoff Point)
Drill Pipe 1
3,000 ft.
x
0.0141
bbl./ft. =
Drill Pipe 2
0
ft.
x
0.0000
bbl./ft. =
HW Drill Pipe
0
ft.
x
0.0074
bbl./ft. =
Drill Collars
ft.
x
0.0077
bbl./ft. =
Drill Collars
ft.
x
0.0000
bbl./ft. =
Kickoff MD
Kickoff TVD
psi.
bbl.
Strokes
bbl.
bbl.
bbl.
bbl.
bbl.
54.5
374
bbl.
Strokes
Kickoff Point
Start of Hold
(continued on next page)
F-8
Version 2.0 (4/15/00)
PRERECORDED WELL DATA
(Highly Deviated and Horizontal Wells)
(page 2)
INTERNAL CAPACITIES (Section 3 - Start of Hold to TD of Bit)
Drill Pipe 1
0
ft.
x
0.0141
bbl./ft. =
Drill Pipe 2
ft.
x
0.0000
bbl./ft. =
HW Drill Pipe
1000
ft.
x
0.0074
bbl./ft. =
Drill Collars
100
ft.
x
0.0077
bbl./ft. =
Drill Collars
ft.
x
0.0000
bbl./ft. =
0.0
0.0
7.4
0.8
0.0
bbl.
bbl.
bbl.
bbl.
bbl.
Section 3 Subtotal Internal Capacities =
Total MD
Total TVD
8.2
56
bbl.
Strokes
720
Strokes
8,300
6,000
TOTAL INTERNAL CAPACITY
Msrd. Depth(Bit)
8,300 ft.
ANNULUS CAPACITIES
DP1 x Csg.
7,200
DP1 x Liner
DP1 x Hole
DP2 x Csg.
DP2 x Liner
DP2 x Hole
HW DP x Csg.
HW DP x Liner
HW DP x Hole
1,000
DC1 x Csg
DC1 x Liner
DC1 x Hole
100
DC2 x Csg
DC2 x Liner
DC2 x Hole
ft.
ft.
ft.
ft.
ft.
ft.
ft.
ft.
ft.
ft.
ft.
ft.
ft.
ft.
ft.
Msrd Depth(bit)
ft.
8,300
Total Internal =
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
0.0505
0.0000
0.0505
0.0000
0.0000
0.0000
0.0505
0.0000
0.0505
0.0259
0.0000
0.0259
0.0000
0.0000
0.0000
Total Annulus =
System Volume =
(Internal + Annulus)
522.0
105.0
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
417.0
bbl.
=
bbl. =
363.8
0.0
0.0
0.0
0.0
0.0
0.0
0.0
50.5
0.0
0.0
2.6
0.0
0.0
0.0
bbl. =
3,581
Active Pit Volume
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
2,860
Strokes
500
Kickoff Point
Start of Hold
MAX INITIAL SICP TO FRACTURE FORMATION AT SHOE
Max. SICP = (Shoe Test - Present Mud Wt.) x Shoe TVD x 0.007
=
[#
pcf EMW -
74
pcf MW]
x
6,000
F-9
ft. x 0.007 =
2226
Strokes
psi
bbl.
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
__
SECTION G – DRILLER’S METHOD
Table of Contents
1.0
Description of the Method................................................................. G-2
Step1
2.0
The Kick Is Detected – Shut the Well In...................................... G-2
Shut-In Procedure while Drilling ................................................... G-2
Shut-In Procedure while Tripping ................................................. G-2
Step 2a Allow the Well to Stabilize ......................................................... G-3
Step 2b Bumping the Drillpipe Float....................................................... G-3
Step 3
Perform the Kick Control Calculations ...................................... G-4
Step 4
Establish Circulation ................................................................. G-5
Step 5
Circulate Out the Influx Holding Drillpipe Pressure Constant….G-5
Step 6
Shut Down the Pumps – Weight Up the Mud Pits ................. …G-6
Step 7
Re-Establish Circulation and Circulate Kill Mud.................... …G-7
Step 8
Shut Down and Check for Flow ............................................. …G-7
Step 9
Circulate and Condition the mud ........................................... …G-8
Using the Driller’s Method Worksheet ........................................... G-8
Step 1
Pre -recorded Information ...................................................... …G-9
Step 2
Information to be Recorded when Well Kicks........................ …G-9
Step 3
Determining Pressures for the First Circulation ....................... G-9
Step 4
Determining Mud Weight to Balance the Kick.......................... G-10
Rounding-Up Rule ................................................................... G-10
Step 5
Total Volume to Weight-Up ...................................................... G-10
Step 6
Barite Required to Weight-Up .................................................. G-11
Step 7
Determining Pressures for the Second Circulation ................. G-11
Step 8
Determining Reservoir Pressure.............................................. G-12
Step 9
Determining Equivalent Bottomhole Gas Bubble Height ......... G-12
Step 10 Determining Maximum Casing Pressure.................................. G-12
Pc Max (Part 1) ......................................................................... G-13
Pc Max (Part 2) ......................................................................... G-13
Step 11 Determining Volume Gain for a Gas Kick - Figure P.3 ............. G-14
Step 12 Determining Maximum Casing Pressure & Excess Volume.... G-14
Pre-recorded Well Data Sheet (Vertical Well) .......................................... G-15
Driller's Method Worksheet (Vertical Well).............................................. G-16
Figure P.1 ............................................................................................... G-18
Figure P.3................................................................................................ G-19
Pre-recorded Well Data Sheet (Highly Deviated or Horizontal Well)........ G-20
Driller’s Method Worksheet (Highly Deviated or Horizontal Well)............ G-22
Current Revision:
October 2002
Previous Revision: October 1998
G-1
3rd Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
__
SECTION G – DRILLER’S METHOD
1.0
Description of the Method
The Driller's Method of well control is a well killing method that requires two complete
circulations. During the first circulation, mud is pumped to displace the influx from the well;
in the second circulation, weighted kill mud is pumped around to kill the well. While
circulating, the bottomhole pressure is maintained equal to or slightly greater than the
formation pressure. The following discussion describes the Driller's Method in detail from
kick to kill.
STEP 1 - The Kick Is Detected (Shut the Well In)
As always, it is extremely important to shut-in the well as quickly as possible in order
to minimize the size of the infl ux. The best way to achieve this is by using the “Three
S” Shut-In Procedure While Drilling or the “Three S” Shut -In Procedure While
Tripping.
Shut-In Procedure While Drilling
(1) SPACE OUT
Pick up drill string and spot tool joint.
(2) SHUT DOWN
Stop the mud pumps.
(3) SHUT-IN
Close the annular preventer or uppermost pipe ram
preventer. Confirm that the well is shut-in and flow
has stopped. Open HCR valve.
Shut-In Procedure While Tripping
(1) STAB VALVE
Install Full Open Safety Valve (open position) in
drill string. Close Safety Valve.
(2) SPACE OUT
Spot tool joint.
(3) SHUT-I N
Close the annular preventer or uppermost pipe ram
preventer. Confirm that the well is shut-in and flow
has stopped. Open HCR valve.
It should be emphasized that in nearly all well kicks, the Driller will be the responsible
for closing the preventers and shutting the well in. The Driller must have the initiative
and experience to do this by himself if he is alone. It is the responsibility of the Saudi
Aramco Drilling Foreman to make sure the Driller knows the proper shut-in
procedure. The Driller will have plenty of time after the well is shut-in to retrieve his
crews from the mud pits and notify the Toolpusher. The Driller must not delay
when shutting in the well.
Current Revision:
October 2002
Previous Revision: October 1998
G-2
3rd Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
__
SECTION G – DRILLER’S METHOD
Step 2a - Allow the Well to Stabilize, Record Pressure and Volume Gained
After the well is shut-in, it may take a few minutes for the shut-in pressures to
stabilize. If the pipe is reciprocated through the annular preventer during the kill, it
may be advisable to reduce the annular closing pressure to lessen element wear. The
crew should ensure that the bag does not leak at the reduced pressure!
If the choke manifold is lined-up properly, you should be possible to open the choke
line valve at the preventer stack and read the shut-in casing at the choke manifold. If
no drillpipe float is installed, read and record the shut-in drillpipe pressure as well.
Finally examine the pit volume gained during the kick and verify this number with the
Derrickman.
Step 2b - Bumping the Drillpipe Float
If a drillpipe float is installed, the pressure gauge on the drillpipe will probably read
near zero. In order to get an accurate value for the shut-in drillpipe pressure, the float
will have to be “bumped” open by slowly pumping down the drillpipe. The correct
procedure for bumping the float is given below.
Float Bumping Procedure
(1)
(2)
(3)
(4)
(5)
(6)
Make sure the well is shut-in and that the shut-in casing pressure is
recorded.
Slowly pump down the drillpipe while monitoring both the casing and
drillpipe pressure.
The drillpipe pressure will increase as you begun. Watch carefully for a “lull”
in the drillpipe pressure (a hesitation in the rate of increase), which will
occur as the float is pumped off of its seat. Record the drillpipe pressure
when the lull is first seen.
To verify that the float has been pumped open, continue pumping down the
drillpipe very slowly until an increase in the casing pressure is observed.
This should occur very soon after the lull was observed on the drillpipe
gauge.
Shut down the pump as soon as you see the casing pressure start to
increase and record the shut-in drillpipe pressure as the pressure at which
the lull was first seen in Step 3 above (not the final drillpipe pressure after
the pumps are stopped).
Check the shut-in casing pressure again. Any excess pressure may
be bled-off in small increments until equal readings of casing pressure
are observed after two consecutive bleed-offs.
Current Revision:
October 2002
Previous Revision: October 1998
G-3
3rd Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
__
SECTION G – DRILLER’S METHOD
The float bumping procedure, as described above, can be difficult at times if the rig
has big duplex pumps, which are compounded. Clutch the pumps in short burst to
slowly build up pressure on the drillpipe. It is most likely that a drillpipe ‘lull’ won’t
occur before the casing pressure starts to increase. To determine the shut-in drillpipe
pressure in these instances, subtract the increase in shut-in casing pressure from the
final value of shut-in drillpipe pressure after the pumps have been stopped. Use this
value as the official shut-in drillpipe pressure.
If excess pressure is trapped on the
drillpipe when bumping the float….
Shut-in
Drillpipe
Pressure
=
Shut-in drillpipe
pressure after
bumping float
-
Increase in shut-in
casing pressure while
bumping float
Step 3 - Perform the Kick Control Calculations
Calculations should be performed using the Driller's Method worksheet before the
influx is displaced from the well on the first circulation. Several critical items will be
determined including:
•
•
•
•
Bottomhole reservoir pressure
Mud weight necessary to balance the kick
Maximum surface casing pressure during the first circulation
Maximum excess mud volume gained during the first circulation
An example problem illustrating the use of the Driller's Method Worksheet is provided
later in this section.
One thing to keep in mind while performing your calculations is that the formation
fluids in the annulus, especially gas, may migrate up the hole and cause an increase
in the shut-in casing pressure. If the shut-in casing pressure starts increasing
substantially (i.e., to the point of risking shoe breakdown or exceeding the wellhead or
casing pressure limitation), you may have to bleed-off some of the excess pressure
through the choke. It is better to bleed the pressure off in small increments rather than
one large slug. Any excess pressure that appears on the annulus due to the migrating
bubble may be bled-off in small increments until equal readings are observed after
two consecutive bleed-offs.
There is more likelihood of pipe sticking if formation fluids are kept longer in the
annulus and it’s important to proceed as quickly as possible.
Current Revision:
October 2002
Previous Revision: October 1998
G-4
3rd Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
__
SECTION G – DRILLER’S METHOD
Step 4 - Establish Circulation
After the kick control calculations have been performed, you should use the
information recorded on the Driller's Method Worksheet to circulate the influx from
the well. Before breaking circulation, be sure to check the following items.
1)
2)
3)
4)
Be sure that every member of the crew knows exactly what his duties are
before the kill operation begins. (See Section M in this volume for more
details.)
Eliminate all sources of ignition in the immediate vicinity of the rig and
vent lines. See that the vent lines on the mud-gas separator and mud
degasser are secured properly and, if possible, are downwind from the
rig.
Make sure your circulating system (including manifolds and pits) is linedup correctly.
Zero the stroke counter and make a note of the time.
When establishing circulation in a well closed in under pressure, backpressure on
the well is very difficult to control. The procedure is critical, since additional influx
will result if too little backpressure is held, or the formation can breakdown if too
much backpressure is held.
The procedure requires simultaneous manipulation of the choke and the pump
speed. While the pumps are being brought up to speed, the choke is opened in
such a way that casing pressure is maintained constant at its shut-in value just
prior to beginning pumping. As the pumps speed is increased up to the desired kill
rate, drillpipe pressure will increase but casing pressure must be held constant.
Successful manipulation of the choke while establishing circulation in this manner
will maintain constant bottomhole pressure.
The predetermined pump rate must be held constant throughout the killing of the
well. If the pump rate is allowed to vary without adjusting the drillpipe pressure,
constant bottomhole pressure will not be maintained. If the pump rate is increased,
additional frictional pressure will be reflected in the drill pipe pressure. If the choke
is adjusted to bring the drill pipe pressure down to the value predetermined using a
constant rate, then the bottom hole pressure is reduced possibly allowing
additional influx. Conversely, if the pump rate is reduced, the reduction in frictional
pressure will be noted and the choke adjusted to increase the drill pipe pressure,
possibly creating sufficient overpressure at the casing shoe to cause a break down.
Therefore, any change in pump rate should be made known to the choke operator
and the pump returned to the original rate.
Step 5 - Circulate Out the Influx Holding Drillpipe Pressure Constant
As soon as the pumps are operating at the desired kill rate, the drillpipe pressure
should be observed and recorded. Hold the observed drillpipe pressure constant for
the entire first circulation by manipulating the choke as the contaminant is circulated
from the well.
Current Revision:
October 2002
Previous Revision: October 1998
G-5
3rd Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
__
SECTION G – DRILLER’S METHOD
Note:
In all probability, the observed initial circulating pressure on the
drillpipe will be equal to the sum of the initial shut-in drillpipe
pressure and the pre-recorded slow pump rate pressure at the
same kill rate.
As the gas and contaminated mud are circulated to the surface, the gas will begin
to expand, increasing both the casing pressure and pit volume. A pure gas
contaminant will increase the casing pressure to the value shown at “R” on the
worksheet, but will be less if the contaminant includes water and/or oil. This is
probably the most critical stage of the killing operation, where panicking could very
easily turn a good job into a disaster.
It can sometimes be difficult to bleed the gas off fast enough to keep the drill pipe
pressure within limits, but excessive pressure could cause formation breakdown. If
the gas cannot be released fast enough from the annulus to prevent an increase in
drill pipe pressure, the pumps may have to be slowed or even stopped until the
casing pressure can be bled down. For this reason it is a good idea to take several
slow pump rates, including one at the slowest pump rate possible, so that the
drillpipe pressure can be determined at the reduced pumping rate. If the pumps
must be stopped while bleeding down the casing pressure attempt to hold the
drillpipe pressure at or above the original shut-in pressure while bleeding. If the
drillpipe pressure drops below this value, another kick may be taken. The pumps
should be returned to the original rate as soon as possible. This method is not
ideal, but is necessary when the surface facilities cannot safely handle the high
flow rates.
Step 6 - Shut Down the Pumps - Weight Up the Mud Pits
After the contaminant has been circulated out of the well, the pumps can be shut
down and the well shut-in. When shutting down the pumps, the choke should be
closed gradually as the pump speed is reduced. The choke should be closed in a
way that holds the casing pressure constant as the pumps are slowed down. As
the pump speed decreases, the drillpipe pressure will decrease but casing
pressure must be held constant at its value just prior to slowing down. This
procedure insures that constant bottomhole pressure is maintained during the
shutdown. When the well is shut-in after the first circulation, the shut-in casing
pressure and the shut -in drillpipe pressure should be equal. A casing pressure is
higher than the drillpipe pressure indicates that there is still some contaminant in
the annulus or that another kick was taken during the first circulation. Such a
situation will warrant an additional circulation of the well with existing mud before
kill weight fluid is mixed and pumped.
Note:
After shutdown, the SICP and the SIDP should be equal to the initial
shut-in drillpipe pressure that was observed when the well was first
shut-in.
Current Revision:
October 2002
Previous Revision: October 1998
G-6
3rd Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
__
SECTION G – DRILLER’S METHOD
If the shut-in casing pressure is equal to the shut-in drillpipe pressure at the
completion of the first circulation, weight-up the mud in the pits. The first step is to
reduce the mud volume in the active pits to make room for weighting material. The
mud mixing facilities and pit volumes on the particular rig will dictate to some extent
just how the mud should be handled. The ideal situation is to maintain a
reasonably low-volume active system such that the mud circulated out of the hole
can be weighted up without having to stop circulating. It may be desirable to weight
up enough mud to displace the entire hole before the killing operation is started.
Many variables will enter into this decision (as described in Step 3) and every
situation is different. It is important to remember that the mud weight can be raised
while the well is being circulated.
Step 7 - Re-Establish Circulation and Circulate Kill Mud
After the mud has been properly weighted-up, the second circulation should be
started. First, establish the desired pump rate by holding the shut-in casing
pressure constant while bringing the pump up to the kill rate (as described Step 3).
Make sure to hold this pump rate constant throughout the killing of the well.
As the kill mud goes down the drillpipe, adjust the choke so that the casing
pressure remains constant at the shut-in value it had before the start of the second
circulation. Hold the casing pressure constant until the kill mud reaches the
bit (as determined by the drillpipe capacity in strokes).
When the kill mud reaches the bit, the pressure on the drill pipe should be
observed and recorded on your Driller's Method Worksheet. Adjust the choke to
hold this drill pipe pressure constant throughout the remainder of the kill
operation. Continue circulation until the hole is full of kill mud. The approximate
strokes and volume required are indicated on your Prerecorded Well Data sheet.
The casing pressure should drop to zero as the lightweight mud is displaced from
the annulus.
Step 8 - Shut Down and Check for Flow
After the entire hole volume has been displaced with kill mud, the pumps can be
shut down and the well shut -in. When shutting down the pumps, the choke should
be closed (holding casing pressure constant) gradually as the pump speed is
reduced. As the pump speed decreases, the drillpipe pressure will slowly decrease
to zero.
Note:
The casing pressure may already be reading zero before the pumps
are shut down. This is normal and may be expected.
After the well is shut-in, the casing and drillpipe pressures should be zero. Confirm
that the well is dead by cracking open the choke; the well should not flow. If the
well is dead, the BOPs can be opened. Keep in mind that a small volume of gas
may be trapped between the preventer and the choke line. Exercise caution on the
rig floor when opening the preventers.
Current Revision:
October 2002
Previous Revision: October 1998
G-7
3rd Edition
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SECTION G – DRILLER’S METHOD
Step 9 - Circulate and Condition the Mud
After the BOP's are opened, circulate the mud and condition it to the desired
properties. Usually the yield point is too high. Therefore, running or pulling pipe
can cause excessive pressure on the formation or swabbing and either could lead
to another kick.
2.0
Using the Driller’s Method Worksheet
The Driller's Method worksheet is a step-by-step instruction sheet to help the Drilling
Foreman calculate the critical well control parameters, which are necessary to
successfully kill a well using the Driller's Method. Use of the worksheet is demonstrated
here with an example problem.
EXAMPLE PROBLEM
A well is being drilled, and the following data are known prior to kick:
Triplex Pumps:
Casing Size:
Hole Size:
Csg Pressure Limitation:
Shoe Test:
Drill Pipe Size:
Drill Collar Size:
Mud Weight:
Active Surface System:
Slow Pump Rate Data:
16” stroke, 96% vol. eff. (6-1/4” liner)
9-5/8” set at 5,500 ft MD/TVD
8-1/2”
3,160 psi @ 80% burst
2,040 psi with 74 pcf mud
4-1/2”, 16.60 lb/ft
6-3/4” OD x 2-13/16” ID (450 ft long)
74 pcf
750 bbls before kick
500 bbls at start of kill operation
SPM
30
40
PSI
350
550
While drilling at 8,000' TVD, the well kicked and the BOP's were closed.
The following data were observed:
Initial Drill Pipe Pressure
Initial Casing Pressure
Pit Volume Gain
=
=
=
200 psi
300 psi
15 bbl
The following pages describe a step-by-step procedure for determining the well control
parameters, which are necessary to kill the example problem well using the Driller's
Method.
Current Revision:
October 2002
Previous Revision: October 1998
G-8
3rd Edition
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SECTION G – DRILLER’S METHOD
Step 1 – Pre-recorded Information
Prior to the kick, and at all times, your prerecorded data sheet should be completely
filled out except for the measured depth and the length of drillpipe in the hole. Enter
these items and calculate the internal drillstring capacity and the system totals.
Transfer the slow pump rate data from the prerecorded data sheet to line A of the
Driller's Method worksheet.
Step 2 - Information to be Recorded when Well Kicks
Many items of information need to be gathered when a well kicks. These include:
•
•
•
•
•
•
Old Mud Weight
Pit Volume Increase
Initial Shut-in Drill Pipe Pressure
True Vertical Depth Of Hole
Initial Shut-in Casing Pressure
Measured Depth Of Hole
This information should be recorded in lines B through F on the Driller's Method
worksheet.
Step 3 - Determining Pressures for the First Circulation
One of the biggest advantages of the Driller's Method is that it is not necessary to
calculate any circulating drillpipe pressures before the first circulation can begin.
However, while circulating, it is very important to record and maintain a constant
drillpipe pressure once you have it established. Space is provided on the Driller's
Method worksheet to record your circulating drillpipe pressure, which is observed
after the pumps are operating at the predetermined kill rate. The kill rate should be
between 2-5 barrels per minute for most cases. Space is also provided to record
the kill rate (in strokes per minute) before the circulation begins. Remember to keep
the kill rate constant for the entire circulation and to maintain constant drillpipe
pressure by making choke adjustments until the influx is circulated out.
Note:
For added peace of mind during the kill operation, it is possible
to make a quick estimation of what your initial circulating
drillpipe pressure should be after circulation is established.
Simply add the prerecorded slow pump rate pressure at the
desired circulating rate to the initial shut-in drill pipe pressure.
In this example 30 SPM is the kill rate, so use the slow pump
rate pressure at 30 SPM. Therefore, the initial circulating
pressure should be approximately 350 + 200 = 500 psi. You
may wish to jot down this value in the margin for comparison
purposes when the circulation begins. However, the actual
value that is observed on the drillpipe pressure gauge when
circulation is established is the value that should be held
constant for the entire circulation (not your estimated value).
Current Revision:
October 2002
Previous Revision: October 1998
G-9
3rd Edition
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SECTION G – DRILLER’S METHOD
Step 4 - Determining Mud Weight to Balance the Kick
Using the equation below, calculate the increase in mud weight necessary to balance
the kick.
Increase in
Mud Weight
Initial Shut-in Drillpipe Pressure (SIDP)
=
-----------------------------------------0.007 X TVD
=
200
------------------0.007 X 8,000
=
3.6 pcf
Rounding-Up Rule: The increase in mud weight should be calculated to the tenths
place. If the number in the tenths place is greater than zero,
then roundup the number one full pcf. In this example, the
number in the tenths place is six, so the weight is rounded-up
to 4 pcf.
Record an 4 pcf increase on line G of the Driller's Method worksheet. Adding the
mud weight increase G to the old mud weight B yields the new mud weight required
to balance the kick.
New Mud Weight To Balance The Kick = Old Mud Weight + Increase In Mud Weight
= 74 + 4
= 78 pcf
Enter the new mud weight in part H of the worksheet.
Step 5 - Total Volume to Weight-Up
There are several reasons why the volume of mud in the surface pits should be
reduced after the first circulation, but before weighting-up. Some of these reasons
include:
•
•
•
It takes less time to weight-up less volume
It requires less barite to weight-up less volume
It may overflow the pits if barite is added without reducing first
Current Revision:
October 2002
Previous Revision: October 1998
G - 10
3rd Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
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SECTION G – DRILLER’S METHOD
Whatever the reasons, decide on an appropriate pit volume and add it to the total
system volume (from your Prerecorded Data Sheet) to determine the total volume to
weight-up. In our example, we decided on 500 bbls of active pit volume with 501 bbls
of system volume for a total volume of 1001 bbls. to weight-up. Record this value on
part I of the worksheet.
Step 6 - Barite Required to Weight-Up
It's an easy matter to determine the amount of barite, which will be required once the
total volume to weight-up is known. Use the following formula and record the value at
J.
Barite Required
=
Total Volume
to Weight-up
30.0 x Increase In Mud Weight
x
________________________________
262.0 - New Mud Weight
30.0 x 4
=
1,001 x
__________
262.0 – 78
=
653
(50# sacks of barite)
Note that this equation assumes you are using 50 pound sacks of barite.
Step 7 - Determining Pressures for the Second Circulation
Remember, when using the Driller's Method we don't calculate circulating pressures. In
the Driller's Method, circulating pressures are self-determined. This means that the
pressures, which we observe on the gauges, are the pressures that we hold constant
while circulating. The values that we record on the Driller's Method worksheet for
the casing and drillpipe pressures should be observed values, not calculated
values.
On the Driller's Method worksheet, you should record the casing pressure as observed
immediately before the start of the second circulation. It should not be much higher
than the observed shut-in drillpipe pressure. If it is, you may have another kick in the
hole and you should circulate the well as before using the first circulation techniques in
order to clear the well of the additional influx. Otherwise, begin the second circulation
by holding the observed casing pressure constant while establishing circulation and
until the kill mud reaches the bit. You should record the drill string internal capacity (in
strokes) on the worksheet to determine when kill mud will reach the bit.
As soon as the kill mud reaches the bit, our focus should turn to the drillpipe gauge.
The observed drillpipe pressure at this point should be recorded on the worksheet and
held constant for the remainder of the kill. The total system capacity should be written
in the appropriate space on the Driller's Method worksheet.
Current Revision:
October 2002
Previous Revision: October 1998
G - 11
3rd Edition
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SECTION G – DRILLER’S METHOD
Step 8 - Determining Reservoir Pressure
We need to calculate the reservoir pressure as an intermediate step in determining the
more critical well control parameters such as maximum casing pressure and excess
volume. To determine the reservoir pressure, simply multiply the following:
Reservoir Pressure
= New Mud Weight x 0.007 x True Vertical Depth
= 78 X 0.007 x 8000
= 4368 psi
Record this value on the back of the worksheet at K.
Step 9 - Determining Equivalent Bottomhole Gas Bubble Height
This is the height of the gas bubble at the bottom of the hole assuming an annulus equal
to that at the top of the hole. It is used to determine the maximum surface pressure when
the gas bubble reaches the surface. Use the following equation and record on the
worksheet.
Initial Pit Volume Increase
Gas Bubble Height =
_____________________________________
Annulus Capacity Factor (D.P. x Hole)
15 bbl
=
____________
0.0505 bbl/ft
=
297 feet
Step 10 - Determine Maximum Casing Pressure
If the kick is gas, then the maximum casing pressure will occur when the gas first
reaches the surface. We must calculate this value before its arrival to determine if our
wellhead and casing can withstand the pressure. Unfortunately, the mathematical
formula used to determine the maximum casing pressure is somewhat complex. To
simplify the calculation of maximum casing pressure, charts have been developed which
are included in Section P. The maximum casing pressure (P c Max) is calculated in two
steps. An equation is used to calculate Part 1, and a chart is used to calculate Part 2.
Current Revision:
October 2002
Previous Revision: October 1998
G - 12
3rd Edition
WELL CON T ROL M AN U AL
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SECTION G – DRILLER’S METHOD
Pc Max (Part 1)
The first part of Pc Max is determined with the following simple formula:
Pc Max – Part 1 (Driller's Method)
Shut-in Drillpipe Pressure
=
_________________________
2
For our example, Pc Max Part 1 is therefore equal to:
Pc Max – Part 1 (Driller's Method)
200
=
____
= 100 psi
2
Note:
In the past, Pc Max (Part 1) was determined through the use of a
chart, which has since been replaced by the previous equation.
Pc Max (Part 2)
Using Figure P.1, enter the upper left vertical axis at the original mud weight
(74 pcf). Read across to an imaginary line for the reservoir pressure (4368
psi); then drop vertically to the line matching the equivalent bottomhole gas
bubble height (297 ft). Run a horizontal line to the curve for the Pc Max -I
value calculated earlier; then run a vertical line up to the Pc Max-II axis and
read approximately 760 psi. Record this value at Q on the worksheet. Add O
and Q to determine R, the maximum surface casing pressure (860 psi). As
an alternative to the charts, equations are provided on the kill sheet.
Generally speaking, the casing pressure is significant only if it should exceed the
pressure rating of the casing, well head or BOP's. It is seldom possible to calculate with
accuracy whether oil, gas, or water has entered the hole, but with rare exceptions gas is
always present. The method described above will indicate the maximum possible casing
pressure and pit volume gain if pure gas has entered the wellbore. Water or oil will
decrease the casing pressure and volume gain somewhat from those shown on the
worksheet, and can be handled satisfactorily.
Current Revision:
October 2002
Previous Revision: October 1998
G - 13
3rd Edition
WELL CON T ROL M AN U AL
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SECTION G – DRILLER’S METHOD
At this point the maximum permissible casing pressure should have been determined
and a decision made as to whether to circulate the formation fluid out of the hole.
Note: The method used here to graphically determine the maximum surface
pressure is in error by the hydrostatic pressure of the gas column.
Step 11 - Determining Volume Gain for a Gas Kick - Figure P.3
A convenient chart, Figure P.3, is also provided to determine the maximum pit volume
gain, which will occur if the kick is completely gas. Enter at the maximum surface casing
pressure (860 psi). Read down to the reservoir pressure (4368 psi), then across to the
original kick volume (15 bbl). Read down to the horizontal axis to obtain the volume of
gas at the surface (64 bbl). Record this volume at T on the worksheet. Subtract the initial
pit volume increase E from T to determine the pit volume gain when the gas bubble is
circulated to the surface (49 bbl). Record this value.
Step 12 - Determining Maximum Casing Pressure and Excess Volume
Subtract the volume of gas at the surface S from the annulus capacity on the
prerecorded well data sheet. This will show approximately when the maximum casing
pressure and excess volume will occur (393 – 64 = 329 bbl, 2256 strokes). Record these
values in the proper spaces provided.
The following pages provide completed samples of the worksheet and Figures used in
the previous example problem, including:
•
•
•
•
•
•
Pre-recorded Data Sheet (Vertical Well)
Driller’s Method Worksheet (Vertical Well)
Figure P.1 (Pc Max Part 2)
Figure P.3 (Volume Gain)
Pre-recorded Data Sheet (Highly Deviated or Horizontal Well)
Driller’s Method Worksheet (Highly Deviated or Horizontal Well)
The Pre-recorded Data Sheets and Worksheets (for both vertical and highly
deviated/horizontal wells) are also developed in Excel spreadsheets, which perform all
required calculations.
Current Revision:
October 2002
Previous Revision: October 1998
G - 14
3rd Edition
PRE-RECORDED WELL DATA
KEEP THIS DATA SHEET CURRENT AT ALL TIMES
(Vertical and Deviated Wells)
Well Name
HOLE DATA
Field Zuluf
Zuluf Well #1005
Size(actual)
8.5000
Liners (in.)
6.25
6.25
PUMP DATA
No. 1
No. 2
Hole MD
Stroke(in.)
16
16
CASING (LAST SET) DATA
9.6250
by
8.5000
(in. OD)
(in. Avg ID)
8,000
Rod(in. )
Shoe MD
Rig Nadrico #1
ft.
Hole TVD
% Eff.
96
96
bbl./stk
0.1458
0.1458
* X if used, empty if not
5,500
(feet)
Shoe TVD
5,500
(feet)
Limitation =
3160
psi.
WELLHEAD OR CASING PRESSURE LIMITATION
The lessor of: 100% BOP Rating
5,000
psi.
100% Wellhead Rating
5,000
psi.
80% Casing Burst
3,160
psi.
LINER CASING DATA
by
(in. OD)
(in. Avg ID)
DRILL STRING DATA
Drill Pipe 1
4.5000
Drill Pipe 2
HW Drill Pipe
4.5000
in. (OD)
in. (OD)
in. (OD)
INTERNAL CAPACITIES
Drill Pipe 1
7,220
Drill Pipe 2
HW Drill Pipe
330
Drill Collars
450
Drill Collars
ft.
ft.
ft.
ft.
ft.
Msrd Depth(bit)
ft.
8,000
Top @
41.5
x
x
x
x
x
0.0141
0.0074
0.0077
0.0000
Total Internal =
lb./ft.
lb./ft.
lb./ft.
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
107.7
(Note: Use other side for subsea)
ft.
x
0.0505 bbl./ft. =
ft.
x
0.0000 bbl./ft. =
ft.
x
0.0505 bbl./ft. =
ft.
x
0.0000 bbl./ft. =
ft.
x
0.0000 bbl./ft. =
ft.
x
0.0000 bbl./ft. =
ft.
x
0.0505 bbl./ft. =
ft.
x
0.0259 bbl./ft. =
ft.
x
0.0000 bbl./ft. =
Msrd Depth(bit)
ft.
Total Annulus =
MD(feet)
OD(in.)
6.75
ANNULUS CAPACITIES
DP1 x Csg.
5,500
DP1 x Liner
0
DP1 x Hole
1,720
DP2 x Csg.
0
DP2 x Liner
0
DP2 x Hole
0
HW DP
330
DC x Hole
450
DC x Hole
0
8,000
393.2
101.8
0.0
2.4
3.5
0.0
bbl.
bbl.
bbl.
bbl.
bbl.
bbl. =
277.9
0.0
86.9
0.0
0.0
0.0
16.7
11.7
0.0
bbl. =
739
Strokes
2,697
Strokes
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
500.9
bbl.
=
3,436
Strokes
Volume from Bit to Shoe =
86.9
bbl.
=
596
Strokes
Active Pit Volume
x 0.007 x
G-15
5,500
ft. =
(Shoe TVD)
TVD(feet)
DRILL COLLARS
ID(in.)
by
2.8125
by
System Volume (Internal + Annulus) =
MAX INITIAL SICP TO FRACTURE SHOE
[
127
pcf EMW 74
pcf MW]
(Shoe Test)
(Present Mud Weight)
ft.
ft. Shoe @
MD(feet)
16.6
8,000
*Use
For Kill?
X
500
bbl.
2041
psi.
Version 2.0 (4/15/00)
DRILLER'S METHOD WORKSHEET
(Vertical and Deviated Wells)
PRERECORDED INFORMATION
A. Slow Pump Rate Data
Pump #1
( Use SPR Pressure through Riser for SubseaPump
)
#2
SPM
30
40
INFORMATION RECORDED WHEN WELL KICKS
B.
C.
D.
E.
F.
psi
350
550
bbl/stk
0.1458
0.1458
bbl/min
4.37
5.83
13:35
Time of Kick:
B
C
D
E
F
Old Mud Weight
Initial Shut-In Drill Pipe Pressure (SIDP)
Initial Shut-In Casing Pressure (SICP)
Initial Pit Volume Increase
True Vertical Depth of Hole
Measured Depth of Hole (for Capacity Calculations ONLY)
74
200
300
15
8,000
8,000
pcf
psi
psi
bbl
ft (TVD)
ft (MD)
FIRST CIRCULATION TO CLEAR WELL OF INFLUX
Bring Pumps up to Speed While Holding Casing Pressure Constant
{Account for Choke Line Friction if Subsea}
30
SPM
Read and Record Initial Circulating Pressure on Drill Pipe
550
psi
G
4
pcf
H
78
pcf
I
1,001
bbl
J
653
50#
sacks
Casing Pressure
200
psi
Drill String Internal Capacity
739
strokes
Final Circulating Pressure
369
psi
[Should Approximately = Slow Pump Rate Pressure (A) + SIDP (C)]
Maintain Constant DP Pressure Until Influx is Circulated Out. Then Shut Down
Pumps While Holding Casing Pressure Constant. {Remember CLF for Subsea}. If Drill
Pipe and Casing Shut-In Pressures are not Equal, Continue to Circulate Out Influx.
G. Increase in Mud Weight required to Balance Kick
H. New Mud Weight
H=B+G=
I. Total Volume to Weight up I = Active Pit Vol + System Vol =
J. Barite Required
SECOND CIRCULATION TO BALANCE WELL
Bring Pumps up to Speed While Holding
Casing Pressure Constant. {Account for
CLF if Subsea} Maintain Constant Casing
Pressure Until New Mud Reaches the Bit.
Read and Record Drill Pipe Pressure
When New Mud Reaches the Bit
Maintain Constant Drill Pipe Pressure
Until the System is Displaced.
System Volume
3,436
strokes
Version 2.0 (4/15/00)
G-16
DRILLER'S METHOD WORKSHEET
(page 2)
RESERVOIR PRESSURE (Pr)
K
4368
L
0.0505
M
297
ft.
N
0.52
psi/ft.
(Surface) O
100
psi
0
psi
(Subsea) O
100
psi
P
0.84
Q
760
psi
R
860
psi
psi
HEIGHT OF GAS BUBBLE AROUND DRILL PIPE (Kick Height(KH))
L. Annulus Capacity Factor (DP x Casing) Right Below Wellhead
MAXIMUM CASING PRESSURE (Pcmax) WHEN GAS GETS TO SURFACE
N. Mud Weight Gradient, psi/ft
O.
bbls/ft
(Optional Correction for Subsea Wells)
O. (Subsea) A correction must be added to PCmax, Part 1 calculated above to
account for the choke line.
(Subsea) O = Subsea Correction + (Surface) O =
(Use this new O in Part Q and Part R below)
P. TZ= Compressibility and Temperature Effects (Figure 11P.5)
Q. Pcmax, Part2 (Figure 11P.1)
R. Maximum Casing Pressure,
S. Does Pcmax Exceed the Wellhead or Casing Pressure Limitation?
YES
NO
X
VOLUME GAIN WHILE CIRCULATING OUT GAS BUBBLE
T. Volume of Gas at Surface (from Fig. 11P.4 or Formula below)
U. Volume Gain While Circulating Out Gas Kick
T
64.4
bbl
U
49.4
bbl
STROKES TO MAXIMUM CASING PRESSURE AND VOLUME
Maximum Casing Pressure and Excess Volume Occur When the Pumped Volume Equals
Total Annulus Capacity - Volume of Gas at Surface
bbl
strokes
328.8
2256
G-17
WELL CON T ROL M AN U AL
Drilling & Work ove r
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SECTION G – DRILLER’S METHOD
Current Revision:
Previous Revision:
October 2002
October 1998
G - 18
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
__
SECTION G – DRILLER’S METHOD
Current Revision:
Previous Revision:
October 2002
October 1998
G - 19
rd
3 Edition
PRE-RECORDED WELL DATA
KEEP THIS DATA SHEET CURRENT AT ALL TIMES
(Highly Deviated and Horizontal Wells)
Well Name
Zuluf Well #1006
HOLE DATA
Size(avg)
8.5000
Hole Capacity: No pipe in hole
Field
Zuluf
Hole MD
8,300
0.0702
Rig Nadrico #1
ft.
bbls/ft x
Hole TVD
8,300
ft. =
6,000
ft.
582.8
bbl
*Use
For Kill?
X
(from BOP to MD)
PUMP DATA
No. 1
No. 2
Liners (in.) Stroke(in.)
6.25
16
6.25
16
CASING (LAST SET) DATA
9.6250
by
(in. OD)
Rod(in. )
8.5000
(in. Avg ID)
Shoe MD
WELLHEAD OR CASING PRESSURE LIMITATION
The lessor of: 100% BOP Rating
5,000
100% Wellhead Rating
5,000
80% Casing Burst
4,600
LINER CASING DATA
0.0000
by
(in. OD)
0.0000
(in. Avg ID)
DRILL STRING DATA
Drill Pipe 1
4.5000
Drill Pipe 2
HW Drill Pipe
4.5000
in. (OD)
in. (OD)
in. (OD)
Top @
16.6
41.5
% Eff.
96
96
bbl./stk
0.1458
0.1458
* X if used, empty if not
7,200
(feet)
Shoe TVD
6,000
(feet)
Limitation =
4,600
psi.
psi.
psi.
0
MD(feet)
lb./ft.
lb./ft.
lb./ft.
Shoe @
42.3
0.0
0.0
0.0
0.0
Section 1 Subtotal Internal Capacities =
Section 2 Subtotal Internal Capacities =
7,200
6,000
(continued on next page)
G - 20
bbl.
bbl.
bbl.
bbl.
bbl.
42.3
290
3,000
3,000
INTERNAL CAPACITIES (Section 2 - Kickoff Point to Start of Hold)
Drill Pipe 1
3,500 ft.
x
0.0141
bbl./ft. =
49.4
Drill Pipe 2
ft.
x
0
bbl./ft. =
0.0
HW Drill Pipe
700
ft.
x
0.0074
bbl./ft. =
5.2
Drill Collars
ft.
x
0.0077
bbl./ft. =
0.0
Drill Collars
ft.
x
0.0000
bbl./ft. =
0.0
Start of Hold MD
Start of Hold TVD
0
0
MD(feet) TVD(feet)
DRILL COLLARS
OD(in.)
ID(in.)
6.75
by
2.8125
by
INTERNAL CAPACITIES (Section 1 - Surface to Kickoff Point)
Drill Pipe 1
3,000 ft.
x
0.0141
bbl./ft. =
Drill Pipe 2
0
ft.
x
0.0000
bbl./ft. =
HW Drill Pipe
0
ft.
x
0.0074
bbl./ft. =
Drill Collars
ft.
x
0.0077
bbl./ft. =
Drill Collars
ft.
x
0.0000
bbl./ft. =
Kickoff MD
Kickoff TVD
psi.
bbl.
Strokes
bbl.
bbl.
bbl.
bbl.
bbl.
54.5
374
bbl.
Strokes
Version 2.0 (4/15/00)
PRERECORDED WELL DATA
(Highly Deviated and Horizontal Wells)
(page 2)
INTERNAL CAPACITIES (Section 3 - Start of Hold to TD of Bit)
Drill Pipe 1
0
ft.
x
0.0141
bbl./ft. =
Drill Pipe 2
ft.
x
0.0000
bbl./ft. =
HW Drill Pipe
1000
ft.
x
0.0074
bbl./ft. =
Drill Collars
100
ft.
x
0.0077
bbl./ft. =
Drill Collars
ft.
x
0.0000
bbl./ft. =
0.0
0.0
7.4
0.8
0.0
bbl.
bbl.
bbl.
bbl.
bbl.
Section 3 Subtotal Internal Capacities =
Total MD
Total TVD
8.2
56
bbl.
Strokes
720
Strokes
8,300
6,000
TOTAL INTERNAL CAPACITY
Msrd. Depth(Bit)
8,300 ft.
ANNULUS CAPACITIES
DP1 x Csg.
7,200
DP1 x Liner
DP1 x Hole
DP2 x Csg.
DP2 x Liner
DP2 x Hole
HW DP x Csg.
HW DP x Liner
HW DP x Hole
1,000
DC1 x Csg
DC1 x Liner
DC1 x Hole
100
DC2 x Csg
DC2 x Liner
DC2 x Hole
ft.
ft.
ft.
ft.
ft.
ft.
ft.
ft.
ft.
ft.
ft.
ft.
ft.
ft.
ft.
Msrd Depth(bit)
ft.
8,300
Total Internal =
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
0.0505
0.0000
0.0505
0.0000
0.0000
0.0000
0.0505
0.0000
0.0505
0.0259
0.0000
0.0259
0.0000
0.0000
0.0000
Total Annulus =
System Volume =
(Internal + Annulus)
522.0
105.0
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
417.0
bbl.
=
bbl. =
363.8
0.0
0.0
0.0
0.0
0.0
0.0
0.0
50.5
0.0
0.0
2.6
0.0
0.0
0.0
bbl. =
3,581
Active Pit Volume
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
2,860
Strokes
500
MAX INITIAL SICP TO FRACTURE FORMATION AT SHOE
Max. SICP = (Shoe Test - Present Mud Wt.) x Shoe TVD x 0.007
=
[#
pcf EMW -
74
pcf MW]
x
6,000
G - 21
ft. x 0.007 =
2226
Strokes
psi
bbl.
DRILLER'S METHOD WORKSHEET
(Highly Deviated and Horizontal Wells)
PRERECORDED INFORMATION
A. Slow Pump Rate Data
Pump #1
( Use SPR Pressure through Riser for Subsea Pump
)
#2
SPM
30
40
INFORMATION RECORDED WHEN WELL KICKS
B.
C.
D.
E.
F.
psi
350
550
bbl/stk
0.1458
0.1458
bbl/min
4.4
5.8
13:35
Time of Kick:
B
C
D
E
F
Old Mud Weight
Initial Shut-In Drill Pipe Pressure (SIDP)
Initial Shut-In Casing Pressure (SICP)
Initial Pit Volume Increase
True Vertical Depth of Hole
Measured Depth of Hole (for Capacity Calculations ONLY)
74
200
300
15
6,000
8,300
pcf
psi
psi
bbl
ft (TVD)
ft (MD)
FIRST CIRCULATION TO CLEAR WELL OF INFLUX
Bring Pumps up to Speed While Holding Casing Pressure Constant
{Account for Choke Line Friction if Subsea}
30
SPM
Read and Record Initial Circulating Pressure on Drill Pipe
550
psi
G
5
pcf
H
79
pcf
I
1,022
bbl
J
838
50#
sacks
Casing Pressure
200
psi
Drill String Internal Capacity
720
strokes
Final Circulating Pressure
374
psi
[Should Approximately = Slow Pump Rate Pressure (A) + SIDP (C)]
Maintain Constant DP Pressure Until Influx is Circulated Out. Then Shut Down
Pumps While Holding Casing Pressure Constant. {Remember CLF for Subsea}. If Drill
Pipe and Casing Shut-In Pressures are not Equal, Continue to Circulate Out Influx.
G. Increase in Mud Weight required to Balance Kick
H. New Mud Weight
H=B+G=
I. Total Volume to Weight Iup
= Active Pit Vol + System Vol =
J. Barite Required
SECOND CIRCULATION TO BALANCE WELL
Bring Pumps up to Speed While Holding
Casing Pressure Constant. {Account for
CLF if Subsea} Maintain Constant Casing
Pressure Until New Mud Reaches the Bit.
Read and Record Drill Pipe Pressure
When New Mud Reaches the Bit
Maintain Constant Drill Pipe Pressure
Until the System is Displaced.
System Volume
3,581
strokes
Version 2.0 (4/15/00)
G-22
DRILLER'S METHOD WORKSHEET
(page 2)
RESERVOIR PRESSURE (Pr)
K
3318
L
0.0505
M
297
ft.
N
0.52
psi/ft.
O.
O
100
psi
P. TZ= Compressibility and Temperature Effects (Fig 11P.5)
P
0.95
Q
703
psi
R
803
psi
HEIGHT OF GAS BUBBLE AROUND DRILL PIPE (KH)
L. Annulus Capacity Factor (DP x Casing) Right Below Wellhead
psi
bbls/ft
MAXIMUM CASING PRESSURE (Pcmax) WHEN GAS GETS TO SURFACE
N.
Q. Pcmax, Part2 (Figure 11P.1)
R. Maximum Casing Pressure,
S. Does Pcmax Exceed the Wellhead or Casing Pressure Limitation?
YES
NO
X
VOLUME GAIN WHILE CIRCULATING OUT GAS BUBBLE
T. Volume of Gas at Surface (from Fig. 11P.4 or Formula below)
U. Volume Gain While Circulating Out Gas Kick
T
59
bbl
U
44
bbl
STROKES TO MAXIMUM CASING PRESSURE AND VOLUME
Maximum Casing Pressure and Excess Volume Occur When the Pumped Volume Equals
Total Annulus Capacity - Volume of Gas at Surface
bbl
strokes
358.1
2457
G-23
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SECTION H – ENGINEER’S METHOD
Table of Contents
1. 0
Description of the Method................................................................. H-2
Step 1
2.0
The Kick Is Detected - Shut The Well In....................................... H-2
Shut-In Procedure while Drilling .................................................... H-2
Shut-In Procedure while Tripping ................................................... H-2
Step 2a Allow the Well to Stabilize ........................................................... H-3
Step 2b Bumping the Drillpipe Float ........................................................ H-3
Step 3 Perform the Kick Control Calculations........................................ H-4
Step 4 Raise the Mud Weight in the Pits................................................. H-4
Step 5 Establish Circulation .................................................................. H-5
Step 6 Pumping Kill Mud from Bit .......................................................... H-6
Step 7 Pumping Kill Mud from Bit to Surface ......................................... H-6
Step 8 Shut Down and Check for Flow ................................................... H-7
Step 9 Circulate and Condition the Mud................................................. H-7
Using the Engineer’s Method Worksheet ..................................... H-8
Step 1 Pre-recorded Information............................................................ H-8
Step 2 Information to be Recorded when Well Kicks ............................. H-9
Step 3 Determining Mud Weight to Balance the Kick ............................. H-9
Rounding-Up Rule......................................................................... H-9
Step 4 Total Volume to Weight-Up........................................................ H-10
Step 5 Barite Required to Weight-Up.................................................... H-10
Step 6 Determining Initial Circulating Pressure ................................... H-10
Step 7 Determining Final Circulating Pressure .................................... H-11
Step 8 Drillpipe Pressure Schedule...................................................... H-11
Step 9 Determining Reservoir Pressure ............................................... H-13
Step 10 Determining Maximum Casing Pressure ................................... H-13
Pc Max (Part 1)........................................................................... H-13
Pc Max (Part 2)........................................................................... H-13
Step 11 Determining Pit Volume Gain for a Gas Kick ............................. H-14
Step 12 Maximum Casing Pressure & Excess Volume Occurrence ....... H-14
Pre-recorded Well Data Sheet (Vertical Well) .......................................... H-16
Engineer's Method Worksheet (Vertical Well)......................................... H-17
Figure P.2a (Pc Max - Part 1) ................................................................... H-19
Figure P.2b (Pc Max - Part 2) .................................................................. H-20
Figure P.3 (Volume Gain) ...................................................................... H-21
Pre-recorded Well Data Sheet (Highly Deviated or Horizontal Well)........ H-22
Engineer’s Method Worksheet (Highly Deviated or Horizontal Well)....... H-24
Current Revision:
Previous Revision:
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SECTION H – ENGINEER’S METHOD
1.0
Description of the Method
The Engineer's Method (also called the wait and weight method) is a well killing method
that requires only one complete circulation. The kill mud is circulated into the well at the
same time the kick is being removed from the annulus. During the circulation, the
bottomhole pressure is maintained at level equal to or slightly greater than the formation
pressure. The following information describes the Engineer's Method in detail from kick to
kill.
Step 1 - The Kick Is Detected (Shut the Well In)
As always, it is extremely important to get the well shut -in as quickly as possible in
order to minimize the size of the influx. The best way to achieve this is by using the
“Three S” Shut-In Procedure while Drilling or the “Three S” Shut -In Procedure while
Tripping.
Shut-In Procedure While Drilling
(1)
SPACE OUT
Pick up drill string and spot tool joint.
(2) SHUT DOWN
Stop the mud pumps.
(3)
Close the annular preventer or uppermost pipe ram
preventer. Confirm that the well is shut-in and flow has
stopped. Open HCR valve.
SHUT-IN
Shut-In Procedure While Tripping
(1) STAB VALVE Install Full Open Safety Valve (open position) in drill string.
Close the safety valve.
(2) SPACE OUT
Spot tool joint.
(3) SHUT-I N
Close the annular preventer or uppermost pipe ram
preventer. Confirm that the well is shut-in and flow has
stopped. Open HCR valve.
It should be stressed that in nearly all well kicks, the Driller will be responsible for
actually closing the preventers and shutting the well in. It is the duty of the Saudi
Aramco Drilling Foreman to make sure the Driller can execute the proper shut-in
procedure. The Driller must have the initiative and experience to do this alone if
required. There will be plenty of time after the well is shut-in to retrieve crews from
the mud pits and notify the Toolpusher. The Driller must not delay when shutting
in the well.
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SECTION H – ENGINEER’S METHOD
Step 2a - Allow the Well to Stabilize, Record Pressure and Volume Gained
After the well is shut-in, it may take a few minutes for the shut-in pressures to
stabilize. If the pipe is reciprocated through the annular preventer during the kill, use
this time to reduce the annular closing pressure to reduce element wear. Make sure
the bag does not leak at the reduced pressure!
With your choke manifold ilned-up properly, open the choke line valve at the
preventer stack and read the shut-in casing pressure at the choke manifold. If no
drillpipe float is installed, read and record the shut-in drillpipe pressure as well.
Finally, examine the pit volume charts to determine the volume gained during the kick
and verify this number with the Derrickman.
Step 2b - Bumping the Drillpipe Float
If a drillpipe float is installed, the pressure gauge on the drillpipe will probably read
near zero. In order to get an accurate value for the shut-in drillpipe pressure, “bump”
the float open by slowly pumping down the drillpipe. The correct procedure for
bumping the float is given below.
Float Bumping Procedure
(1)
(2)
(3)
(4)
(5)
(6)
Make sure the well is shut-in and that the shut-in casing pressure is
recorded.
Slowly pump down the drillpipe while monitoring both the casing and
drillpipe pressure.
The drillpipe pressure will increase as pumping is begun. Watch carefully
for a “lull” in the drillpipe pressure (a hesitation in the rate of increase),
which will occur as the float is pumped off of its seat. Record the drillpipe
pressure when the lull is first seen.
To verify that the float has been pumped open, continue pumping down
the drillpipe very slowly until an increase in the casing pressure is
observed. This should occur very soon after the lull is detected on the
drillpipe gauge.
Shut down the pump as soon as you see the casing pressure begin
to increase and record the shut-in drillpipe pressure as the pressure at
which the lull was first seen, in Step 3 above (not the final drillpipe
pressure after the pumps are stopped).
Check the shut-in casing pressure again. Any excess pressure may be
bled-off in small increments until equal casing pressure readings are
observed after two consecutive bleed-offs.
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Previous Revision:
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SECTION H – ENGINEER’S METHOD
Sometimes the float bumping procedure can be difficult to perform if the rig has big
duplex pumps, which are compounded. Clutch the pumps in short burst to slowly
build up pressure on the drillpipe. It’s more likely that a drillpipe “lull” won’t take place
before the casing pressure starts to increase when using this procedure. To
determine the shut-in drillpipe pressure in these instances, subtract the increase in
shut-in casing pressure from the final value of shut-in drillpipe pressure after the
pumps have been stopped. The equation for this calculation is given below. Use this
value as the official shut-in drillpipe pressure.
If excess pressure is trapped on the
drillpipe when bumping the float…
Shut-in
Drillpipe =
Pressure
Shut-in drillpipe
pressure after
bumping float
-
Increase in shut-in
casing pressure while
bumping float.
Step 3 - Perform the Kick Control Calculations
Calculations should be performed using the Engineer's Method Worksheet before the
kill mud is circulated into the well. Several critical items will be determined including:
•
•
•
•
•
Drillpipe pressure schedule
Bottomhole reservoir pressure
Mud weight necessary to balance the kick
Maximum surface casing pressure during the kill circulation
Maximum excess mud volume gained during the kill circulation
An example problem illustrating the use of the Engineer's Method Worksheet is
provided later in this section.
One thing to keep in mind while performing your calculations is that the formation
fluids in the annulus, especially gas, may migrate up the hole and cause an increase
in the shut-in casing pressure. If the shut-in c asing pressure starts increasing
substantially to the point of risking an underground blowout or exceeding the
wellhead or casing pressure limitation, bleed-off some of the excess pressure
through the choke. It is better to bleed the pressure off in small increments rather
than one large slug. Any excess pressure, which appears on the annulus due to the
migrating gas bubble, may be bled-off in small increments until equal readings are
observed after two consecutive bleed-offs.
Step 4 - Raise the Mud Weight in the Pits
As soon as the required mud weight has been calculated, raising the mud weight in
the pits should begin. The first step is to reduce the mud volume in the active pits to
make room for weighting material. The amount of barite required to increase the mud
weight is determined in part ‘J’ of the Engineer's Method Worksheet. If barite required
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SECTION H – ENGINEER’S METHOD
exceeds barite on hand, either further reduce the volume in the active system or
proceed with the Drillers Method. The mud mixing facilities and pit volumes on the
particular rig will dictate to some extent just how the mud should be handled. The
ideal situation is to maintain a reasonably low-volume active system so that the mud
circulated out of the hole can be weighted up without having to stop circulating. It
may be desirable to weight up enough mud to displace the entire hole before the
killing operation is started. Many variables will enter into this decision, so each
situation must be handled on its own merits. The important thing is that the mud
weight can be raised while the well is being circulated.
Meanwhile, formation fluids in the annulus, especially gas, will migrate, causing an
increase in casing pressures. Also, the longer formation fluids are in the annulus, the
more likely pipe sticking becomes. Therefore, it is important to proceed as quickly as
possible.
Step 5 - Establish Circulation
After the kick control calculations have been performed and the mud has been
weighted-up properly, the well should be circulated through the choke using the
information recorded on the Engineer's Method Worksheet. Before breaking
circulation, be sure to check the following items.
(1)
(2)
(3)
(4)
Be sure that all members of the crew knows exactly what his duties are
before the kill operation begins. (See Section M in this volume for more
details.)
Eliminate all sources of ignition in the immediate vicinity of the rig and vent
lines. See that the vent lines on the mud-gas separator and mud degasser
are secured properly and, if possible, are downwind from the rig.
Make sure your circulating system (including manifolds and pits) are lined-up
correctly.
Zero the stroke counter and make a note of the time.
When establishing circulation in a well closed in under pressure, backpressure on the
well is very difficult to control. The procedure is critical, since additional influx will
result if too little backpressure is held, and the formation can breakdown if too much
backpressure is held.
The procedure requires simultaneous manipulation of the choke and the pump
speed. While the pumps are being brought up to speed, the choke is opened in such
a way that casing pressure is maintained constant at its shut-in value just prior to the
start of pumping. As the pump speed is increased up to the desired kill rate, drillpipe
pressure will increase, but casing pressure must be held constant. Successful
manipulation of the choke while establishing circulation in this manner will maintain
constant bottomhole pressure.
Current Revision:
Previous Revision:
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SECTION H – ENGINEER’S METHOD
The chosen pump rate must be held constant throughout the killing of the well. If the
pump rate is allowed to vary without adjusting the choke size, constant bottomhole
pressure will not be maintained. If the pump rate is increased, additional friction
pressure will cause the drillpipe pressure to increase. If the choke is adjusted to lower
the drill pipe pressure to its assumed correct value, then the bottomhole pressure is
reduced, possibly allowing another influx. Conversely, if the pump rate is reduced,
the reduction in friction pressure will be noted and the choke adjusted to increase the
drill pipe pressure, possibly creating sufficient overpressure at the casing shoe to
cause a breakdown. Therefore, any change in pump rate should be made known to
the choke operator and the pump returned to the original rate.
Step 6 - Follow the Drillpipe Pressure Schedule While Pumping Kill Mud
After circulation has been established and the pumps are operating at the desired kill
rate, the previously calculated initial circulating pressure should be observed on the
drillpipe pressure gauge. As the kill mud goes down the drillpipe, gradually adjust the
choke so that the drillpipe pressure closely tracks the drillpipe pressure schedule
calculated earlier. At this point in the kill procedure, constant bottom-hole pressure is
being maintained by following the drillpipe pressure schedule and by making slight
choke adjustments. Do not change the pump rate to accomplish this. Also, do not
make choke adjustments in order to keep the casing pressure constant while the
drillpipe is being displaced with kill mud. When an influx rises above the drill collars to
around the drillpipe, the influx column height is reduced as a result of the larger
annular capacity around the drillpipe as compared to around the drill collars. This
reduction increases the hydrostatic head in the annulus. Therefore, as constant
bottomhole hold pressure is being maintained by following the drillpipe profile, it is
possible to see a drop in casing pressure as the influx height shortens.
When the kill weight mud gets to the bottom of the drill string, the pressure on the
drillpipe should be the final circulating pressure, as recorded at ‘L’ on the worksheet.
Step 7 - Hold the Drillpipe Pressure Constant for the Remainder of the Kill
When kill mud starts to be circulated up the annulus, the choke must be manipulated
so that drillpipe pressure is maintained constant at the final circulating pressure.
As the gas and contaminated mud are circulated to the surface, the gas will begin to
expand, increasing both the casing pressure and pit volume. A pure gas contaminant
will increase the casing pressure to the value shown at ‘W’ on the worksheet. It will
be less if the kick also includes water and/or oil. Probably the most critical stage of
the killing operation takes place at this time, and panicking can very turn a good job
into a disaster.
Current Revision:
Previous Revision:
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October 1998
H-6
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SECTION H – ENGINEER’S METHOD
It can sometimes be difficult to bleed the gas off fast enough to keep the drill pipe
pressure within limits, but excessive pressure could cause formation breakdown. If
the gas cannot be released fast enough from the annulus to prevent an increase in
drill pipe pressure, the pumps may have to be slowed or even stopped until the
casing pressure is bled down. For this reason, it is a good idea to take several slow
pump rates (including one at the slowest pump rate possible) so that the new drillpipe
pressure at the reduced pumping rate can be determined. If the pumps must be
stopped while bleeding down the casing pressure, attempt to hold the drillpipe
pressure at or above the original shut-in pressure while bleeding. If the drillpipe
pressure drops below this value, another kick may occur. The pumps should be
returned to the original rate as soon as possible. This method is not ideal, but is
necessary when the surface facilities cannot safely handle the high flow rates.
Continue circulation until the entire system is full of the kill weight mud. The
approximate strokes required are indicated on the pre-recorded data sheet.
Step 8 - Shut Down and Check for Flow
After the entire hole volume has been displaced with kill mud, the pumps can be shut
down and the well shut-in. When shutting down the pumps, the choke should be
closed (holding casing pressure constant) gradually as the pump speed is reduced.
Note: The casing pressure may already be reading zero before the pumps are
shut down. This is normal and may be expected.
As the pump speed decreases, the drillpipe pressure will slowly decrease to zero.
After the well is shut-in, both the casing and drillpipe pressures should be zero.
Confirm that the well is dead by cracking open the choke; the well should not flow. If
the well is dead, the BOP's can be opened. Keep in mind that a small volume of gas
may be trapped between the annular preventer and the choke line. Exercise caution
on the rig floor when opening the preventers.
Step 9 - Circulate and Condition the Mud
After the BOP’s are opened, the mud should be circulated and conditioned to the
desired properties. Usually, the yield point is too high. Thus, running or pulling pipe
can cause excessive pressure on the formation or swabbing, and either could lead to
another kick.
Current Revision:
Previous Revision:
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October 1998
H-7
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SECTION H – ENGINEER’S METHOD
2.0
Using the Engineer’s Method Worksheet
The Engineer's Method Worksheet is a step-by-step instruction sheet to help the Drilling
Foreman calculate the critical well control parameters that are necessary to successfully
kill a well using the Engineer's Method. Use of the Worksheet is demonstrated here
through the use of an example problem described below:
EXAMPLE PROBLEM
A well is being drilled, and the following data are known prior to kick:
Triplex Pumps:
Casing Size:
Hole Size:
Csg Pressure Limitation:
Shoe Test:
Drill Pipe Size:
Drill Collar Size:
Mud Weight:
Active Surface System:
16” stroke, 96% vol. eff. (6-1/4” liner)
9-5/8” set at 5,500 ft MD/TVD
8-1/2”
3,160 psi @ 80% burst
2,040 psi with 74 pcf mud
4-1/2”, 16.60 lb/ft
6-3/4” OD x 2-13/16” ID (450 ft long)
74 pcf
750 bbls before kick
500 bbls at start of kill operation
Slow Pump Rate Data:
SPM
30
40
PSI
350
550
While drilling at 8,000' TVD, the well kicked and the BOP's were closed.
The following data were observed:
Initial Drill Pipe Pressure
Initial Casing Pressure
Pit Volume Gain
=
=
=
200 psi
300 psi
15 bbl
The following pages describe a step-by-step procedure for determining the well control
parameters, which are necessary to kill the example problem well using the Engineer's
Method.
Step 1 - Pre-recorded Information
Prior to the kick, and at all times, your pre-recorded data sheet should be completely
filled-out except for the measured depth and the length of drillpipe in the hole. Enter
these items and calculate the internal drillstring capacity and the system totals.
Transfer the slow pump rate data from the pre-recorded data sheet to line A of the
Engineer's Method worksheet.
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Previous Revision:
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SECTION H – ENGINEER’S METHOD
Step 2 - Information to be Recorded when Well Kicks
Many items of information need to be gathered when a well kicks. These include:
•
•
•
•
•
•
Old Mud Weight
Pit Volume Increase
Initial Shut-in Drill Pipe Pressure
True Vertical Depth Of Hole
Initial Shut-in Casing Pressure
Measured Depth Of Hole
This information should be recorded in lines B through F on the Engineer's Method
worksheet.
Step 3 - Determining Mud Weight to Balance the Kick
Using the equation below, calculate the increase in mud weight necessary to balance
the kick.
Increase in
Mud Weight
Initial Shut-in Drillpipe Pressure (SIDP)
=
-----------------------------------------0.007 X TVD
=
200
------------------0.007 X 8,000
=
3.6 pcf
Rounding-Up Rule: The increase in mud weight should be calculated to the tenths
place. If the number in the tenths place is greater than zero,
then roundup the number one full pcf. In this example, the
number in the tenths place is six, so the weight is rounded-up
to 4 pcf.
Record an 4 pcf increase on line G of the Engineer's Method worksheet. Adding the
mud weight increase G to the old mud weight B yields the new mud weight required
to balance the kick.
New Mud Weight To Balance The Kick = Old Mud Weight + Increase In Mud Weight
= 74 + 4
= 78 pcf
Enter the new mud weight in part H of the worksheet.
Current Revision:
Previous Revision:
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SECTION H – ENGINEER’S METHOD
The mud weight determined by this procedure will provide a hydrostatic pressure
equal to the BHP and sufficient to kill the well, but perhaps not high enough for
making a trip. Weighting up a mud increases its yield point, causing increased
pressure on the formation during circulation (the equivalent circulating density). As
extra mud weight and a higher yield point could fracture the formation, it is best to
adjust the yield point and add a trip margin after the well is killed.
Step 4 - Total Volume to Weight-Up
As discussed in the Driller's Method, there are several reasons why you should
reduce the volume of mud in your surface pits before weighting up. Again some of
these reasons are:
•
•
•
It takes less time to weight up less volume.
It requires less barite to weight up less volume.
It may overflow your pits while you are circulating the influx out.
Whatever the reason, decide on the volume that you are going to use and add it to
your system volume (from the pre-recorded data sheet) to determine the total volume
to weight up. In our example we again used 500 barrels to arrive at a total volume to
weight up of 1,001 bbls. Record this value at I on the worksheet.
Step 5 - Barite Required to Weight-Up
Again, the same formula used to determine barite requirements for the Driller's
Method will be used to calculate the volume required for the Engineer's Method. The
equation is shown below:
Barite Required
= Total Volume
to Weight Up
30.0 x Increase in Mud Weight
x
___________________________
262.0 – New Mud Weight
Note that this equation assumes you are using 50 pound sacks of barite.
Step 6 - Determining Initial Circulating Pressure
Immediately after the pumps are operating at the desired kill rate and kill mud is
going down the hole, the initial circulating pressure should be observed on the
drillpipe gauge. The initial circulating pressure can be calculated by adding the slow
pump rate pressure at the desired kill rate A to the initial shut-in drill pipe pressure C.
This is expressed mathematically by:
Initial Circulating Pressure = Slow Pump Rate Pressure + Shut-in Drillpipe Pressure
Current Revision:
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SECTION H – ENGINEER’S METHOD
In this example 30 SPM was selected; therefore the initial circulating pressure will be
200 + 350 = 550 psi; record this value at K.
Note: If for some reason the pre-recorded circulating pressures at various rates
are unavailable, the initial drill pipe circulating pressure can be
determined by proceeding as follows:
a) Hold casing pressure constant until the pump is at the desired speed.
b) Read the drill pipe pressure at that time. This pressure minus the
initial shut-in drill pipe pressure will be the reduced circulating
pressure at the desired speed and would be used to calculate the final
circulating drill pipe pressure.
This procedure is enumerated in step form on the back of the Engineer’s
Method worksheet.
Step 7 - Determining Final Circulating Pressure
The final circulating pressure is the pressure the drillpipe gauge should read when kill
mud reaches the bit. The final circulating pressure can be calculated by the formula:
Final Circulating Pressure =
Slow Pump
x
Rate Pressure
=
200
x
=
369 psi
New Mud Weight
Old Mud Weight
78
74
Step 8 - Drillpipe Pressure Schedule
Successful well killing with the Engineer's Method requires that the drillpipe pressure
decrease from a higher value (initial circulating pressure) to a lower value (final
circulating pressure) as kill mud is pumped down the drillstring. It is very important
that the drillpipe pressure be reduced smoothly in small increments as the drillpipe is
filled with kill mud. The drillpipe pressure should not be reduced all at once when the
kill mud reaches the bit.
In order to accomplish the smooth transition from initial circulating pressure to the
final circulating pressure, create a drillpipe pressure schedule which displays the
correct circulating drillpipe pressure at 50 or 100 stroke increments as kill mud is
pumped down the drillstring. The Drilling Foreman can track the drillpipe pressure
and the pump strokes and make small choke adjustments so that the observed
drillpipe pressures are equal to the calculated values displayed on the schedule at all
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SECTION H – ENGINEER’S METHOD
points during the circulation. It is important to realize that this drillpipe pressure drop
should require minimal choke adjustments since the hydrostatic pressure in the
drillpipe will be increasing automatically as the kill mud is pumped down.
The first step in creating the drillpipe pressure schedule is to transfer the internal,
annulus and system capacity values from the pre-recorded data sheet to lines N and
O on the Engineer's Method worksheet.
Next, record your calculated initial circulating pressure K on the top/right side of the
schedule table and record zero strokes on the left side.
Next, record your calculated final circulating pressure L on the bottom line of the
schedule table [on the right] opposite the total internal stroke capacity [on the left].
We now need to fill-in the lines between the initial circulating pressure and the final
circulating pressure on the drillpipe pressure schedule table. The drillpipe pressure
drop per stroke can be calculated with the following formula:
Drillpipe Pressure
Drop (per stroke)
Initial Circulating Pressure – Final Circulating Pressure
=
________________________________________________
Total Internal Stroke Capacity
550 - 369
=
_________
744
=
0.24 psi/stroke
This equation will normally yield a fraction of a psi reduction per pump stroke, which
is too small for us to accurately measure on the rig. Therefore, arbitrarily choose a
stroke increment (100 strokes), which becomes the point of reference as kill mud is
pumped down the drillpipe. Instead of reducing the drillpipe pressure 0.24 psi per
stroke, we reduce it 24 psi per 100 strokes (which is essentially the same thing).
Then, subtract this pressure decline (24 psi per 100 strokes) from the initial
circulating pressure at each increment until the final circulating pressure at the total
internal capacity is reached. The schedule is completed by adding stroke increments
on the left side and subtracting pressure increments from the right side.
Current Revision:
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SECTION H – ENGINEER’S METHOD
Step 9 - Determining Reservoir Pressure
Calculate the reservoir pressure as an intermediate step in determining the more
critical well control parameters such as maximum casing pressure and excess
volume. To determine the reservoir pressure, simply multiply the following:
Reservoir Pressure = New Mud Weight x 0.007 x True Vertical Depth
= 78 x 0.007 x 8000
= 4368 psi
Record this value on the back of the worksheet at P.
Step 10 - Determining Maximum Casing Pressure
If the kick is gas, then the maximum casing pressure will occur when the gas first
reaches the surface. We must calculate this value before its arrival to determine if our
wellhead and casing can withstand the pressure. Unfortunately, the mathematical
formula used to determine the maximum casing pressure is complex. To simplify the
calculation of maximum casing pressure, charts have been developed and are
included in the back of this section and Section P. The maximum casing pressure (P c
Max) is calculated in two steps so two charts are required.
Pc Max (Part 1)
On Figure P.2a, enter the left vertical axis at the true vertical depth (8,000
ft), and read across to the line for the drillpipe by hole annulus capacity
factor (use line B: 8-5/8" hole, 4-1/2" drillpipe). Drop a vertical line to the
increase in mud weight (4 pcf), and then read across to the right vertical
axis to find Pc max Part 1 (30 psi). Record this value at U.
Pc Max (Part 2)
On Figure P.2b, begin at the upper horizontal axis at the new mud weight
(78 pcf). Drop a vertical line to the reservoir pressure (4368 psi), and then
run a horizontal line to the curve corresponding to the original kick volume
(15 bbl). Drop another vertical line to the drillpipe by hole annulus capacity
factor (8-5/8" hole, 4-1/2" drillpipe), then run a horizontal line to the right
vertical axis and read Pc Max (Part 2). Record this value (774 psi) at V on
the worksheet.
To determine the maximum surface casing pressure while properly circulating out a
pure gas kick (P c Max) simply add U to V; record this value at W. As an alternative to
the charts, the killsheet provides equations to calculate Pc Max.
Current Revision:
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SECTION H – ENGINEER’S METHOD
The next question is very important and its answer may determine the course of
action, which is taken for the kill. In most cases, it will be allowed to go to 100% of
the wellhead pressure or BOP ratings, but only 80% of the casing burst
pressure. Generally speaking, the casing pressure is significant only if it should
exceed the pressure rating of the casing, well head or BOPs. It is seldom possible to
calculate with accuracy whether oil, gas, or water has entered the hole, but with rare
exceptions gas is always present. The method described above will indicate the
maximum possible casing pressure and pit volume gain if pure gas has entered.
Water or oil will decrease the casing pressure and volume gain somewhat from those
shown on the worksheet, and can be handled satisfactorily.
At this point the maximum permissible casing pressure should have been determined
and a decision made as to whether to circulate the formation fluid out of the hole.
Note:
The method used here to graphically determine the maximum surface
pressure is in error by the hydrostatic pressure of the gas column.
Step 11 - Determining Pit Volume Gain for a Gas Kick
A convenient chart is also provided to determine the maximum pit volume gain, which
will occur if the kick is completely gas. Use Figure P.3 to calculate the volume gained.
Enter the top right horizontal axis at the maximum surface casing pressure (804 psi).
Read down to the reservoir pressure (4368 psi) then across to the original kick
volume (15 bbl). Read down to the horizontal axis to obtain the volume of gas at the
surface (69 bbl); record this volume at X. Subtract the initial pit volume increase E
from X to determine the pit volume gain due to gas expansion while the bubble is
being circulated to the surface (54 bbl); record this value at Y.
The volume gained due to barite addition is simplified by the equation shown in
part Z. It is approximated by dividing the barite required to weight up J by 30 sacks of
barite per bbl of additional volume increase; record this value at Z. The total volume
gain while circulating out a gas kick is calculated by adding part Y to part Z; record
this value on the back of the worksheet.
Step 12 - Determining when Maximum Casing Pressure & Excess Volume Occur
Subtract the volume of gas at the surface X from the annulus capacity N to determine
when the maximum casing pressure and excess volume will occur (393 - 69 = 324
bbl, or 2225 strokes). Record these values in the proper spaces provided.
Current Revision:
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H - 14
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SECTION H – ENGINEER’S METHOD
Note:
The maximum casing pressure and excess volume may not occur
exactly at the number of strokes calculated due to gas migration or
hole washout.
The following pages provide completed samples of the worksheet and Figures used
in the previous example problem, including:
•
•
•
•
•
•
•
Pre-recorded Data Sheet (Vertical Well)
Engineer’s Method Worksheet (Vertical Well)
Figure P.2a (Pc Max - Part 1)
Figure P.2b (Pc Max - Part 2)
Figure P.3 (Volume Gain)
Pre-recorded Data Sheet (Highly Deviated or Horizontal Well)
Engineer’s Method Worksheet (Highly Deviated or Horizontal Well)
The Pre-recorded Data Sheets and Worksheets (for both vertical and highly
deviated/horizontal wells) are also developed in Excel spreadsheets, which perform
all required calculations.
Current Revision:
Previous Revision:
October 2002
October 1998
H - 15
3rd Edition
PRE-RECORDED WELL DATA
KEEP THIS DATA SHEET CURRENT AT ALL TIMES
(Vertical and Deviated Wells)
Well Name
HOLE DATA
Field Zuluf
Zuluf Well #1005
Size(actual)
8.5000
Liners (in.)
6.25
6.25
PUMP DATA
No. 1
No. 2
Hole MD
Stroke(in.)
16
16
CASING (LAST SET) DATA
9.6250
by
8.5000
(in. OD)
(in. Avg ID)
8,000
Rod(in. )
Shoe MD
Rig Nadrico #1
ft.
Hole TVD
% Eff.
96
96
bbl./stk
0.1458
0.1458
* X if used, empty if not
5,500
(feet)
Shoe TVD
5,500
(feet)
Limitation =
3160
psi.
WELLHEAD OR CASING PRESSURE LIMITATION
The lessor of: 100% BOP Rating
5,000
psi.
100% Wellhead Rating
5,000
psi.
80% Casing Burst
3,160
psi.
LINER CASING DATA
by
(in. OD)
(in. Avg ID)
DRILL STRING DATA
Drill Pipe 1
4.5000
Drill Pipe 2
HW Drill Pipe
4.5000
in. (OD)
in. (OD)
in. (OD)
INTERNAL CAPACITIES
Drill Pipe 1
7,220
Drill Pipe 2
HW Drill Pipe
330
Drill Collars
450
Drill Collars
ft.
ft.
ft.
ft.
ft.
Msrd Depth(bit)
ft.
8,000
Top @
41.5
x
x
x
x
x
0.0141
0.0074
0.0077
0.0000
Total Internal =
lb./ft.
lb./ft.
lb./ft.
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
107.7
(Note: Use other side for subsea)
ft.
x
0.0505 bbl./ft. =
ft.
x
0.0000 bbl./ft. =
ft.
x
0.0505 bbl./ft. =
ft.
x
0.0000 bbl./ft. =
ft.
x
0.0000 bbl./ft. =
ft.
x
0.0000 bbl./ft. =
ft.
x
0.0505 bbl./ft. =
ft.
x
0.0259 bbl./ft. =
ft.
x
0.0000 bbl./ft. =
Msrd Depth(bit)
ft.
Total Annulus =
MD(feet)
OD(in.)
6.75
ANNULUS CAPACITIES
DP1 x Csg.
5,500
DP1 x Liner
0
DP1 x Hole
1,720
DP2 x Csg.
0
DP2 x Liner
0
DP2 x Hole
0
HW DP
330
DC x Hole
450
DC x Hole
0
8,000
393.2
101.8
0.0
2.4
3.5
0.0
bbl.
bbl.
bbl.
bbl.
bbl.
bbl. =
277.9
0.0
86.9
0.0
0.0
0.0
16.7
11.7
0.0
bbl. =
739
Strokes
2,697
Strokes
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
500.9
bbl.
=
3,436
Strokes
Volume from Bit to Shoe =
86.9
bbl.
=
596
Strokes
Active Pit Volume
x 0.007 x
H-16
5,500
ft. =
(Shoe TVD)
TVD(feet)
DRILL COLLARS
ID(in.)
by
2.8125
by
System Volume (Internal + Annulus) =
MAX INITIAL SICP TO FRACTURE SHOE
[
127
pcf EMW 74
pcf MW]
(Shoe Test)
(Present Mud Weight)
ft.
ft. Shoe @
MD(feet)
16.6
8,000
*Use
For Kill?
X
500
bbl.
2041
psi.
Version 2.0 (4/15/00)
ENGINEER'S METHOD WORKSHEET
(Vertical and Deviated Wells)
A. Slow Pump Rate Data
( Use SPR Pressure thru Riser for Subsea )
Pump #1
Pump #2
SPM
30
40
psi
350
550
bbl/stk
0.1458
0.1458
bbl/min
4.37
5.83
Time of Kick:
B.
C.
D.
E.
F.
Old Mud Weight
Initial Shut-In Drill Pipe Pressure (SIDP)
Initial Shut-In Casing Pressure (SICP)
Initial Pit Volume Increase
True Vertical Depth of Hole
Measured Depth of Hole (for Capacity Calculations ONLY)
B
C
D
E
F
13:35
74.0
200
300
15
8000
8000
G
4.0
pcf
H
78.0
pcf
pcf
psi
psi
bbl
ft (TVD)
ft (MD)
G. Increase in Mud Weight required to Balance Kick
H. New Mud Weight
H=B+G=
I = Active Pit Vol + System Vol =
I. Total Volume to Weight up
I
1001 bbl
J
653
50# sacks
K
550
psi
L
369
psi
J. Barite Required
K. Slow Pump Rate Pressure + SIDP
K =A+C=
L. Slow Pump Rate Pressure X (New Mud Wt / Old Mud Wt)
M
N
O
M. Total Internal Capacity (from Prerecorded Well Data)
N. Total Annulus Capacity (from Prerecorded Well Data)
O. System Volume (from Prerecorded Well Data)
strokes
739
2697
3436
107.7 bbl
393.2 bbl
500.9 bbl
24.5
Total Internal Cap (M) =
Strokes
0
100
200
300
400
500
600
700
0
0
0
739
Pressure (psi)
550
525
501
476
452
427
403
378
369
H-17
psi/strk incr
= Initial Circ. Press. (K)
= Final Circ. Press. (L)
Version 2.0 (4/15/00)
ENGINEER'S METHOD WORKSHEET
(page 2)
RESERVOIR PRESSURE (Pr)
MAXIMUM CASING PRESSURE (Pcmax) WHEN GAS GETS TO SURFACE
Q. Drill String Capacity from Prerecorded Data
R. Annulus Capacity Factor (DP x Casing) Right Below Wellhead =
P
4368
psi
Q
108
bbl
R
0.0505
S
0.84
T
0.55
bbl/ft
S. Temperature and Compression Effects. (From Fig. 11P.5 or Formula Below)
T. New Mud Weight Gradient
(Surface) U
psi/ft
30
psi
0
psi
(Subsea) U
30
psi
V
774
psi
W
804
psi
NO
X
X
69
bbl
Y
54
bbl
Z
22
bbl
76
bbl
(Optional Correction for Subsea Wells)
U. (Subsea) A correction must be added to PCmax, Part 1 calculated above to
account for the choke line.
(Subsea) U = Subsea Correction + (Surface) U =
(use this new U in Part V. and Part W. below)
W. Maximum Casing Pressure,
Does Pcmax Exceed the Wellhead or Casing Pressure Limitation?
YES
VOLUME GAIN WHILE CIRCULATING OUT GAS BUBBLE
X. Volume of Gas at Surface (From Formula Below)
Y. Volume Gain While Circulating Out Gas Kick
Y=X-E
Z. Volume Gain due to Barite Addition
Total Volume Gain While Circulating Out Gas Kick = Y + Z
STROKES TO MAXIMUM CASING PRESSURE AND VOLUME
Maximum Casing Pressure and Excess Volume Occur When the Pumped Volume Equals
bbl
strokes
324
2225
Total Annulus Capacity - Volume of Gas at Surface =N - X
H-18
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SECTION H – ENGINEER’S METHOD
Current Revision:
Previous Revision:
October 2002
October 1998
H - 19
3rd Edition
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SECTION H – ENGINEER’S METHOD
Current Revision:
Previous Revision:
October 2002
October 1998
H - 20
3rd Edition
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SECTION H – ENGINEER’S METHOD
Current Revision:
Previous Revision:
October 2002
October 1998
H - 21
3rd Edition
PRE-RECORDED WELL DATA
KEEP THIS DATA SHEET CURRENT AT ALL TIMES
(Highly Deviated and Horizontal Wells)
Well Name
Zuluf Well #1006
HOLE DATA
Size(avg)
8.5000
Hole Capacity: No pipe in hole
Field
Zuluf
Hole MD
8,300
0.0702
Rig Nadrico #1
ft.
bbls/ft x
Hole TVD
8,300
ft. =
6,000
ft.
582.8
bbl
*Use
For Kill?
X
(from BOP to MD)
PUMP DATA
No. 1
No. 2
Liners (in.) Stroke(in.) Rod(in. )
6.25
16
6.25
16
CASING (LAST SET) DATA
9.6250
by
(in. OD)
8.5000
Shoe MD
(in. Avg ID)
% Eff.
96
96
bbl./stk
0.1458
0.1458
* X if used, empty if not
7,200
(feet)
Shoe TVD
6,000
(feet)
Limitation =
4,600
WELLHEAD OR CASING PRESSURE LIMITATION
The lessor of: 100% BOP Rating
5,000 psi.
100% Wellhead Rating
5,000 psi.
80% Casing Burst
4,600 psi.
LINER CASING DATA
0.0000
by
(in. OD)
DRILL STRING DATA
Drill Pipe 1
4.5000
Drill Pipe 2
HW Drill Pipe
4.5000
0.0000
(in. Avg ID)
Top @
in. (OD)
in. (OD)
in. (OD)
16.6
41.5
0
MD(feet)
lb./ft.
lb./ft.
lb./ft.
INTERNAL CAPACITIES (Section 1 - Surface to Kickoff Point)
Drill Pipe 1
3,000 ft.
x
0.0141 bbl./ft. =
Drill Pipe 2
0
ft.
x
0.0000 bbl./ft. =
HW Drill Pipe
0
ft.
x
0.0074 bbl./ft. =
Drill Collars
ft.
x
0.0077 bbl./ft. =
Drill Collars
ft.
x
0.0000 bbl./ft. =
Shoe @
42.3
0.0
0.0
0.0
0.0
3,000
3,000
INTERNAL CAPACITIES (Section 2 - Kickoff Point to Start of Hold)
Drill Pipe 1
3,500 ft.
x
0.0141 bbl./ft. =
49.4
Drill Pipe 2
ft.
x
0
bbl./ft. =
0.0
HW Drill Pipe
700
ft.
x
0.0074 bbl./ft. =
5.2
Drill Collars
ft.
x
0.0077 bbl./ft. =
0.0
Drill Collars
ft.
x
0.0000 bbl./ft. =
0.0
Section 2 Subtotal Internal Capacities =
Start of Hold MD
Start of Hold TVD
7,200
6,000
(continued on next page)
H-22
0
0
MD(feet) TVD(feet)
DRILL COLLARS
OD(in.)
ID(in.)
6.75
by
2.8125
by
Section 1 Subtotal Internal Capacities =
Kickoff MD
Kickoff TVD
psi.
bbl.
bbl.
bbl.
bbl.
bbl.
42.3
290
bbl.
Strokes
bbl.
bbl.
bbl.
bbl.
bbl.
54.5
374
bbl.
Strokes
Version 2.0 (4/15/00)
PRE-RECORDED WELL DATA
(Highly Deviated and Horizontal Wells)
(page 2)
INTERNAL CAPACITIES (Section 3 - Start of Hold to TD of Bit)
Drill Pipe 1
0
ft.
x
0.0141 bbl./ft. =
Drill Pipe 2
ft.
x
0.0000 bbl./ft. =
HW Drill Pipe
1000
ft.
x
0.0074 bbl./ft. =
Drill Collars
100
ft.
x
0.0077 bbl./ft. =
Drill Collars
ft.
x
0.0000 bbl./ft. =
0.0
0.0
7.4
0.8
0.0
bbl.
bbl.
bbl.
bbl.
bbl.
Section 3 Subtotal Internal Capacities =
Total MD
Total TVD
8.2
56
bbl.
Strokes
720
Strokes
8,300
6,000
TOTAL INTERNAL CAPACITY
Msrd. Depth(Bit)
8,300 ft.
ANNULUS CAPACITIES
DP1 x Csg.
7,200
DP1 x Liner
DP1 x Hole
DP2 x Csg.
DP2 x Liner
DP2 x Hole
HW DP x Csg.
HW DP x Liner
HW DP x Hole
1,000
DC1 x Csg
DC1 x Liner
DC1 x Hole
100
DC2 x Csg
DC2 x Liner
DC2 x Hole
ft.
ft.
ft.
ft.
ft.
ft.
ft.
ft.
ft.
ft.
ft.
ft.
ft.
ft.
ft.
Msrd Depth(bit)
ft.
8,300
Total Internal = 105.0
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
0.0505
0.0000
0.0505
0.0000
0.0000
0.0000
0.0505
0.0000
0.0505
0.0259
0.0000
0.0259
0.0000
0.0000
0.0000
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
bbl./ft. =
Total Annulus = 417.0
System Volume =
522.0
(Internal + Annulus)
bbl.
=
bbl. =
363.8
0.0
0.0
0.0
0.0
0.0
0.0
0.0
50.5
0.0
0.0
2.6
0.0
0.0
0.0
bbl. =
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
bbl.
2,860
3,581
Strokes
Active Pit Volume
500
MAX INITIAL SICP TO FRACTURE FORMATION AT SHOE
Max. SICP = (Shoe Test - Present Mud Wt.) x Shoe TVD x 0.007
=
[#
pcf EMW -
74
pcf MW] x
6,000
H-23
ft. x 0.007 =
2226
psi
Strokes
bbl.
ENGINEER'S METHOD WORKSHEET
(Highly Deviated and Horizontal Wells)
PRERECORDED INFORMATION
A. Slow Pump Rate Data
( Use SPR Pressure thru Riser for Subsea )
Pump #1
Pump #2
SPM
30
40
INFORMATION RECORDED WHEN WELL KICKS
B. Old Mud Weight
C. Initial Shut-In Drill Pipe Pressure (SIDP)
D. Initial Shut-In Casing Pressure (SICP)
E. Initial Pit Volume Increase
F. True Vertical Depth of Hole
Measured Depth of Hole (for Capacity Calculations ONLY)
psi
350
550
bbl/stk
0.1458
0.1458
bbl/min
4.4
5.8
Time of Kick:
B
C
D
E
F
13:35
74
200
300
15
6,000
8,300
G
5
pcf
H
79
pcf
I
1,022
bbl
J
838
50# sacks
K
550
psi
FINAL CIRCULATING PRESSURE
L. Slow Pump Rate Pressure X (New Mud Wt / Old Mud Wt)
L
374
psi
CIRCULATING PRESSURE AT KICKOFF POINT
M. Total Internal Capacity (from Prerecorded Well Data)
M
720
N
290
strokes
O
105
psi
P
10
psi
Q
455
psi
R. Strokes from Kickoff Point to Start of Hold (from Prerecorded Well Data)
R
374
strokes
S. Hydrostatic Pressure Increase Due to KWM at Start of Hold
S
210
psi
T. Friction Pressure Increase Due to KWM at Start of Hold
T
22
psi
pcf
psi
psi
bbl
ft (TVD)
ft (MD)
MUD WEIGHT TO BALANCE KICK
G. Increase in Mud Weight required to Balance Kick
H. New Mud Weight
H=B+G=
I. Total Volume to Weight up
I = Active Pit Vol + System Vol =
J. Barite Required
INITIAL CIRCULATING PRESSURE
K. Slow Pump Rate Pressure + SIDP
K =A+C=
N. Surface to Kickoff Point Strokes (from Prerecorded Data)
strokes
O. Hydrostatic Pressure Increase Due to KWM at Kickoff Pt.
P. Friction Pressure Increase Due to KWM at Kickoff Pt.
Q. Circulating Pressure at Kickoff Point
Q=K-O+P
CIRCULATING PRESSURE AT START OF HOLD
Version 2.0 (4/15/00)
H-24
ENGINEER'S METHOD WORKSHEET
(page 2)
U. Circulating Pressure at Start of Hold
U=K-S +T=
V. Strokes from Hold Point to TD (from Prerecorded Well Data)
U
362
psi
V
56
strokes
DRILL PIPE PRESSURE PROFILE
W. Pressure Drop Per Stroke to Kickoff Point
W
0.3290
psi per stroke
X. Pressure Drop Per Stroke from Kickoff to Start of Hold
X
0.2479 psi per stroke
Y. Pressure Drop Per Stroke from Hold Point to TD
(note: for a horizontal well this will be negative, meaning the pressure will increase each stroke increment)
Y
Kickoff Pt. (N)
Start of Hold (R+N)
Total Int. Cap. (M)
Strokes
0
40
80
120
160
200
240
280
0
0
290
390
490
590
0
0
0
0
0
664
670
680
690
700
710
0
0
0
0
720
Pressure (psi)
550
537
524
511
497
484
471
458
0
0
455
430
405
380
0
0
0
0
0
362
363
365
367
369
371
0
0
0
0
374
H-25
-0.2113 psi per stroke
= Initial Circ. Press. (K)
= Kickoff Pt. Circ. Press. (Q)
=Circ Press. @ Start of Hold(U)
=Final Circ. Press. (L)
ENGINEER'S METHOD WORKSHEET
(page 3)
RESERVOIR PRESSURE (Pr)
Z
3318
psi
AA
105
bbl
BB
0.0505
CC
0.95
DD
0.553
EE
36
psi
FF
720
psi
GG
756
psi
NO
X
HH
62
bbl
II
47
bbl
JJ
28
bbl
75
bbl
MAXIMUM CASING PRESSURE (Pcmax) WHEN GAS GETS TO SURFACE
AA. Drill String Capacity from Prerecorded Data
BB. Annulus Capacity Factor DP x Casing Right Below Wellhead
bbl/ft
CC. Temperature and Compression Effects. (TZ from Figure 11P.5 or Formula below)
GG. Maximum Casing Pressure,
PCmax=(Part1) + (Part2) = EE + FF =
psi/ft
Does Pcmax Exceed the Wellhead or Casing Pressure Limitation?
YES
VOLUME GAIN WHILE CIRCULATING OUT GAS BUBBLE
HH. Volume of Gas at Surface (From Fig 11P.4 or From Formula Below)
II. Volume Gain While Circulating Out Gas Kick
II = HH - E
JJ. Volume Gain due to Barite Addition
Total Volume Gain While Circulating Out Gas
= II + JJ
STROKES TO MAXIMUM CASING PRESSURE AND VOLUME
Maximum Casing Pressure and Excess Volume Occur When the Pumped Volume Equals
Total Annulus Capacity - Volume of Gas at Surface
= Annulus Capacity (from Prerecorded) - HH
H-26
bbl
355
strokes
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SECTION I – VOLUMETRIC CONTROL
Table of Contents
Introduction.........................................................................................................I-2
1.0
Basic Volumetric Control Principles ................................................I-2
1.1
1.2
1.3
2.0
3.0
4.0
5.0
First Basic Principle - Boyle's Law..................................................I-2
Second Basic Principle - Hydrostatic Pressure ..............................I-3
Third Basic Principle - Volume and Height......................................I-4
Description of the Method...................................................................I-4
2.1
Volumetric Control ..........................................................................I-5
Step 1 Calculations .......................................................................I-5
Safety Factor......................................................................I-5
Pressure Increment............................................................I-6
Mud Increment ...................................................................I-6
Step 2 Establish Safety Factor ......................................................I-7
Step 3 Bleed Off the Mud Increment..............................................I-7
Step 4 Wait for Gas Bubble to Migrate ..........................................I-8
Step 5 Bleed Mud from the Annulus..............................................I-8
Step 6 Wait for Gas Bubble to Migrate ..........................................I-8
Step 7 Alternate Bleeding and Migrating.......................................I-8
Step 8 Lubricate Mud into the Well ...............................................I-9
Lubricant and Bleed .............................................................................I-9
Step 1 Calculate ........................................................................... I-9
Step 2 Lubricate ........................................................................... I-9
Step 3 Wait....................................................................................I-9
Step 4 Bleed................................................................................ I-10
Step 5 Repeat Previous Steps.................................................... I-10
Volumetric Control Example ............................................................ I-10
Other Things to Consider.................................................................. I-13
5.1
Annulus Capacity Factor............................................................... I-13
5.2
Directional Wells........................................................................... I-14
5.3
Similarity to Driller’s Method......................................................... I-14
5.4
Casing Pressure Continues to Rise with Gas at the Surface ........ I-14
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SECTION I – VOLUMETRIC CONTROL
Introduction
In controlling a threatened blowout, special problems may arise that complicate the application of
routine methods of well control. One of these problems is not being able to circulate an influx
out of the wellbore. This may be due to several things, such as inoperative pumps, plugged bit
or drill pipe, drill pipe being well above the influx, as in a kick taken while tripping, or pipe
being out of the hole completely. When one of these problems occurs, the well cannot be
circulated with kill mud until corrective measures have been taken and the ability to circulate out
the influx is regained which could require quite some time. In the case of a plugged bit, it would be
necessary to perforate the drill pipe, or, if the drill pipe was off bottom, it would be necessary to
strip back to bottom.
Monitoring the casing pressure while initiating corrective procedures will dictate the method of
controlling the well. If the casing pressure does not increase above the original shut-in pressure, a
saltwater kick is indicated. Since there is less density differential between salt water and mud than
between gas and mud, the salt water will migrate much slower than gas. Thus, the shut-in casing
pressure will remain relatively constant and the only consideration is to leave the well shut in until it
can be killed. However, if the casing pressure increases above the original shut-in pressure, a gas
kick is indicated. The expansion characteristics of gas coupled with the density differential between
gas and mud which cause the gas to migrate up the hole, dictate the use of the volumetric control
method.
Successful use of the volumetric control method requires a thorough understanding of three basic
principles. The first principle is Boyle's Law, which states that the pressure of a gas is directly
related to its volume. The second principle is hydrostatic pressure and how it is calculated. The
third principle involves fluid volume and height as determined by annular capacities.
1.0
Basic Volumetric Control Principles
1.1
First Basic Principle - Boyle's Law
Boyle's Law states that the pressure of a gas is directly related to its volume. If a
volume of gas is compressed, the pressure in the gas will increase. Conversely, if a
gas is allowed to expand, the pressure in the gas will decrease. Stated
mathematically, Boyle's Law is written as:
Equation I.1 - Boyle's Law
where:
Current Revision:
Previous Revision:
P1V1
=
P2V2
P1
V1
P2
V2
=
=
=
=
Pressure in gas at condition 1
Volume of gas at condition 1
Pressure in gas at condition 2
Volume of gas at condition 2
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SECTION I – VOLUMETRIC CONTROL
This equation is a simplification of the gas law equation, PV = ZnRT, which neglects
the effect of the temperature and gas compressibility factors.
Relating this phenomenon to well control, if a gas kick migrates up the annulus
without expansion, the pressure of the gas bubble will remain constant. If the gas
bubble is allowed to expand as it migrates up the annulus, then the pressure in the
gas bubble will decrease.
Allowing the gas bubble to migrate to the surface without expansion will usually
result in disastrous consequences. This is because the pressure in the bubble as it
enters at the bottom of the wellbore is equal to the formation pressure. Owing to the
nature of all gas bubbles, they tend to rise in fluids which have greater density than
their own. If a gas bubble rises without expansion, it will have the same pressure on
the surface as it had on bottom, in effect bringing bottomhole formation pressure to
the surface! The consequences of this action can be disastrous, often resulting in
ruptured casing or an underground blowout.
On the other hand, if we allow the volume of the gas to increase as it rises in the
annulus, then according to Boyle's Law, the pressure in the gas bubble will
decrease. This is precisely the action we take when using volumetric control. We
allow the gas bubble to expand by bleeding off mud at the surface through the
choke.
1.2
Second Basic Principle - Hydrostatic Pressure
The rising gas bubble can be treated as a surface pressure with respect to the mud
below it. Anytime the gas bubble rises by one foot in the annulus, there will be one
additional foot of mud below the gas bubble. The additional foot of mud below the
gas bubble increases the hydrostatic pressure of the mud below the gas bubble,
which increases the bottomhole pressure by a like amount according to the following
formula:
Bottomhole Pressure = Hydrostatic Pressure + Surface Pressure
If we bleed mud from the annulus in order to lower the pressure in the gas bubble,
then we naturally reduce the volume of mud in the annulus, and therefore, the
hydrostatic pressure as well. When we bleed the mud from the annulus, it is very
important that we do it in a way that holds the casing pressure (surface pressure)
constant. From the above equation, it is clear that if we bleed mud from the annulus
(lower the hydrostatic pressure) while holding the same casing pressure (surface
pressure constant), then the bottomhole pressure will also decrease.
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Therefore, in volumetric control, we have two ways to influence the bottomhole
pressure:
•
•
Do nothing, let the gas bubble rise, and bottomhole pressure goes up.
Bleed mud from the annulus, lower the hydrostatic pressure, and
bottomhole pressure goes down.
We must be very careful when bleeding mud from the annulus because if we lower
the hydrostatic pressure too much, we may go underbalanced and take another
influx of gas into the well. We want to bleed-off just enough mud at the surface so
that the bottomhole pressure never drops below the reservoir pressure. In order to
accomplish this, we need to equate the loss in hydrostatic pressure with the volume
of mud bled-off at the surface. The BHP is maintained at a value slightly above
formation pressure by bleeding off a volume of mud which causes a reduction
in the hydrostatic pressure which is equal to the rise in casing pressure
caused by the migrating gas. It is for this reason that we must measure the
amount of mud bled-off from the annulus and equate that volume to a reduction in
hydrostatic pressure.
1.3
Third Basic Principle - Volume and Height
Everyone should be comfortable with annular volume and height relationships.
These are used in cement jobs, prerecorded data sheets, and numerous other
everyday calculations on the rig. Annulus capacity factors are tabulated in Tables
P.1, P.2 and P.3, or can be calculated with the formula on the following page:
Annulus Capacity Factor
where:
ACF
OD2 – ID 2
= -------------1029
ACF
OD
ID
=
=
=
Annulus Capacity Factor (bbl/ft)
Outside Diameter of Annular Space (in)
Inside Diameter of Annular Space (in)
We need these factors in order to calculate the reduction in hydrostatic pressure
which occurs each time we bleed mud from the annulus. We must know the drop in
hydrostatic pressure which will occur as a result of each mud bleeding.
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SECTION I – VOLUMETRIC CONTROL
2.0
Description of the Method
The volumetric control method is not a kill method, but rather, it is a method of
controlling the bottomhole pressure until provisions can be made to circulate or bullhead
kill mud into the well.
The essence of volumetric control is to allow controlled expansion of the gas bubble as it
migrates up the hole. We allow the gas bubble to expand by bleeding-off mud at the
surface while holding casing pressure constant. Casing pressure is held constant only
while the mud is being bled-off; at other times it is allowed to increase naturally. Each
barrel of mud that we bleed-off at the surface changes the wellbore environment in
four ways.
1.
2.
3.
4.
2.1
The gas bubble to expand by one barrel
The hydrostatic pressure of the mud in the annulus to decrease
The bottomhole pressure to decrease
The surface casing pressure to stay the same
Volumetric Control
Volumetric control is accomplished in a series of steps that causes the bottomhole
pressure to rise and fall in succession. We let the gas bubble rise and the
bottomhole pressure goes up. Then we bleed mud from the annulus and the
bottomhole pressure goes down. Then we let the gas bubble rise, and then bleed
mud, and so on. In this way, bottomhole pressure is held within a range of values
that is high enough to prevent another influx and low enough to prevent an
underground blowout.
Step One - Calculations
There are three calculations which need to be performed before a volumetric
control procedure can be executed.
•
•
•
Safety Factor
Pressure Increment
Mud Increment
Safety Factor
The safety factor is an increase in the bottomhole pressure which we
allow to occur naturally as gas migrates up the annulus. By allowing
the gas bubble to rise in the annulus, we are allowing the bottomhole
pressure to increase. It is important that we allow the bottomhole
pressure to increase to a value which is well above the formation
pressure to insure that we don't go underbalanced when we bleed mud
from the annulus in later steps. An appropriate value for the safety
factor is in the range of 200 psi in most cases. Depending on the
depth, angle and fluid in the well, it may take several hours for the gas
bubble to rise sufficiently to increase the casing pressure by 200 psi.
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SECTION I – VOLUMETRIC CONTROL
Sometimes, depending on how close the shoe is to exceeding its
fracture pressure under initial shut-in conditions, it will be advisable to
select a safety factor smaller than 200 psi. Any increase in the
bottomhole pressure will be reflected as an equal increase in the shoe
pressure as well. If the shoe is close to its fracture pressure, then the
safety factor will have to be appropriately reduced. If you calculate that
a 200 psi safety factor will break the shoe down, then a 100 psi safety
factor would be more suitable.
Pressure Increment
The pressure increment is the reduction in hydrostatic pressure which
occurs each time we bleed a given volume of mud from the annulus.
The Drilling Foreman should select a pressure increment which
produces a reduction in hydrostatic pressure equal to one-third of the
value of the initial safety factor (rounded to the nearest 10 psi). For
example, if a 150 psi safety factor was chosen, then the pressure
increment should produce a reduction in hydrostatic pressure of
50 psi (i.e., one-third of 150 psi).
Pressure Increment
Safety Factor
Pressure Increment
=
_________________
3
Mud Increment
The mud increment is the volume of mud which must be bled from the
annulus in order to reduce the annular hydrostatic pressure by the
amount of the pressure increment determined above. The mud
increment can be calculated with the equation given to the right. It is
very important that some means be available to measure the small
volumes of mud which are bled off from the annulus.
Mud Increment
PI x ACF
Mud Increment
=
___________
MW x 0.007
where:
Current Revision:
Previous Revision:
October 2002
October 1998
PI =
ACF =
MW =
Pressure Increment (psi)
Annulus Capacity Factor (bbl/ft)
Mud Weight (pcf)
I-6
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SECTION I – VOLUMETRIC CONTROL
For example, if a hydrostatic reduction (pressure increment) of 50 psi
is desired and the annulus capacity factor is 0.0714 bbl/ft with a mud
weight of 85 pcf, then the proper mud increment is 6 bbls.
Step Two - Allow Casing Pressure to Increase Establish Safety Factor
After the calculations are completed, the next step in Volumetric Control is to
wait for the gas bubble to migrate up the hole and cause an increase in the
shut-in casing pressure. (In reality, this would be occurring as you were
performing your calculations). You should allow the gas bubble to rise until
the casing pressure has increased by an amount equal to the safety factor.
No mud has been bled off from the annulus, so the hydrostatic pressure of
the mud has not changed since the well was first shut in.
While Gas Bubble Migrates
Bottomhole
Pressure
(Goes Up)
=
Hydrostatic Pressure + Surface Pressure
(Stays the Same)
(Goes Up)
At this point, the bottomhole pressure has also increased by the amount of
the safety factor and the well should be safely overbalanced.
Step Three - Hold Casing Pressure Constant by Bleeding Off the Mud
Increment
After the safety factor overbalance is applied to the well, the first mud
increment can be bled from the well. The manner in which the mud is bledoff from the annulus is very important - it must be bled in such a way that
the casing pressure remains constant throughout the entire bleeding.
This is done to insure that the bottomhole pressure is reduced only by a loss
in the mud hydrostatic pressure, and not by an additional loss in surface
pressure. During the bleeding process, the hydrostatic pressure is reduced
by the pressure increment while the surface pressure is held the same, so
the bottomhole pressure is also reduced by the pressure increment.
While Bleeding Mud from the Annulus
Bottomhole
Pressure
(Goes Down)
Current Revision:
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=
Hydrostatic Pressure + Surface Pressure
(Goes Down)
(Stays the Same)
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SECTION I – VOLUMETRIC CONTROL
Each time we bleed mud from the annulus, the gas bubble expands to fill the
volume vacated by the mud. As the gas bubble expands, the pressure in the
bubble decreases according to Boyle's Law.
Step Four - Wait for Casing Pressure to Rise as the Gas Bubble
Migrates
Each bleeding of mud from the annulus reduces the bottomhole pressure by
the amount of the pressure increment. This decreases our safety factor
overbalance. In order to get the full value of overbalance back on the well,
we simply wait for the gas bubble to migrate up the annulus. As the gas
bubble migrates, both surface pressure and bottomhole pressure increase
just as when the safety factor was applied. We wait for the gas bubble to rise
until the surface casing pressure has increased by an amount equal to the
pressure increment. At this point, we have also increased bottomhole
pressure by the amount of the pressure increment, and the well is back at full
overbalance.
Step Five - Hold Casing Pressure Constant by Bleeding Mud from the
Annulus
Once we have our full overbalance back on the well, we can safely bleed
another mud increment from the annulus. As with the first bleeding, this step
is accomplished while holding casing pressure constant. This reduces the
bottomhole pressure by the amount of the pressure increment because a like
amount of mud hydrostatic pressure has been bled from the well. This has
also caused the gas bubble to expand by the volume of the mud increment.
Step Six - Wait for Casing Pressure to Increase as the Gas Bubble
Migrates
After the bleed step we again wait for the gas bubble to migrate with the well
shut in. The bottomhole pressure will rise back to its full overbalanced
condition. We know when this has occurred because the casing pressure will
have risen by the amount of the pressure increment.
Step Seven - Alternate Holding Casing Pressure Constant and Letting It
Rise
The remainder of the volumetric control procedure is simply a succession of
bleeding and migrating, bleeding and migrating, bleeding and migrating, until
the gas has finally migrated all the way to the surface. Each time we bleed
we lower the bottomhole pressure, and each time we migrate we raise the
bottomhole pressure. During each bleed step we allow the gas bubble to
expand which lowers the pressure in the bubble. By the time the gas reaches
the surface, it has expanded to many times its original volume so its pressure
is greatly reduced.
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SECTION I – VOLUMETRIC CONTROL
Step Eight - Lubricate Mud into the Well
The casing pressure should stop increasing after the gas has reached the
surface. The well is stable at this point, but in most cases, you will want to
bleed the gas from the well and replace it with mud before attempting further
well work. This step involves bleeding gas from the well to reduce the casing
pressure by a predetermined increment. Then, a measured volume of mud
should be pumped into the well to increase the hydrostatic pressure in the
annulus by the amount of surface pressure which was lost when the gas was
first bled off. These steps should be repeated until gas can no longer be bled
from the well.
3.0
Lubricate and Bleed
Sometimes during major well control situations, there comes a time when gas is at surface
and it is not possible to circulate (as could easily be the case during a Volumetric Control
procedure). This is the point in time that the surface pressure is the highest due to
decreased hydrostatic in the well. When this occurs, the best way to remove the gas is by
circulating. However, when circulation is not possible the well has to be lubricated and
bled. The theory involved in lubricating and bleeding is the same as that for Volumetric
Control but in reverse. Surface pressure is replaced with hydrostatic pressure by pumping
mud into the well on top of the gas. The gas and mud are allowed to change places in the
hole and some of the surface pressure is bled off. The lubricate and bleed procedure is
listed in the following steps.
Step One - Calculate
Calculate the hydrostatic pressure that will be exerted by 1 barrel of mud.
Step Two - Lubricate
Slowly pump a given volume of mud into the well. The amount chosen will
depend on many different well conditions and may change throughout the
procedure. The rise in surface pressure can be calculated by applying
Boyle’s law of P1V1 = P2V2 and realizing that for every barrel of mud pumped
into the well the bubble size decrease by 1 barrel.
Step Three - Wait
Allow the gas to migrate back to the surface. This step could take quite some
time and is dependent on a number of factors such as mud weight and
viscosity.
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Step Four - Bleed
Bleed gas from the well until the surface pressure is reduced by an amount
equal to the hydrostatic pressure of the mud pumped in. it is every important
to bleed only gas. If at any time during procedure mud reaches the surface
and starts bleeding. The well should be shut in and the gas allowed to
migrate.
Step Five - Repeat Previous Steps
Repeat Steps 2 through 4 until all of the gas has been bled off or a desired
surface pressure has been reached.
4.0
Volumetric Control Example
Ali Al-Saffar, the Saudi Aramco Drilling Foreman, was glad he had been to well control
school last week on his days off; he knew he would need it now. Kicks were common
while drilling through "The Trend", but this one had just turned ugly. Just moments after
he started pumping using the Engineer's Method, something had plugged him off at the
bit. He noticed one of the roustabouts searching for a glove out by the pipe racks. He
knew he would have to use Volumetric Control. Ali gathered up the following information
and jotted it down in his tally book:
Hole Size:
Drill Pipe:
Ann. Capacity
TD:
Shoe Test:
8-1/2"
5" X-Hole
0.0459 bbl/ft
14,400' MD/TVD
126 pcf EMW
Kick Size:
Mud Weight;
SICP:
SIDP:
Casing Shoe:
24 bbl
114 pcf
640 psi
520 psi
12,220' MD/TVD
Ali knew the first thing to do was to determine the safety factor, pressure increment and
mud increment. He knew he had to check the shoe pressures first. Under shut-in
conditions he calculated his shoe pressure as:
Shoe Pressure =
(TVDshoe x Mud Weight x 0.007) + SICP
=
(12,220' x 114 pcf x 0.007) + 640 psi
=
10,391 psi
He knew his shoe would break down at a pressure of,
Shoe Fracture
Pressure
=
Current Revision:
Previous Revision:
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October 1998
(TVDshoe x Shoe Test x 0.007)
=
(12,220 x 126 pcf x 0.007)
=
10,778 psi
I - 10
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Ali saw that the casing pressure could rise another 387 psi (10,778 psi - 10,391 psi = 387
psi) before breaking the shoe down, so he decided on a safety factor of 200 psi.
His pressure increment was quickly calculated by dividing the safety factor by 3, as such,
Pressure
Increment
200 psi
=
=
_______
3
67 psi (or 70 psi)
Ali then had to calculate his mud increment (or the volume of mud to generate 70 psi of
hydrostatic pressure in his annulus).
PI x ACF
Mud Increment =
____________
MW x 0.007
70 x 0.0459
=
____________
114 x 0.007
=
4.0 bbls
Ali then knew that for every 4.0 bbls of mud he bled from the annulus, the hydrostatic
pressure would be reduced by 70 psi. With these calculations completed, he was ready to
proceed.
Ali had a roughneck bring a chair up to the rig floor because he knew that the operation
was going to take a long time. He then told the rig welder to weld a bead in a small tank at
the 4.0 barrel mark up from the bottom (Ali had determined that he would use the small
tank to measure the mud volume which he bled from the well). Ali sat and waited for the
casing pressure to rise.
In less than an hour, the casing pressure rose 200 psi, from the initial shut-in value of 640
psi to 840 psi. Ali knew that his well was now safely overbalanced, so he was ready for the
first bleed step.
The choke manifold was lined up to bleed directly into the small tank through the blooey
line out near the reserve pit. He had a roughneck with a walkie-talkie out there to measure
the volume. Ali cracked the choke and bled-off the first little bit of mud from the annulus;
the drop on the casing pressure gauge was imperceptible. He bled a little more mud and
the casing pressure gauge dropped five psi. Ali closed the choke and in a little while, the
pressure had risen back to 840 psi. He continued to bleed mud in small increments trying
to keep the casing pressure as close to 840 psi as possible. Over an hour later, the
roughneck finally had 4.0 bbls in the small tank.
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SECTION I – VOLUMETRIC CONTROL
Ali knew that he had lowered the bottomhole pressure by 70 psi as he had bled the 4.0
bbls from the annulus, so he waited while the gas bubble migrated up the hole and
watched as the casing pressure gauge rose an additional 70 psi to 910 psi (840 psi + 70
psi = 910 psi). By this time in the operation, nearly three hours had elapsed.
Now that he had his full 200 psi of bottomhole overbalance back on the well, it was time to
bleed another 4.0 barrels of mud from the annulus. This time he held the casing pressure
as best he could at 910 psi. The roughneck told him when the tank was full.
Figure I.1
Volumetric Control Example Pressures
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SECTION I – VOLUMETRIC CONTROL
For the next seven hours, Ali bled mud and then waited, bled more mud and waited some
more, and then bled and waited again for a total of fourteen bleed steps. On the fifteenth
bleed, with the casing pressure at 1820 psi, Ali started getting gas through the choke. He
stopped bleeding and checked to make sure the pipe rams weren't leaking. Everything was
in order and he felt fine. Just then the perforating truck pulled up to location to shoot some
holes in his drillcollars. He'd be circulating within the hour.
A plot of Ali's volumetric control procedure is shown in Figure I.1 You can see that on each
bleed step the bottomhole pressure decreased, and on each migrate step the bottomhole
pressure increased. Casing pressure rose during each migrate step and was held constant
during each bleed step. The gas bubble volume increased by 4.0 bbls during each bleed
step and rose from its initial volume of 24 bbls to 84 bbls when it finally reached the surface
(24 bbl kick + 60 bbls bled = 84 bbls).
5.0
Other Things to Consider
5.1
Annulus Capacity Factor
The annulus capacity factor which is used to determine the mud increment should be
taken at the top of the gas bubble. Note that the annulus capacity factor may change
as the gas bubble migrates up the hole if a tapered drillstring is in use or drilling liner
is installed in the well. If the bubble migrates into a smaller annular space, then less
mud needs to be bled from the annulus to produce the same hydrostatic pressure
reduction. In these instances, the rate of rise of the gas bubble should be calculated
to help in predicting when the new annulus capacity factor should be used. This rate
of rise of the gas bubble can be estimated with Equation I.2.
Equation I.2
Rate of Gas Bubble Rise
∆SICP
ROR
=
__________________
MW x 0.007 x ∆T
where:
ROR
∆SICP
MW
∆T
=
=
=
=
Rate of Rise (ft/min)
Change in Shut-in Casing Pressure
Mud Weight (pcf)
Time from end of last bleed to start of next bleed (min)
If an accurate time log is kept of the volumetric control procedure, then the rate of
rise can be calculated over the interval of each migration step. Remember however,
that the gas bubble will continue to rise even while mud is being bled from the well.
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SECTION I – VOLUMETRIC CONTROL
5.2
Directional Wells
Due to the hypothetical nature of this well control method, it may be used with limited
success in deviated holes.
5.3
Similarity to Driller's Method
In essence, the volumetric control procedure is identical to the first circulation of the
Driller's Method, except that no pumps are used and the final casing pressure is
somewhat higher. With volumetric control, the influx is allowed to migrate out of the
hole rather than being circulated out of the hole. Once the influx is removed and mud
is lubricated into the annulus, the well should be in the same state that it would have
been if the first circulation of Driller's Method had been completed. However, except
that the casing pressure may be higher due to the additional safety factor applied to
the well.
5.4
Casing Pressure Continues to Rise with Gas at the Surface
This may occur if the gas bubble is severely strung-out over the length of the hole.
Since gas contributes very little to the hydrostatic pressure of the fluids in the well, it
can usually be bled from the well without causing much of a pressure reduction at
the bottom of the hole. Therefore, if gas reaches the surface and the casing pressure
continues to rise, the Drilling Foreman should bleed small amounts of gas from the
well while keeping casing pressure constant until the casing pressure no longer
continues to rise.
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SECTION J - EQUIPMENT REQUIREMENTS
Table of Contents
1.0
Drilling BOP Stacks .................................................................. J - 4
1.1
2.0
3.0
Class ‘A’ 10,000 psi BOP Stack ........................................................ J - 4
1.1.1 Class ‘A’ 10,000 psi BOP Stack Arrangement (Normal)......... J - 4
1.1.2 Class ‘A’ 10,000 psi BOP Stack Arrangement (Tapered)....... J - 7
1.2
Class ‘A’ 5,000 psi BOP Stack .......................................................... J - 8
1.2.1 Class ‘A’ 5,000 psi BOP Stack Arrangement (Normal)........... J - 8
1.2.2 Class ‘A’ 5,000 psi BOP Stack Arrangement (Tapered)....... J - 12
1.3
Class ‘A’ 3,000 psi BOP Stack ........................................................ J - 13
1.3.1 Class ‘A’ 3,000 psi BOP Stack Arrangement (Large Hole)... J - 13
1.3.2 Class ‘A’ 3,000 psi BOP Stack Arrangement (Smaller Hole) J - 15
1.4
Class ‘B’ 3,000 PSI BOP Stack ....................................................... J - 17
1.5
Class ‘C’ 3,000 psi BOP Stack ........................................................ J - 18
1.6
Class ‘D’ Diverter BOP Stack.......................................................... J - 19
1.7
General Requirements for Drilling BOP Equipment..................... J - 20
1.7.1 Annular Units ........................................................................ J - 21
1.7.2 Fixed Rams Preventers ........................................................ J - 21
1.7.3 Variable Bore Rams.............................................................. J - 22
1.7.4 Shear Blind Rams................................................................. J - 22
1.7.5 Blind Flanges on Side Outlets .............................................. J - 24
1.7.6 Minimum Bore Requirements for Kill and Choke Lines………J - 24
Workover BOP Stacks ............................................................. J - 24
2.1
Class ‘I’ 2,000 PSI BOP Stack ........................................................ J - 24
2.2
Class ‘II’ 3,000 psi BOP Stack......................................................... J - 25
2.3
Class ‘III’ 5,000 psi BOP Stack........................................................ J - 26
2.4
Class ‘IV’ 10,000 psi BOP Stack ..................................................... J - 26
2.5
General Requirements for Workover BOP Equipment ................ J - 27
2.5.1 Annular Units ........................................................................ J - 29
2.5.2 Fixed Rams Preventers ........................................................ J - 29
2.5.3 Variable Bore Rams.............................................................. J - 29
2.5.4 Shear Blind Rams................................................................. J - 29
2.5.5 Blind Flanges on BOP Side Outlets………………………………J - 30
2.5.6 Minimum Bore Requirements for Kill and Choke Lines……..J - 30
Special Operations BOP Stacks ............................................. J - 30
3.1
Coil Tubing Operations................................................................... J - 30
3.1.1 Low Pressure BOP Equipment Requirements ..................... J - 31
3.1.2 High Pressure BOP Equipment Requirements..................…J - 32
3.2
Snubbing Operations ...................................................................... J - 33
3.2.1 Low Pressure BOP Equipment Requirements ..................... J - 33
3.2.2 High Pressure BOP Equipment Requirements..................... J - 34
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3.3
4.0.
5.0
6.0
7.0
Electric Line Operations ................................................................. J - 35
3.3.1 Open Hole BOP Equipment Requirements .......................... J - 35
3.3.2 Cased Hole BOP Equipment Requirements......................... J - 35
Choke Manifolds ....................................................................... J - 37
4.0.1 10,000 psi Working Pressure ............................................... J - 37
4.0.2 5,000 psi Working Pressure (Onshore) ................................ J - 38
5,000 psi Working Pressure (Offshore) ................................ J - 39
4.0.3 3,000 psi Working Pressure ............................................... .J - 41
4.1
Location............................................................................................ J - 42
4.2
Choke Manifold Pressure Ratings ................................................ J - 42
4.3
Piping Specifications ...................................................................... J - 42
4.4
Choke Manifold Discharge ............................................................. J - 42
4.4.1 Flare Lines ............................................................................ J - 42
4.4.2 Gas Buster Lines .................................................................. J - 43
4.5
Choke Requirements....................................................................... J - 44
4.6
Valve Requirements ........................................................................ J - 44
4.7
Gauges.............................................................................................. J - 44
4.8
Line Maintenance............................................................................. J - 44
4.9
Normal Valve Position..................................................................... J - 44
Accumulator Closing Units ..................................................... J - 44
5.1
Fluid Requirements ......................................................................... J - 44
5.2
Design Requirements...................................................................... J - 45
5.3
Bottle Pre-Charge Requirements ................................................... J - 45
5.4
Operator Control Requirements..................................................... J - 45
5.5
Accumulator Location..................................................................... J - 45
5.6
Pump System ................................................................................... J - 45
5.7
Pressure Regulator Settings .......................................................... J - 46
Sizing BOP Closing Equipment .............................................. J - 46
6.1
General Requirements .................................................................... J - 46
6.2
Size Calculations ............................................................................. J - 47
6.3
Alternate Size Calculations............................................................. J - 50
Preventer Units......................................................................... J - 53
7.1
Annular Preventers.......................................................................... J - 53
7.1.1 Hydril ‘MSP’ .......................................................................... J - 54
7.1.2 Hydril ‘GK’ ............................................................................. J - 55
7.1.3 Hydril ‘GL’ ............................................................................. J - 56
7.1.4 Shaffer ‘Spherical’................................................................. J - 57
7.1.5 Cameron Model ‘D’ ............................................................... J - 58
7.2
Sealing Elements ............................................................................. J - 59
7.3
Stripping with Annular .................................................................... J - 60
7.4
Ram Preventers ............................................................................... J - 60
7.4.1 Hydril Type ‘V’....................................................................... J - 60
7.4.2 Shaffer Type ‘LWS’............................................................... J - 61
7.4.3 Shaffer Type ‘SL’ .................................................................. J - 62
7.4.4 Cameron Type ‘U’................................................................. J - 62
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7.5
8.0
Ram Construction............................................................................ J - 63
7.5.1 Hydril Rams .......................................................................... J - 63
7.5.2 Cameron Rams .................................................................... J - 64
7.5.3 Shaffer Rams........................................................................ J - 65
7.6
Variable Bore Rams......................................................................... J - 65
7.7
Shear Blind Rams ............................................................................ J - 66
7.8
Secondary Seals .............................................................................. J - 68
Accessory Blowout Prevention Equipment ........................... J - 68
8.1
Pit Volume Totalizer ........................................................................ J - 68
8.2
Mud Flow Indicators........................................................................ J - 69
8.3
Mud/Gas Separators........................................................................ J - 69
8.3.1 Degassers............................................................................. J - 69
8.3.2 Gas Busters .......................................................................... J - 69
8.4
Full-Opening Safety Valve .............................................................. J - 72
8.5
Inside BOP........................................................................................ J - 73
8.6
Drilling Chokes ................................................................................ J - 74
8.7
Trip Tank........................................................................................... J - 74
8.8
Strokes Counters............................................................................. J - 76
8.9
Gas Detectors .................................................................................. J - 76
8.10
Mud Logging Unit ............................................................................ J - 76
8.11
Mud Weight Recorders ................................................................... J - 76
8.12
Drilling Rate Recorders................................................................... J - 77
8.13
Bowl Protectors ............................................................................... J - 77
8.14
Drillpipe Float Valves ...................................................................... J - 77
8.15
Valve Removal Plugs....................................................................... J - 77
8.16
Back Pressure Valves ..................................................................... J - 79
8.16.1 One-Way Check Valve ......................................................... J - 79
8.16.2 Two-Way Check Valve ......................................................... J - 80
8.17
Coflex Hose ...................................................................................... J - 81
8.18
Weco Connections .......................................................................... J - 81
8.19
Chiksans .......................................................................................... J - 81
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SECTION J - EQUIPMENT REQUIREMENTS
Any BOP equipment arrangement or pressure rating variation from the standards set forth herein
must be approved by the General Manager, Drilling and Workover. The enforcement of these
equipment standards shall be the responsibility of the Drilling Superintendent. The Drilling Foreman
shall ensure that the proper equipment is available and correctly installed. All BOP equipment shall
comply with API Specifications, if not specified in these standards. The BOP equipment must be
arranged to allow:
Ø A means of closing the top of the open hole, as well as around drill pipe or collars, and
stripping the drill string to bottom.
Ø A means of pumping into a hole and circulating out a well kick.
Ø A controlled release of the influx.
Ø A redundancy in equipment in the event that any one function fails.
rd
Changes in this 3 Edition of the Saudi Aramco Well Control Manual are indicated by a bold vertical
line in the right margin, opposite the revision.
1.0
Drilling BOP Stacks
The drilling program shall specify the Class BOP stack (not individual components) to be
used.
1.1
Class ‘A’ 10,000 psi BOP Stack
A Class ‘A’ 10,000 psi BOP stack shall be installed on all offshore and onshore wells
where surface pressure may become more than 5,000 psi but not more than 10,000
psi. All equipment shall meet NACE Standard MR-01-75 (Latest Revision) for sour
service with 10,000 psi working pressure. All elements for Class ‘A’ 10,000 psi stacks
shall be 10,000 psi rated working pressure and all flanges in the stack shall be 135/8" or 11” 10M. One exception to this is that the annular preventer shall be 5,000 psi
working pressure. It is also unnecessary to have a 10,000 psi rotating head. Each
ram preventer shall have two 4-1/16" 10M flanged outlets. For a double ram preventer
there would be a total of four flanged outlets. All preventers shall be installed so that
rams can be changed without moving the stack.
1.1.1
Class ‘A’ 10,000 psi BOP Stack Arrangement (Normal)
When using a single size of drill pipe (one size of drill pipe from bottom to
top) the stack arrangement shall be as described below and as shown in
Figure J.1:
a) A wellhead spool (casing head) with a 13-5/8" or 11” 10M flange with two
(2) 3-1/16" 10M flanged side outlets for emergency kill operations shall
be installed. One outlet shall have two (2) 3-1/16" 10M flanged gate
valves with a 3-1/16” blind flange installed. The other outlet shall have a
manually operated flanged 3-1/16" gate valve next to the wellhead and a
hydraulic control flanged 3-1/16" 10M gate valve tied to the emergency
kill line. The emergency kill line shall be an individual line with flanged
steel piping (no chiksan swings or hammer unions) and a minimum 3"
10M rated working pressure. Coflex hose (coflon lined) may be used in
combination with steel line. The emergency kill line shall extend from the
wellbore to end of the catwalk (approximately 90 feet), with a 3" 1502
Weco welded union (threaded connections are not acceptable) for
connection to an emergency pump.
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Figure J.1
Class ‘A’ 10,000 psi BOP Stack
(using a single size drillpipe)
Shear Blind Rams
3-1/16” 10M Emergency Kill Line
Note:
b)
Current Revision:
Previous Revision:
All BOP equipment with working pressures of 3,000 psi and above
shall have flanged, welded, integral, or hubbed connections only.
If the wellhead top flange is below ground level, a 13-5/8" or 11” 10M
spacer spool spacer may be required. If the wellhead spool is not 135/8" or 11” 10M, a double studded adapter flange shall be required.
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c)
A 13-5/8" or 11” 10M flanged double gate ram preventer shall be
installed on the wellhead spool above ground level with master drill
pipe rams (bottom) and blind rams (top).
d)
A 13-5/8" or 11” 10M flanged drilling cross shall be installed on the
double ram preventer. The drilling cross shall have two (2) 4-1/16" 10M
flanged side outlets.
There shall be a double studded adapter flange 4-1/16" 10M to 2-1/16"
10M installed on the kill line side. From the drilling cross out, there
shall be:
•
•
•
•
a 2-1/16" 10M flanged manually operated gate valve
a 2-1/16" 10M flanged hydraulic control gate valve
a 2-1/16" 10M flanged spacer spool
a 2-1/16" 10M flanged tee
On each side of the tee there shall be a 2-1/16" 10M flanged gate valve
and a 2-1/16" 10M flanged check valve. On the remote side, the kill line
shall be 10M and run at least 90 feet from the wellbore to the end of
the walk, with a flange to Weco 2" welded union. On the primary side,
the kill line shall be 10M and connected directly to the mud pumps or to
the stand pipe manifold, with a 10M manual isolation valve between the
kill line and 5M stand pipe.
On the choke line, from the drilling cross out, there shall be:
•
•
•
a 4-1/16" 10M flanged manually operated gate valve
a 4-1/16" 10M flanged hydraulic control gate valve
a 4-1/16" 10M flanged line to a 4-1/16" 10M flanged
manually operated gate valve at the choke manifold
All steel piping shall be made with 10M flanges, targeted tees, blocktee elbows, and factory-made 10M working pressure line. All tees must
be targeted with renewable 10M blind flanges (welded tees are not
acceptable).
Chiksans and Weco connections (other than the remote connections at
end of the catwalk) are not acceptable for kill line, emergency kill line,
or choke line. Coflex hose (coflon lined) may be used in combination
with steel line for the kill or emergency kill line.
Current Revision:
Previous Revision:
e)
A 13-5/8" or 11” 10M flanged double gate ram preventer shall be
installed on the 10M drilling cross. There shall be shear blind rams
(bottom) and drill pipe rams (top) of the double ram preventer.
f)
A 13-5/8" or 11” 5/10M flanged bottom and studded top annular
preventer will be installed on the top double ram preventer. A screw-on
top annular is acceptable.
g)
A 13-5/8" or 11” 5/10M flanged rotating head, with a flanged bottom
connection to match the top connection of the annular preventer and a
9" 3M flanged side outlet, shall be installed on top of the annular
preventer. A spacer spool may be required if annular studded top is not
compatible with rotating head flange.
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SECTION J - EQUIPMENT REQUIREMENTS
1.1.2
Class ‘A’ 10,000 psi BOP Stack Arrangement (Tapered)
When using a tapered drill string (two sizes of drill pipe) from the bottom to
top shall be exactly the same as the arrangement for a single size drill pipe
string, except the blind rams in the lower double ram preventer shall be
replaced with rams to fit small drill pipe, as shown in Figure J.2.
Figure J.2
Class ‘A’ 10,000 psi BOP Stack
(using a tapered drill string)
Shear Blind Rams
3-1/16” 10M Emergency Kill Line
Note: All BOP equipment with working pressures of 3,000 psi and above shall have
flanged, welded, integral, or hubbed connections only.
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SECTION J - EQUIPMENT REQUIREMENTS
1.2
Class ‘A’ 5,000 psi Stack
A Class ‘A’ 5,000 psi stack shall be installed on all offshore and onshore wells where
surface pressure may become more than 1,000 psi, but not more 5,000 psi. All
equipment shall meet NACE Standard MR-01-75 (Latest Revision) for sour service
with a 5,000 psi working pressure. All elements of Class ‘A’ 5,000 psi stacks shall be
5,000 psi rated working pressure and all flanges on the stack shall be either 13-5/8"
or 11" 5M. Each ram preventer shall have two (2) 3-1/8" (or larger) 5M side outlets. A
double ram preventer will have four side outlets. All preventers shall be installed so
that rams can be changed without moving the stack.
All Class ‘A’ 5,000 psi stacks used offshore shall have shear blind rams installed in
the ram cavity immediately above the drilling cross. Shear blind rams on onshore
stacks are required only on wells with high H2S, in gas cap areas, and wells in
populated areas. Details regarding shear blind ram applications are provided in
Section 1.7.4.
1.2.1
Class ‘A’ 5,000 psi Stack Arrangement (Normal)
When using a single size drill pipe string (one size of drill pipe) from the
bottom to top, the stack arrangement shall be as described below and as
shown in Figure J.3:
a)
A wellhead spool (casing head) with a 13-5/8" or 11" 3M flange with
two (2) 2-1/16" 3M side outlets for emergency kill operations shall be
installed. One outlet shall have a 2-1/16" 3M gate valve with a 2-1/16"
3M blind flange. The other outlet shall have a manually operated 21/16" 3M flanged gate valve next to the wellhead and a hydraulic
control 2-1/16" 3M flanged gate valve tied into the emergency kill line.
The emergency kill line shall be an individual line with flanged steel
piping (no chiksan swings or hammer unions) and a minimum 2” 5M
rated working pressure. Coflex hose (coflon lined) may be used in
combination with steel line.
For onshore operations, the emergency kill line shall extend from the
wellbore to end of the catwalk (approximately 90 feet), with a 2" 1502
Weco welded union (threaded connections are not acceptable) for
connection to an emergency pump.
Note: If shear blind rams are utilized, then the emergency kill line shall be 3”
and 5 M rated working pressure. The manual gate valve shall remain
as 2” with double studded adapter to 3”.
Note: If the wellhead spool has a 5M top flange, then the side outlet valves
shall be 5M.
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Figure J.3
Class ‘A’ 5,000 psi BOP Stack – (using a single size drill pipe)
Note: Kill and Emergency Kill Lines configured for onshore
operations
Optional
or Shear Blind Rams
(see Sec. 1.7.4)
2-1/16” 5M Emergency Kill Line
(3-1/8” 5M if Shear Blind Rams are utilized)
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SECTION J - EQUIPMENT REQUIREMENTS
Note:
All BOP equipment with working pressures of 3,000 psi and
above shall have flanged, welded, integral, or hubbed
connections only.
b)
If the wellhead top flange is below ground level, a 13-5/8" or 11" 5M
spacer spool may be required.
c)
A 13-5/8" or 11" 5M flanged single ram preventer shall be installed on
the wellhead spool above ground level with master drill pipe rams.
Variable bore rams are optional (provided the minimum acceptable
ratings for H2S and temperature are met) for tapered drill string
applications on Class ‘A’ 5M stacks. However, the master pipe ram
must be a fixed ram.
Note:
Currently, Cameron’s Extended Range High Temperature
VBR-II Packer is the only variable bore ram is approved for 5M
applications. Additional information regarding the use of
variable bore rams is provided in Section 1.7.3.
d)
A 13-5/8" or 11" 5M flanged drilling cross shall be installed on the
single ram preventer. The drilling cross shall have two (2) 3-1/8" 5M
side outlets.
e)
There shall be a 3-1/8" 5M to 2-1/16" 5M double studded adapter
flange installed on the kill line side.
For Land Operation:
From the drilling cross out, there shall be:
•
•
•
•
a 2-1/16" 5M flanged manually operated gate valve
a 2-1/16" 5M flanged hydraulic control gate valve
a 2-1/16" 5M flanged spacer spool
a 2-1/16" 5M flanged tee
On each side of the tee there shall be a 2-1/16" 5M flanged gate valve
and a 2-1/16" 5M flanged check valve.
On the remote side, the kill line shall be 5M and run at least 90 feet
from the wellbore to the end of the catwalk, with a flange to Weco 2"
welded union.
On the primary side, the kill line shall be 5M and connected directly to
the mud pumps or to the stand pipe manifold.
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For Offshore Operation:
From the drilling cross out, there shall be:
•
•
•
•
a 2-1/16" 5M flanged manually operated gate valve
a 2-1/16" 5M flanged hydraulic control gate valve
a 2-1/16" 5M check valve
a 2-1/16" 5M flanged line or Coflex hose (coflon lined) to the
pump/choke manifold
The emergency kill line shall have the capability of being connected to
the cement manifold through the choke manifold as shown in Figure
18A or through a dedicated line from the rig floor cement manifold. A 3”
ID, 5M Coflex (coflon lined) hose shall be run between the fixed piping
and applicable casing spool.
Note:
Due to the length required in offshore operations, it is
recommended that a short connection (between the cement
manifold and whatever facility is used) be of a removable type
to reduce the chance of plugging the line with cement during
cementing operations. This connection shall be in place and
tested during drilling operations.
On the choke line, from the drilling cross out, there shall be:
•
•
•
a 3-1/8" 5M flanged manually operated gate valve
a 3-1/8" 5M flanged hydraulic control gate valve
a 3-1/8" 5M flanged line or Coflex hose (coflon lined) to a 3-1/8"
5M flanged manually operated gate valve at the choke manifold
All steel piping shall be made with 5M flanges, targeted tees, block-tee
elbows, and factory-made 5M working pressure line. All tees must be
targeted with renewable 5M blind flanges (welded tees are not
acceptable).
Chiksans and Weco connections (other than the remote connection at
the catwalk, land operation) are not acceptable. Coflex hose (coflon
lined) may be used in combination with steel line for kill, emergency kill
line, or choke line.
Current Revision:
Previous Revision:
f)
Either two (2) 13-5/8" or 11" 5M flanged single ram preventers or a
double ram preventer shall be installed, blind rams or shear blind
rams, see required applications in Section 1.7.4, (bottom) and drill
pipe rams (top).
g)
A 13-5/8" or 11" 5M flanged bottom and studded top annular preventer
will be installed on the top ram preventer. A screw-on top annular is
acceptable.
h)
A 13-5/8" 5M or 11" 5M rotating head is optional.
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SECTION J - EQUIPMENT REQUIREMENTS
1.2.2
Class ‘A’ 5,000 psi Stack Arrangement (Tapered)
When using a tapered drill string (two sizes of drill pipe) from the bottom to
top shall be exactly the same as the arrangement for the single size drill pipe
string. The only exception is the top drill pipe rams shall be replaced with
small drill pipe rams, as shown in Figure J.4.
Figure J.4
Class ‘A’ 5,000 psi BOP Stack – (using a tapered drill string)
Note: Kill and Emergency Kill Lines configured for onshore operations
Optional
or Shear Blind Rams
(see Sec. 1.7.4)
2-1/16” 5M Emergency Kill Line
(3-1/8” 5M if Shear Blind Rams are utilized)
Current Revision:
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SECTION J - EQUIPMENT REQUIREMENTS
Note:
1.3
All BOP equipment with working pressures of 3,000 psi and above shall have flanged,
welded, integral, or hubbed connections only.
Class ‘A’ 3,000 psi BOP stack
A Class ‘A’ 3,000 psi BOP stack shall be installed on all wells where large diameter
hole is being drilled, as through 18-5/8" casing, and where hydrocarbon reservoirs
with up to 3000 psi surface pressure may be drilled.
1.3.1
Large Diameter Hole (as with Deep Gas Wells)
All equipment shall meet NACE Standard MR-01-75 (Latest Revision) for
sour service with a 3,000 psi working pressure. All elements of Class ‘A’
3,000 psi stacks shall be 3,000 psi rated working pressure and all flanges on
the stack shall be either 26-3/4" or 20-3/4” 3M. Each ram preventer shall
have two (2) 4-1/16" 3M side outlets. A double ram preventer will have four
side outlets. All preventers shall be installed so that rams can be changed
without moving the stack.
The arrangement from the bottom to the top shall be as follows:
Current Revision:
Previous Revision:
a)
A wellhead spool (18-5/8" landing base or casing spool) with 20-3/4"
3,000 psi flange and two (2) 3-1/16" 3M side outlets for emergency kill
operations shall be installed. One outlet shall have a 3-1/16" 3M gate
valve with a 3-1/16" 3M blind flange. The other outlet shall have a
manually operated 3-1/16" 3M flanged gate valve next to the wellhead
and a hydraulic control 3-1/16" 3M flanged gate valve tied into the
emergency kill line. The emergency kill line shall be an individual line
with flanged steel piping (no chiksan swings or hammer unions) and a
minimum 3” 10M rated working pressure. Coflex hose (coflon lined)
may be used in combination with steel line. The emergency kill line
shall extend from the wellbore to end of the catwalk (approximately 90
feet), with a 3" 1502 Weco welded union (threaded connections are not
acceptable) for connection to an emergency pump.
b)
If the wellhead top flange is below ground level, a 20-3/4” 3M spacer
spool may be required.
c)
A 26-3/4” or 20-3/4” 3M flanged single ram preventer shall be installed
on the wellhead spool above ground level with master drill pipe rams.
If a 26-3/4” BOP stack is used, a 20-3/4” 3M to 26-3/4” DSA flange will
be required.
d)
A 26-3/4” or 20-3/4” 3M flanged drilling cross shall be installed on the
single ram preventer. A drilling cross shall have two (2) 4-1/16" 10M
side outlets. The same valve arrangement (with same equipment
requirements) on the kill and choke lines as for the Class ‘A’ 10,000 psi
BOP stack shall be used, as shown in Figure J.5.
e)
Either a 26-3/4" or 20-3/4" 3M flanged double ram preventer or two (2)
single ram preventers shall be installed, with blind rams (bottom) and
drill pipe rams (top).
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Note:
Current Revision:
Previous Revision:
All BOP equipment with working pressures of 3,000 psi and above
shall have flanged, welded, integral, or hubbed connections only.
f)
A 26-3/4” or 20-3/4" 3M to 30” 1M or 21-1/4" 2M double studded
adapter flange (DSA) will be required on top of this preventer. The DSA
can be eliminated if a 26-3/4” or 20-3/4" 3M psi flange is manufactured
on the annular preventer.
g)
A 30” 1M or 21-1/4" 2M flanged bottom annular preventer shall
complete this stack. A screw-on top annular is acceptable.
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SECTION J - EQUIPMENT REQUIREMENTS
1.3.2
Smaller Diameter Hole (as with Critical Oil Wells)
At the discretion of the Drilling Manager, some oil wells may require a Class
‘A’ 3,000 psi stacks rather than a Class ‘B’ 3,000 psi stack. All equipment
shall meet NACE Standard MR-01-75 (Latest Revision) for sour service with
a 3,000 psi working pressure. All elements of Class ‘A’ 3,000 psi stacks shall
be 3,000 psi rated working pressure and all flanges on the stack shall be 135/8" 3M. Each ram preventer shall have two (2) 3-1/16" 3M side outlets. A
double ram preventer will have four side outlets.
Shear blind rams (SBR) are required in the Class ‘A’ 3,000 psi stack on
wells in the gas cap or populated areas.
The arrangement from the bottom to the top shall be as follows:
a)
A wellhead spool (13-3/8" landing base) with 13-5/8" 3,000 psi flange
and two (2) 2-1/16" 3M side outlets for emergency kill operations shall
be installed. One outlet shall have a 2-1/16" 3M gate valve with a 21/16" 3M blind flange. The other outlet shall have a manually operated
2-1/16" 3M flanged gate valve next to the wellhead and a hydraulic
control 2-1/16" 3M flanged gate valve tied into the emergency kill line.
The emergency kill line shall be an individual line with flanged steel
piping (no chiksan swings or hammer unions) and a minimum 3” 3M
rated working pressure (if SBR used) otherwise 2” 3M. Coflex hose
(coflon lined) may be used in combination with steel line. The
emergency kill line shall extend from the wellbore to end of the catwalk
(approximately 90 feet), with a 1502 WECO welded union (threaded
connections are not acceptable) for connection to an emergency pump.
Note: If shear blind rams are utilized, then the emergency kill line shall be 3” and
3M rated working pressure. The manual gate valve shall remain as 2” with
double studded adapter to 3”.
b)
If the wellhead top flange is below ground level, a 13-5/8” 3M spacer
spool may be required.
c)
A 13-5/8” 3M flanged single ram preventer shall be installed on the
wellhead spool above ground level with master drill pipe rams.
d)
A 13-5/8” 3M flanged drilling cross shall be installed on the single ram
preventer. A drilling cross shall have two (2) 3-1/16" 3M side outlets.
The same arrangement on the kill and choke lines as for the Class ‘A’
5,000 psi BOP stack (land operation) shall be used, as shown in Figure
J.6.
All steel piping shall be made with 3M flanges, targeted tees, block-tee
elbows, and factory-made 3M working pressure line. All tees must be
targeted with renewable 3M blind flanges (welded tees are not
acceptable).
Chiksans and Weco connections (other than the remote connections at
the end of the catwalk) are not acceptable. Coflex hose (coflon lined)
may be used in combination with steel line.
Current Revision:
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SECTION J - EQUIPMENT REQUIREMENTS
Figure J.6
Class ‘A’ 3,000 psi BOP – (using single size drill pipe)
Smaller Diameter Hole
(Critical Oil Wells)
2-1/16” 3M Kill Line
3-1/16” x 2-1/16”
or Shear Blind Rams
(see Sec. 1.7.4)
3-1/16” ID
3M
2-1/16” 3M Emergency Kill Line
3-1/16” 3M if Shear Blind Rams are utilized
Note:
Current Revision:
Previous Revision:
All BOP equipment with working pressures of 3,000 psi and above
shall have flanged, welded, integral, or hubbed connections only.
e)
Either two (2) 13-5/8" 3M flanged single ram preventers or a double
ram preventer shall be installed, with blind rams or shear blind rams,
see required applications in Section 1.7.4, (bottom) and drill pipe
rams (top).
f)
A 13-5/8" 3M flanged bottom with studded top annular preventer shall
complete this stack.
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SECTION J - EQUIPMENT REQUIREMENTS
1.4
Class ‘B’ 3,000 PSI BOP Stack
A Class ‘B’ 3,000 psi BOP stack (Figure J.7) shall be installed, as a minimum, on all
development oil producers, water injectors, observation and water disposal wells. All
BOP equipment shall be 13-5/8” 3M, with kill and choke line requirements as
previously described in the Class ‘A’ 3M. The kill line shall be 3M and connected
directly to the mud pumps or to the stand pipe manifold.
All tees must be targeted with renewable 3M blind flanges (welded tees are not
acceptable). Chiksans and Weco connections (other than the remote connection on
the emergency kill line at the end of the catwalk) are not acceptable. Coflex hose
(coflon lined) may be used in combination with steel line for kill, emergency kill, or
choke line.
Figure J.7
Class ‘B’ 3,000 psi BOP Stack
2-1/16” 3M
Emergency Kill Line
Note:
Current Revision:
Previous Revision:
All BOP equipment with working pressures of 3,000 psi and above shall have
flanged, welded, integral, or hubbed connections only.
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This stack will also be used for deep gas wells on 24” casing (K1 or K2 well design)
or 18-5/8” casing (MK1 well design). All BOP equipment shall be 26-3/4” 3M, as
previously described in Class ‘A’ 3,000 psi.
1.5
Class ‘C’ 3,000 psi BOP Stack
A Class ‘C’ 3,000 psi BOP stack (Figure J.8) shall be installed on all power water
injector wells during the drilling and acidizing operations in the Arab-D hole section.
The minimum equipment required will be an annular type preventer and a
hydraulically operated dual ram preventer (or two single ram preventers) with blind
rams located on top and pipe rams on bottom. Two (2) 3-1/16” 3M side outlets below
the pipe rams are required, one for the kill line hook-up and other for the choke line.
The kill line shall be adapted to 2-1/16” 3M and connected directly to the mud pumps
or to the stand pipe manifold. A 10” 3M Ball Valve (with 9” bore) is located below the
ram preventers and becomes part of the injection tree upon completion of the well.
All tees must be targeted with renewable 3M blind flanges (welded tees are not
acceptable). Chiksans and Weco connections are not acceptable. Coflex hose
(coflon lined) may be used in combination with steel line for kill or choke line.
Figure J.8
Class ‘C’ 3,000 psi BOP Stack
Double Gate or Two
Single Preventers
3-1/16” Min ID
Ball
Valve
8” Invasion Line to Pit
Current Revision:
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SECTION J - EQUIPMENT REQUIREMENTS
Note:
1.6
All BOP equipment with working pressures of 3,000 psi and above shall have
flanged, welded, integral, or hubbed connections only.
Class ‘D’ Diverter Stack
A Class ‘D’ Diverter stack (Figure J.9) will be installed on the conductor and/or next
casing of all onshore exploration wells and development wells in the shallow gas area
or areas where offset data indicates possible shallow gas. In addition, this diverter
stack will also be required on the conductor of all offshore exploration wells and wells
where offset data indicates possible shallow gas.
The diverter line shall consist of Schedule 40 steel piping. This line shall be securely
anchored and terminate in the reserve pit or overboard. Saudi Aramco requires two
(2) 6” ID full opening valves and 10” lines. All lines must be as straight as possible
and all turns targeted to minimize erosion.
The emergency pump in connection shall be a 3-1/8” 2M flanged connection, located
90 degrees offset from the diverter lines (as noted in Figure J.9 below). The kill line
shall be connected directly to the mud pumps or to the stand pipe manifold.
Figure J.9
Class ‘D’ Diverter Stack
10.75” OD x 10.50” ID
10.75” OD x 10.50” ID
3-1/8” 2M Side Outlet
(offset 900 from diverter lines)
Current Revision:
Previous Revision:
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SECTION J - EQUIPMENT REQUIREMENTS
1.7
General Requirements for Drilling BOP Equipment
•
All newly manufactured BOP equipment shall be API monogrammed.
•
A full OEM certification of the BOP, choke manifold (including chokes), and all
related equipment (i.e. closing unit, kill line valves, choke line valves, coflex hoses
etc.) shall be required at contract start-up and contract renewal with a maximum
period of 3 years between OEM re-certification.
•
The BOP should be opened, cleaned, and visually inspected after every nipple
down, including servicing the manual lock screws.
•
Elastomers exposed to well fluids shall be changed at a maximum of every 12
months, unless visual inspection requires changing earlier. However, it is
acceptable to use seal elements for 30” annulars up to 36 months (provided
inspections are satisfactory, properly documented, and the expiration date of the
elastomer is not exceeded). Seal elements for all other annulars (21-3/4” and
smaller) shall be replaced no later than every 12 months, as per policy.
•
A Maintenance Log for each piece of BOP equipment shall be maintained. This log
shall include, at a minimum, records of all service and inspections performed on the
BOP. The log will travel with the Contractor owned equipment and shall be kept in
the BOP shop for Saudi Aramco owned equipment.
•
The pressure rating of all pressure control equipment (BOP, valves, etc.) must be
greater than the maximum anticipated surface pressure.
•
Vibrator hoses on the rig pumps shall have molded end connections. Threaded or
seal welded connections are not acceptable.
•
The through-bore size of the preventer stack, tubing head, and any adapters used
in the BOP hook-up shall be large enough for the maximum size bit, scraper, liner
hanger, packer, plug, cup tester, or any other large diameter down-hole tools to be
run in the well.
•
Only a drilling spool is acceptable for kill/choke line installation. However in special
cases (as space limitation), preventer side outlets may be used in lieu of a drilling
spool. The diameter of all preventer side outlets must be as large as the choke
manifold lines.
•
Valve Removal (VR) plugs are not required on side outlets of the ram preventers.
•
All ram preventers must be equipped with manual or automatic locking devices,
which must be locked whenever the rams are used to control the well. Hand
crank/wrench or hand wheel systems are acceptable manual locking devices.
•
The inside manual valves on the choke and kill lines are considered master valves
and normally would never, except for pressure testing, be closed unless the outside
valve (HCR) has failed.
•
Check valves must be installed on the kill lines but are not required on the
emergency kill line.
•
The emergency kill line and choke/kill lines should be washed out as required to
prevent mud solids settling.
Current Revision:
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• Preventer assemblies will be dismantled between wells to inspect for internal
corrosion and erosion and to check flange bolts.
•
At least one spare set of ram seals (top seals and packer rams) for all rams,
including packer rams for each size of tubing or drill pipe to be used, bonnet or door
seals, connecting rod seals, plastic packing for ram shaft secondary seals, ring
gaskets to fit flange connections, and spare seal element for the annular preventer
must be on the rig site.
•
Ram blocks should not be dressed until ready to use.
•
Only OEM parts are acceptable when repairing or redressing the BOP, valves,
chokes, and closing units.
•
All rigs shall maintain a logbook of BOP schematics detailing the components
installed in each ram cavity. The logbooks shall contain the part number,
description and installation date of ram blocks, top seals, ram or annular packers
and bonnet/door seals. To be witnessed/co-signed by Toolpusher and Saudi
Aramco Representative (see Form # 1.0 in Section S of this manual).
•
All preventers shall meet NACE STANDARD MR-01-75 (Latest Revision).
1.7.1
Annular Units
§
Cameron, Shaffer, and Hydril are acceptable manufacturers for annulars.
§
The minimum acceptable ratings for H2S and temperature are as follows,
3000 psi and less
5000 psi equipment
10000 psi equipment
2.5% H2S and 180°F
2.5% H2S and 180°F
2.5% H2S and 180°F
§
Gray/Regan diverters are acceptable for 500, 1,000, and 2,000 psi service.
§
If a rotary diverter system is utilized on an offshore rig, the diverter lines must
have the capability of discharging below the bottom of the hull due to H2S.
1.7.2
Fixed Ram Preventers
§
Cameron, Shaffer and Hydril are acceptable manufacturers for fixed rams.
§
As of April 2000, Hydril has met the minimum acceptable ratings.
§
Only fixed rams are acceptable as master pipe rams on all BOP stacks.
§
The minimum acceptable ratings for H2S and temperature are as follows,
3000 psi stack
5.0% H2S and 250°F
5000 psi stack
10.0% H2S and 250°F
10000 psi stack
20.0% H2S and 300°F
Current Revision:
Previous Revision:
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1.7.3
Variable Bore Ram Preventers
§
Variable bore rams (VBR) are optional for tapered drill string applications on
Class ‘A’ stacks. However, the master pipe ram must be a fixed ram.
§
The Cameron Extended Range High Temperature VBR-II Packer (3-1/2” to 57/8” pipe sizes) for the Cameron 13-5/8” U Type blowout preventer is
acceptable for 3M and 5M applications. The VBR was successfully tested to
250 degrees F with a CAMLAST elastomer rated for 20% H2S. See Section S
for details.
§
The minimum acceptable ratings for H2S and temperature for VBRs are,
3000 psi stack
5000 psi stack
10000 psi stack
1.7.4
§
5.0% H2S and 250°F
10.0% H2S and 250°F
20.0% H2S and 250°F
Shear Blind Rams
A new policy of utilizing shear blind rams (SBR) in Saudi Aramco operations
was approved in October 2000.
SBR are required on,
q
q
q
q
q
Class ‘A’ 10000 psi stacks (All Deep Gas Expl./Dev. Wells)
Offshore Class ‘A’ 5000 psi stacks (All Offshore Wells)
Onshore Class ‘A’ 5000 psi stacks (Expl./Dev. Wells >10 % H2S)
Gas Cap Wells (Either 3000 or 5000 Class ‘A’ Stacks)
Populated Wells (All Wells in Populated Areas)
§
Cameron’s 13-5/8” and 11” Shearing Blind Rams (for use with U-Type ram
preventer) are acceptable for pressure applications to 10M psi. Recent HTHP
testing at Cameron has exceeded the requirements of API 16A and Saudi
Aramco specifications (300 degrees F and 20% H2S). See Section S for details.
§
Shaffer’s 13-5/8” ‘V’ Shear Ram (for use with Model SL ram preventer) is also
acceptable for pressure applications to 10M psi. Recent HTHP testing at
Shaffer has exceeded the requirements of API 16A and Saudi Aramco
specifications (300 degrees F and 20% H2S). See Section S for details.
§
The minimum acceptable ratings for H2S and temperature for SBR are,
3000 psi stack
5.0% H2S and 250°F
5000 psi stack
10.0% H2S and 250°F
10000 psi stack
20.0% H2S and 300°F
Note: The minimum temperature rating for 10M has been increased from 250
to 300 degrees F because of successful test results by Shaffer and
Cameron.
§
Hydril’s shear blind rams are not approved at this time. Their current
0
temperature rating is limited to 180 F.
§
All rigs utilizing SBR shall have a 3” emergency kill line. This will provide
additional emergency kill line capacity, in case the SBR did not make a proper
seal after cutting the pipe. If the wellhead spool outlet is 2”, then the inboard
manual valve shall be 2” with DSA back to 3”.
Current Revision:
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§
The table below indicates the shear capability of SBR for different BOP
pressure applications.
SHEAR BLIND RAM CAPABILITY
10,000 PSI SERVICE
BOP
BOPE
SERVICE
SIZE - WP
MFG.
DRILL PIPE SHEAR
REQUIRED
OPERATOR
OEM
CAPABILITY
SHEAR
REQUIRED
SIDE PACKER
BLIND
SIZE
CLASS
Ø DEEP GAS
CAMERON (1)
13-5/8" 10M
CLASS 'A'
EXPL/ DEV.
RATINGS
TEMP, 0F
RAM TYPE
H2S, %
'SBR'
YES/ LBT (2)
300
20
'V'
14"/10" (3)
300
20
'SBR'
YES/ LBT (2)
300
20
'T-72'
14"/10" (3)
250
20
DRILL PIPE SHEAR
REQUIRED
OPERATOR
OEM
CAPABILITY
SHEAR
REQUIRED
SIDE PACKER
BLIND
SIZE
ALL SIZES TO
5-1/2" 24.7# G-105
SHAFFER (1)
ALL SIZES TO
5-1/2" 24.7# G-105
CAMERON (1)
11" 10M
CLASS 'A'
ALL SIZES TO
5" 19.5# G-105
SHAFFER (1)
ALL SIZES TO
5" 25.6# G-105
3,000 - 5,000 PSI SERVICE
BOP
BOPE
SERVICE
SIZE - WP
MFG.
CLASS
RAM TYPE
Ø OFFSHORE
13-5/8" 3-5M
Ø ONSHORE
CLASS 'A'
CAMERON (1)
ALL SIZES TO
'SBR'
RATINGS
TEMP, 0F
YES/ LBT (2)
H2S, %
250
20
5-1/2" 24.7# G-105
Ø EXPL/DEV. w/
H2S > 10%
DUAL TUBING
(SHEAR RAMS UNDER REVIEW)
STRINGS
Ø GAS CAP
WELL
Ø POPULATED
AREAS
SHAFFER (1)
ALL SIZES TO
'V'
14"/10" (3)
250
20
'SBR'
YES/ LBT (2)
250
20
'T-72'
14"/10" (3)
250
20
5-1/2" 24.7# G-105
11" 3-5M
CAMERON (1)
CLASS 'A'
ALL SIZES TO
5" 19.5# G-105
SHAFFER (1)
ALL SIZES TO
5" 25.6# G-105
NOTE:
Current Revision:
Previous Revision:
(1)
(2)
(3)
BOTH CAMERON AND SHAFFER ARE APPROVED MANUFACTURERS.
CAMERON - LBT REFERS TO LARGE BORE SHEAR BONNETS WITH TANDEM BOOSTERS.
SHAFFER - 14" OPERATOR WITH 10" BOOSTER IS REQUIRED.
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1.7.5
§
Flanges installed on the side outlets of ram preventers that do not have VR
(Valve Removal) plugs installed shall be blind with no penetrations.
§
Flanges installed on the side outlets of ram preventers that have VR (Valve
Removal) plugs installed shall have a ½” NPT tap with a ½” NPT plug installed.
1.7.6
2.0
Blind Flanges on BOP Side Outlets
Minimum Bore Requirements for Kill, Emergency Kill, and Choke Lines
§
The minimum bore size for kill, emergency kill, and choke lines shall be the
same bore as the weld neck flange used in the pressure application (see
specification details in Section R).
§
All lines shall be welded and pressure tested as per API Specification 6A.
Workover BOP Stacks
Maintaining control of a well during the completion and workover phases may be more
complicated than well control in drilling operations. Additional complications may exist as, a)
various types of workover fluids ranging from low-density diesel to high-density brine fluids
may be used; b) interrelated activities may occur simultaneously, such as workovers on a
platform with producing wells.
Saudi Aramco has four (4) classes of BOP arrangements for workover operations. The
workover program shall specify the Class BOP stack (not individual components) to be
used.
2.1
Class ‘I’ 2000 psi Workover Stack
a)
This class is used on water supply wells and shallow low-pressure aquifer
observation wells, where the operation to be performed on the well and/or
space below the rig substructure precludes use of ram-type preventers.
b)
The minimum equipment required will be a Hydril, Cameron, or Shaffer
annular type preventer. A 2” kill and/or fill-up line shall be connected to the
landing base side outlet.
c)
When sufficient space below the rig substructure is available, a ball valve shall
be used below the annular, as shown in Figure J.10.
d)
Annular preventer will be visually inspected and functionally tested prior to
installation and pressure tested after installation using a cup-type tester set at a
depth of 60’. Test pressures will be specified in the workover program.
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Ball
Valve
2.2
Class ‘II’ 3000 psi Workover Stack
a)
This class BOP stack is used on most onshore workovers to be performed on
producing, water injection and reservoir observation wells. These wells are
normally low-pressure and equipped with 3000 psi WP wellhead equipment.
b)
The minimum equipment required will be an annular type preventer and a
hydraulically operated dual ram preventer (or two single ram preventers) with
blind rams (bottom) and pipe rams (top). Two (2) 3-1/16” 3M side outlets from
below the blind rams are required, one for kill line hook-up and one for the
choke line.
c)
The kill line shall be adapted to 2-1/16” 3M and connected directly to the mud
pumps or to the stand pipe manifold.
d)
Position manual valves adjacent to the stack and HCR valves outboard on the
kill and choke lines, as shown in Figure J.11.
e)
All tees must be targeted with renewable 3M blind flanges (welded tees are not
acceptable). Chiksans and Weco connections are not acceptable. Coflex hose
(coflon lined) may be used in combination with steel line for kill or choke line.
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Double Gate or
Two Single
3-1/16” Min
Two (2) 3” minimum flanged outlets required
below blind rams (one for the kill line hook-up
and the other for the choke line). The kill line
shall be adapted to 2-1/16” 3M.
Note:
2.3
2.4
All BOP equipment with working pressures of 3,000 psi and above shall have flanged,
welded, integral, or hubbed connections only.
Class ‘III’ 5000 psi Workover Stack (same as Class ‘A’ 5000 psi Drilling Stack)
a)
This class BOP is used on most offshore workovers and onshore wells with
5000 psi WP wellhead equipment.
b)
The Class ‘III’ 5000 psi workover stack is arranged the same as the Class ‘A’
5000 psi drilling stack. All equipment requirements are as previously discussed
in Section 1.2 and shown in Figures J.3 and J.4.
Class ‘IV’ 10000 psi Workover Stack (same as Class ‘A’ 10000 psi Drilling Stack)
a)
This class BOP is used on all workovers with 10000 psi WP wellhead
equipment.
b)
The Class IV 10000 psi workover stack is arranged the same as the Class ‘A’
10000 psi drilling stack. All BOP equipment in this stack shall be 11” 10M rated
working pressure, including the annular preventer. All other equipment
requirements are as previously discussed in Section 1.1 and shown in Figures
J.1 and J.2.
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2.5
General Requirements for Workover BOP Equipment
•
All newly manufactured BOP equipment shall be API monogrammed.
•
A full OEM certification of the BOP, choke manifold (including chokes), and all
related equipment (i.e. closing unit, kill line valves, choke line valves, coflex hoses
etc.) shall be required at contract start-up and contract renewal with a maximum
period of 3 years between OEM re-certification.
•
The BOP should be opened, cleaned, and visually inspected after every nipple
down, including servicing the manual lock screws.
•
Elastomers exposed to well fluids shall be changed at a maximum of every 12
months, unless visual inspection requires changing earlier. However, it is
acceptable to use seal elements for 30” annulars up to 36 months (provided
inspections are satisfactory, properly documented, and the expiration date of the
elastomer is not exceeded). Seal elements for all other annulars (21-3/4” and
smaller) shall be replaced no later than every 12 months, as per policy.
•
A Maintenance Log for each piece of BOP equipment shall be maintained. This log
shall include, at a minimum, records of all service and inspections performed on the
BOP. The log will travel with the Contractor owned equipment and shall be kept in
the BOP shop for Saudi Aramco owned equipment.
•
The pressure rating of all pressure control equipment (BOP, valves, etc.) must be
greater than the maximum anticipated surface pressure during the workover.
•
Vibrator hoses on the rig pumps shall have molded end connections. Threaded or
seal welded connections are not acceptable.
•
The through-bore size of the preventer stack, tubing head, and any adapters used
in the BOP hook-up shall be large enough for the maximum size bit, scraper, liner
hanger, packer, plug, cup tester, or any other large diameter down-hole tools to be
pulled or run.
•
A double-ram preventer may be used in the Class ‘II’ 3M stack, but the connection
for the choke line and kill line must be below the blind ram (lower ram). The
diameter of all preventer side outlets must be as large as the choke manifold lines.
•
Valve Removal (VR) plugs are not required on side outlets of the ram preventers.
•
All ram preventers must be equipped with manual or automatic locking devices,
which must be locked whenever the rams are used to control the well. Hand
crank/wrench or hand wheel systems are acceptable manual locking devices.
•
The inside manual valves on the choke and kill lines are considered master valves
and normally would never, except for pressure testing, be closed unless the outside
valve (HCR) has failed.
•
Check valves must be installed on the kill lines but are not required on the
emergency kill line.
•
The emergency kill line and choke/kill lines should be washed out as required to
prevent mud solids settling.
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•
Preventer assemblies will be dismantled between wells to inspect for internal
corrosion and erosion and to check flange bolts.
•
At least one spare set of ram seals (top seals and packer rams) for all rams,
including packer rams for each size of tubing or drill pipe to be used, bonnet or door
seals, connecting rod seals, plastic packing for ram shaft secondary seals, ring
gaskets to fit flange connections, and spare seal element for the annular preventer
must be on the rig site.
•
Ram blocks should not be dressed until ready to use.
•
Only OEM parts are acceptable when repairing or redressing the BOP, valves,
chokes, and closing units.
•
All rigs shall maintain a logbook of BOP schematics detailing the components
installed in each ram cavity. The logbooks shall contain the part number,
description and installation date of ram blocks, top seals, ram or annular packers
and bonnet/door seals. To be witnessed/co-signed by Toolpusher and Saudi
Aramco Representative (see Form # 1.0 in Section S of this manual).
•
All preventers shall meet NACE STANDARD MR-01-75 (Latest Revision).
•
All workover rigs using a 3M choke manifold shall use the manifold configuration
described in Section J 4.0.3. This manifold includes one (1) 3” minimum diameter
choke line, two (2) 3” minimum flare lines, a manual adjustable choke and a remote
hydraulic controlled adjustable choke.
•
All wells on the same offshore platform shall be shut-in prior to workover operations
using two (2) mechanical methods of isolation,
Below Surface:
Closed and Tested Surface Controlled Sub-Surface Safety Valve
(locked out of operation). Prior to moving in a workover rig, Field
Services will close Sub-Surface Safety Valves on all wells and
de-pressurize the platform. If a Sub-Surface Safety Valve is
leaking, Well Services will replace the valve.
At Surface:
Closed Master Valve
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2.5.1
Annular Units
§
Cameron, Shaffer, and Hydril are acceptable manufacturers for annulars.
§
The minimum acceptable ratings for H2S and temperature are as follows,
3000 psi and less
5000 psi equipment
10000 psi equipment
2.5% H2S and 180°F
2.5% H2S and 180°F
2.5% H2S and 180°F
§
Gray/Regan diverters are acceptable for 500, 1,000, and 2,000 psi service.
§
If a rotary diverter system is utilized on an offshore rig, the diverter lines must
have the capability of discharging below the bottom of the hull due to H2S.
2.5.2
Fixed Ram Preventers
§
Cameron, Shaffer and Hydril are acceptable manufacturers for fixed rams.
§
As of April 2000, Hydril has met the minimum acceptable ratings.
§
Only fixed rams are acceptable as master pipe rams on all BOP stacks.
§
The minimum acceptable ratings for H2S and temperature are as follows,
3000 psi stack
5.0% H2S and 250°F
5000 psi stack
10.0% H2S and 250°F
10000 psi stack
20.0% H2S and 300°F
2.5.3
Variable Bore Ram Preventers
§
Variable bore rams (VBR) are optional for tapered drill string applications on
Class ‘A’ stacks. However, the master pipe ram must be a fixed ram.
§
The Cameron Extended Range High Temperature VBR-II Packer (3-1/2” to 57/8” pipe sizes) for the Cameron 13-5/8” U Type blowout preventer is
acceptable for 3M and 5M applications. The VBR was successfully tested to
250 degrees F with a CAMLAST elastomer rated for 20% H2S. See Section S
for details.
§
The minimum acceptable ratings for H2S and temperature for VBRs are,
3000 psi stack
5000 psi stack
10000 psi stack
2.5.4
§
5.0% H2S and 250°F
10.0% H2S and 250°F
20.0% H2S and 250°F
Shear Blind Rams
A new policy of utilizing shear blind rams (SBR) in Saudi Aramco operations
was approved in October 2000.
SBR are required on,
q
q
q
q
q
Current Revision:
Previous Revision:
Class ‘A’ 10000 psi stacks (All Deep Gas Expl./Dev. Wells)
Offshore Class ‘A’ 5000 psi stacks (All Offshore Wells)
Onshore Class ‘A’ 5000 psi stacks (Expl./Dev. Wells >10 % H2S)
Gas Cap Wells (Either 3000 or 5000 Class ‘A’ Stacks)
Populated Wells (All Wells in Populated Areas)
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§
Cameron and Shaffer are acceptable manufacturers for SBR (refer to Section
1.7.4 for details).
§
The minimum acceptable ratings for H2S and temperature for SBR are,
3000 psi stack
5000 psi stack
10000 psi stack
§
Hydril’s shear blind rams are not approved at this time. Their current
0
temperature rating is limited to 180 F.
§
All rigs utilizing SBR shall have a 3” emergency kill line. This will provide
additional emergency kill line capacity, in case the SBR did not make a proper
seal after cutting the pipe. If the wellhead spool outlet is 2”, then the inboard
manual valve shall be 2” with DSA back to 3”.
§
The table shown in Section 1.7.4 indicates the shear capability of SBR for
different BOP pressure applications.
2.5.5
Blind Flanges on BOP Side Outlets
§
Flanges installed on the side outlets of ram preventers that do not have VR
(Valve Removal) plugs installed shall be blind with no penetrations.
§
Flanges installed on the side outlets of ram preventers that have VR (Valve
Removal) plugs installed shall have a ½” NPT tap with a ½” NPT plug installed.
2.5.6
3.0
5.0% H2S and 250°F
10.0% H2S and 250°F
20.0% H2S and 300°F
Minimum Bore Requirements for Kill, Emergency Kill, and Choke Lines
§
The minimum bore size for kill, emergency kill, and choke lines shall be the
same bore as the weld neck flange used in the pressure application (see
specification details in Section R).
§
All lines shall be welded and pressure tested as per API Specification 6A.
Special Well Operations BOP Stacks
The following represents Drilling and Workover’s minimum BOP equipment requirements
for coil tubing, snubbing, and wireline operations. In some cases, the service company’s
internal policy may exceed these BOP requirements.
3.1
BOP Equipment Requirements for Coil Tubing Operations
BOP equipment requirements for low-pressure and high-pressure coil tubing (CT)
operations are shown in Figures J.12 and J.13, respectively. Selecting the BOP
arrangement shall be based on the maximum anticipated operating or shut-in
wellhead pressure. These arrangements are for standard CT operations and
should be modified as needed for special or unusual applications.
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3.1.1
Low-Pressure Coiled Tubing BOP Equipment Requirements
The low-pressure or standard arrangement (less than 5000 psi WHP) includes
4 sets of rams: blinds rams on top, cutter rams in the #2 position, slip type
rams in the #3 position, and tubing rams in the #4 position. In addition, there is
a flow cross with a valve installed below the cross. See Figure J.12.
Figure J.12
Low-Pressure Coil Tubing BOP Arrangement
Low-pressure stacks shall comply with the following minimum requirements:
•
•
•
•
•
•
•
•
•
•
Current Revision:
Previous Revision:
All equipment shall meet or exceed NACE MR-01-75 and API Standards
for well control
Rated WP greater than the maximum anticipated well pressure
Side-door stripper
Minimum BOP configuration of blind, shear, slip, and pipe rams
Kill line with minimum 2-1/16” flanged connection
Flow cross with flanged outlets and double valves
Ability to monitor wellhead pressure below the pipe rams with isolator
Slip design that will minimize fatigue/deformation damage
Slip rams capable of holding the pipe up to the yield point with maximum
rated WP in a hang-off mode
Accumulator shall be sized to operate all BOPE (close-open-close) at
maximum rated WP
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3.1.2
High-Pressure Coiled Tubing BOP Equipment Requirements
The high-pressure arrangement (greater than 5000 psi WHP) includes the
same equipment as in the low-pressure arrangement, plus a second set of
tubing rams below the flow cross when lifting the well. The master pipe rams
should be substituted for combination shear/seal and pipe/slip rams when
flowing the well with coil tubing in the hole (i.e. treating or production logging). A
second stripper is also required when treating or production logging. See
Figure J.13.
Figure J.13
High-Pressure Coil Tubing BOP Arrangement
High-pressure stacks shall comply with the following minimum requirements:
•
•
•
•
•
•
•
•
•
•
•
•
Current Revision:
Previous Revision:
All equipment comply or exceed NACE STANDARD MR-01-75 and API
Standards for well control
Rated WP greater than the maximum anticipated well pressure
Side-door stripper
Second side-door or radial stripper is required if flowing well w/ CT in hole
Minimum BOP configuration of blind, shear, slip, pipe rams, and master
pipe rams below flow cross
Master pipe rams should be substituted for combination shear/seal and
pipe/slip rams when flowing the well with CT in the hole
Kill line with minimum 2-1/16” flanged connection
Flow cross with flanged outlets and double valves
Ability to monitor wellhead pressure below the pipe rams with isolator
Slip design that will minimize fatigue/deformation damage
Slip rams capable of holding the pipe up to the yield point with maximum
rated WP in a hang-off mode
Accumulator shall be sized to operate all BOPE (close-open-close) at
maximum rated WP
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3.2
BOP Arrangement for Snubbing Operations
The stack arrangements in Figure J.14 and J.15 show basic set-ups for lowpressure and high-pressure snubbing operations. Selecting the BOP arrangement
shall be based on the maximum anticipated operating or shut-in pressure.
3.2.1
Low-Pressure Snubbing BOP Equipment Requirements
The low-pressure (less than 5000 psi WHP) or standard arrangement’s
basic features are the #1 and #2 stripping rams, equalizing loop, safety,
and blind rams. The primary rams are the #1 and #2 stripping rams. These
rams are used in conjunction with the equalizing loop to strip the pipe into
or out of the hole. The equalizing loop and vent line are used to bleed off
the pressure. Note that the equalizing loop contains a fixed or positive
choke to minimize the surge pressure when bleeding off the pressure.
Each set of valves contains one manual and one remotely operated valve.
Below the #2 rams is a set of safety or secondary rams to be used
whenever either of the stripper rams begin to leak or fail. Below the safety
rams is a set of blind rams to be used to shut the well in when pipe is out of
the hole or landed in the hangar.
Figure J.14
Low-Pressure Snubbing Stack
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3.2.2
High-Pressure Snubbing BOP Equipment Requirements
The high-pressure arrangement (greater than 5000 psi WHP) includes
everything the standard arrangement has plus a second spool with dual
outlets that contains a remotely operated choke, a set of shear blind rams,
and a second set of safety rams. The shear blind rams are considered a
third line of defense and are a last resort if primary control of the well is
lost. In addition, a positive choke is added to the vent line to allow a slower
bleed-off of pressure from the well.
Figure J.15
High-Pressure Snubbing Stack
Outlet Spool with Dual
Hydraulic
Chokes
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3.3
BOP Arrangements for Electric Line Operations
The required BOP arrangement shall be determined by the electric line
application (open-hole or cased hole) and maximum anticipated surface
pressure during the operation. All BOP equipment shall comply with API 6A and
NACE MR-01-75 (Latest Revision).
3.3.1
Open-Hole Electric Line BOP Requirements (Over-Balanced Condition)
When open-hole logging, an electric line BOP is not required, provided
primary well control (hydrostatic pressure > formation pressure) can be
maintained and confirmed. However, an electric line BOP is recommended
on all gas wells by the Gas Drilling & Workover Operations Department.
3.3.2
Cased-Hole Electric Line BOP Requirements (Under-Balanced Condition)
When perforating or logging under-balanced, an electric line BOP and
lubricator are required with a wellhead adapter flange connected to the top
of the test head or tree. Minimum electric line BOP requirements for
various cased-hole pressure applications are summarized below.
Cased-Hole Electric Line
BOP Requirements:
Wells with Max.
Expected WHP
< 5,000 psi
Wells with Max.
Expected WHP
5,000 to 10,000
psi
5,000 psi
10,000 psi
Not Acceptable
Not Acceptable
Required
Required
2
3
2500 F
3000 F
Tool Trap
Required
Required
Tool Catcher
Optional
Optional
Ball Check Valve
Required
Required
Remote Grease Injection Unit
Stuffing Box with Hydraulic
Operated Pack-Off
Required
Required
Required
Required
(Under-Balanced Condition)
7/32 –1/4” Line
Working Pressure
Manual BOP
Hydraulic BOP
Minimum Number of Rams
Minimum Temperature
Rating of Elastomer
A stuffing box (w/ hydraulic operated pack-off) is required in unperforated
cased hole when running CBL, or similar logs, with + 1000 psi surface
pressure while logging. An electric line BOP is optional in this situation.
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A typical electric line rig-up for cased-hole operations is shown in Figure
J.16.
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4.0
Choke Manifolds
All choke manifolds and piping shall meet Sour Service NACE MR-01-75 (Latest Revision)
and API Specification 6A. Required specifications and applications for the 10000 psi, 5000
psi, and 3000 psi choke manifolds are shown below.
4.0.1
10,000 psi Working Pressure Choke Manifold
ACCEPTABLE FOR THE FOLLOWING CLASS APPLICATIONS:
CLASS ‘A’ 10,000 PSI (DRILLING)
CLASS ‘IV’ 10,000 PSI (WORKOVER)
All 10M psi (& higher) choke manifolds shall comply with the following minimum requirements:
• Valves and chokes shall be monogrammed to API Specification 6A and made to
the following,
PSL-2 (with PSL-3 gas test)
PR-1
MR-EE
TR-U (Suitable for 3000 F service)
Forged Bodies and Bonnets
All valves must be of a single gate (slab) design
• All flanges and other components shall be monogrammed to API Spec-6A
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4.0.2
5,000 psi Working Pressure Choke Manifold
Choke manifold configurations for 5,000 psi onshore and offshore applications
are shown in Figure J.18 and Figure J.18A respectively. Figure J.18B shows the
test manifold and associated required connections from the choke manifold in
offshore applications.
ACCEPTABLE FOR THE FOLLOWING ONSHORE APPLICATIONS:
CLASS ‘A’ 5,000 PSI (DRILLING)
CLASS ‘III’ 5,000 PSI (WORKOVER)
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ACCEPTABLE FOR THE FOLLOWING OFFSHORE APPLICATIONS:
CLASS ‘A’ 5,000 PSI (DRILLING)
CLASS ‘III’ 5,000 PSI (WORKOVER)
Note:
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Previous Revision:
All 3-1/8” lines shall be 5M flanged steel piping or Coflex flexible hose (coflon lined, with a
3” minimum ID). A combination of flanged steel piping and Coflex hose is acceptable.
Weco or chiksan-type connections are not acceptable. Only targeted or block-tee elbows
with renewable blind flanges are acceptable.
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All 5M psi choke and test manifolds shall comply with the following minimum requirements:
• Valves and chokes shall be monogrammed to API Specification 6A and made
to the following,
PSL-2
PR-1
MR-EE
TR-U
Forged Bodies and Bonnets
All valves must be of a single gate (slab) design
•
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All flanges and other components shall be monogrammed to API Spec-6A
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4.0.3
3,000 psi Working Pressure Choke Manifold
Figure J.19
3,000 psi Working Pressure Choke Manifold
Note: 1.
2
3
Manual Valves on LP downstream side of Buffer Tank are normally OPEN
Manual Valves upstream of Buffer Tank are normally OPEN
Manual Valve upstream of Buffer Tank on emergency gut line is normally CLOSED and downstream
Manual Valve is normally OPEN
Manual
Adjustable Choke
3-1/16” Min. x 3M
OPEN
Note - 1
#1 To Flare Pit
(3” Minimum Line)
OPEN
#2 To Flare Pit
(3” Minimum Line)
OPEN
To Shaker/Trip Tank
3-1/16” Min. x 3M
CLOSED
4-Way Cross
w/ Pressure Tap and
Gauge
3-1/16” Min. x 3M
OPEN
8” Minimum O.D
-
Remote Controlled
Hydraulic Choke
ACCEPTABLE FOR THE FOLLOWING CLASS APPLICATIONS:
CLASS ‘A’ 3,000 PSI (DRILLING)
CLASS ‘B’ 3,000 PSI (DRILLING)
CLASS ‘C’ 3,000 PSI (DRILLING)
CLASS ‘II’ 3,000 PSI (WORKOVER)
All 3M psi choke manifolds shall comply with the following minimum requirements:
• Valves and chokes shall be monogrammed to API Specification 6A and made
to the following,
PSL-2
PR-1
MR-EE
TR-U
Forged Bodies and Bonnets
All valves must be of a single gate (slab) design
• All flanges and other components shall be monogrammed to API Spec-6A
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4.1
Location
The choke manifold shall be skid mounted on land rig (rig floor mounted on
offshore rigs) and located in an accessible area.
4.2
Choke Manifold Pressure Ratings
The complete choke manifold, chokes, valves and piping will be full working
pressure of the BOP stack through the block valves down-stream of the chokes.
4.3
Piping Specifications
The piping from the BOP stack to the choke manifold shall have the same working
pressure (or greater) as the BOP stack. All piping shall meet Sour Service NACE
MR-01-75 (Latest Revision) and API Specification 6A.
Choke lines for 3M and 5M applications shall either be steel pipe, Coflex hose
(coflon lined only), or combination of Coflex and steel pipe. All flexible hose shall be
monogrammed to API Specification 16C, and all end connections monogrammed
to API Specification 6A.
Choke lines for 10000 psi application shall be flanged pipe only.
All fabricated steel piping shall be as straight as possible, with targeted or block-tee
elbows at turns. All tees must be targeted with renewable blind flanges (welded
tees are not acceptable).
All choke line and manifold connections shall be flanged, welded, integral, or
hubbed. Chiksans and Weco connections are not acceptable.
4.4
Choke Manifold Discharge
Provisions shall be made for the discharge from the choke manifold to be
selectively diverted to:
4.4.1
Flare Lines
Two (2) 3-1/2” EUE flare lines, each approximately 400 feet in length, shall
be required for onshore oil wells.
Four (4) 4-1/2” LTC gas flare lines and one (1) 3-1/2” EUE liquid flare line,
each 1000 feet in length, shall be required for onshore gas wells.
Note:
Using drill pipe for flare line is not recommended because of the
difficulty of properly making up the connections on the ground.
Elbows and chiksans on the flare line are susceptible to erosion/washouts
and are not acceptable (because of the potential for high fluid velocities).
The flare line, as with the choke line, shall be as straight as possible, with
targeted or block-tee elbows at turns, as required.
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An alternate flare pit and flare line will be rigged-up on deep gas wells
(Figure J.20). This emergency flare pit will be used in well kill operations if
the main flare pit cannot be utilized due to change in wind direction.
Electronic flare ignition sources shall be positioned in the main flare pit,
alternate flare pit, and gas buster flare pit.
4.4.2
Gas Buster Lines
There should be a bypass line up-stream of the gas buster directly to the
flare line and a valve on the gas buster inlet line to protect the separator
from high pressure. The mud discharge line from the gas buster must have
a vacuum breaker stacked vent line if the discharge line outlet is lower than
the bottom of the separator. This is to prevent siphoning gas from the
separator to the mud pits. The vacuum breaker stack must be as high as
the gas buster.
One (1) 8” flanged/clamped steel vent line, minimum of 240 feet in length
(from the gas buster), shall be required for onshore oil wells.
Two (2) 8” flanged/clamped steel vent line, minimum of 240 feet in length
(from the gas buster), shall be required for onshore gas wells.
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The flare pit shall be positioned away from the reserve/waste pits to
prevent ignition of any waste hydrocarbons while circulating gas from the
wellbore.
Specific design requirements for gas buster are discussed in Section 8.3.
4.5
Choke Requirements
A remote-controlled hydraulic choke(s) shall be installed on each manifold. A
SWACO ‘Super Choke’, Cameron Drilling Choke or NL Drilling Choke are
acceptable units. Other hydraulic control steel drilling chokes will be considered on
an individual basis. All hydraulic control chokes must be able to provide full
closure.
§
§
§
4.6
Two (2) remote-controlled hydraulic chokes are required on all 10M applications
Two (2) remote-controlled hydraulic chokes are required on all 5M applications
One (1) remote-controlled hydraulic choke is required on all 3M applications
Valve Requirements
All manifold valves shall be non-rising stem gate or plug valves and monogrammed
to API Specification 6A. Additional valve specifications are described in Figures
J.17, J.18, and J.19 for each pressure application. It is acceptable to convert API
monogrammed ‘DD’ valves to ‘EE’ under API 6A, Section 11.
4.7
Gauges
All chokes manifolds shall have a remote reading pressure gauge on the rig floor at
the hydraulic operating panel.
4.8
Line Maintenance
The choke line, choke manifold, mud/gas separator, valves, lines and flare lines
shall be flushed with water after testing or use.
4.9
Normal Valve Position
During normal operations, the valves downstream from the hydraulic control gates
and the hydraulic control chokes shall be in the open position as shown in Figures
J.17, J.18, and J.19.
5.0
Accumulator Closing Units
The brand of closing unit used by the drilling contractor is not dictated by Saudi Aramco;
however, the closing unit must meet the following minimum requirements.
5.1
Fluid Requirements
The accumulator shall store enough fluid under pressure to close all preventers,
open the choke hydraulic control gate valve (HCR), and retain 50% of the
calculated closing volume with a minimum of 200 psi above pre-charge pressure,
without assistance of the accumulator pumps.
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5.2
Design Requirements
The accumulators and all fittings are to be 3,000 psi working pressure. Hydraulic
lines from the accumulator to the BOP stack shall be designed and manufactured
in compliance with API Specification 16D. They must be steel or approved armored
hose (equivalent to Goodhall No. 660 with 4000 psi working pressure). Manifold
and BOP hydraulic lines should be tested to 3,000 psi at installation to ensure
pressure integrity at higher pressures.
Note:
5.3
All air and hydraulic BOP operating units shall be equipped with regulator valves
similar to the Koomey Type TR-5, which will not fail open causing loss of operating
pressure.
Bottle Pre-Charge Requirements
The accumulator bottles will be pre-charged with nitrogen as per manufacturer’s
specifications/recommendations. The minimum required pre-charge pressure
for a 3000 psi working pressure accumulator unit is 1,000 psi. The nitrogen
pre-charge pressure shall be checked and adjusted prior to connecting the closing
unit to the BOP stack and any other time the accumulator must be completely depressured.
The accumulator should be capable of closing each ram within 30 seconds.
Closing time should not exceed 30 seconds for annulars smaller than 18-3/4”
nominal bore and 45 seconds for annular preventers of 18-3/4” and larger.
5.4
Operator Control Requirements
All operating controls shall be clearly marked with function and ram sizes.
Accumulator controls must be in open or closed position, but not in neutral
position. During normal drilling operations the hydraulic control choke line gate
valve next to the wellhead will be closed.
5.5
Accumulator Location
The accumulator shall be located at a remote location, at least 60 feet distance
from the wellbore for oil wells and 100 feet for gas wells, shielded from the
wellhead and protected from other operations around the rig. There must be at
least two (2) sets of remote controls for operating the accumulator to activate the
BOPs. One remote control shall be on the rig floor, accessible to and visible by the
driller and the other shall be located 100’ from the wellhead and near the Company
Representative’s office. Master Controls shall be at the accumulator.
5.6
Pump System
The primary electric/hydraulic pump system and the secondary air/hydraulic pump
system must be independent of each other and fully operational when the
accumulator is in use. The high-pressure set point for both the electric pump and
air pump should be 3,000 psi. The low-pressure set point should be above 2,800
psi for both systems. Do not bleed off pressure due to ambient temperature rise.
Pressure may vary from 3,000 to 3,400 psi in a 24-hour period.
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5.7
Pressure Regulator Settings
The pressure regulators for the annular preventer and ram preventers will be set as
per manufacturer’s specification/recommendation.
6.0
Note 1
For non-emergency BOP operation, use of the lowest possible pressure for daily
operation will extend rubber life. Upon completion of daily testing, return pressure
regulators to normal operations pressure.
Note 2
DO NOT close annular preventers on open hole for complete shut-off except in an
emergency.
Note 3
DO NOT close pipe rams without pipe in the hole. Pipe rams should only be
closed on the proper size pipe in order to avoid damage to the rubber packer or to
the ram carriers.
Sizing BOP Closing Equipment
6.1
General Requirements
The accumulator system and pumps must be of adequate capacity for the BOP
stack in use. The system must hold pressure without leaks or excessive pumping
and should maintain enough pressure capacity reserve to close the preventers with
the recharging pumps turned off. These pumps are designed to charge the
accumulator within a reasonable time period and maintain this charge during
preventer operations.
Saudi Aramco’s design base for accumulator capacity is the following:
a. A hydraulic actuating system that provides sufficient accumulator
capacity to supply 1.5 times the volume necessary to close and
hold closed all BOP equipment units with a minimum pressure of
200 psi above the pre-charge pressure without assistance from a
charging system.
b. An accumulator-backup system shall be automatic, supplied by a
power source independent from the power source to the primary
accumulator-charging system, and possess sufficient capability
to close all blowout components and hold them closed.
The design base is equivalent to sizing a 3000 psi accumulator (1000 psi precharge) with enough capacity to close the annular and all ram preventers one time,
with the pumps out of service, while maintaining a minimum remaining operating
pressure of 1500 psi. This equivalence is shown on the next page.
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This demanding base using a 50% safety factor is recommended by Saudi Aramco
because it provides complete replenishment of fluid in “close” lines at the time
preventers are activated. The safety factor also allows for loss of fluid capacity due
to “inter-flow” in the four-way valves and possible loss through the packing of the
preventer units.
Opening/closing volume tables provide the necessary information to calculate
individual requirements as to accumulator size needed. Hydraulically operated
choke and kill line valves require added fluid capacity. It must be remembered that
only one-half to two-thirds of the accumulator bottle is liquid filled when fully
charged, depending on the unit.
6.2
Size Calculations
a)
Determine the total gallons to close all the preventers.
Check with manufacturer for exact volumes to function BOP equipment.
Blowout Preventer Equipment
Gallons
To Close
Typical Annular B.O.P. (13 5/8”, 5,000 psi W.P.)
after normal wear
17.98
Three Typical Ram B.O.P.’s (13 5/8”, 5,000 psi W.P.)
(3 X 5.8 gallons)
17.40
Total Gallons for Full Closure of All Preventers
35.38
The total system accumulator capacity should meet
or exceed the following requirements:
Total Gallons to Close
35.38
50% Safety Factor (Required)
17.69
Total Gallons of Usable Fluid Required (VR)
53.07
b)
Calculate the total volume (nitrogen and fluid) required for a 3,000 psi
accumulator.
Use equation below and refer to pressure and volume diagram in Figure 21.
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Equation J.1
VR
V3
=
P3
P3
P2
P1
Where:
P1
P2
= Maximum pressure of accumulator when completely charged
P3
V1
= Nitrogen pre-charge pressure
V2
V3
= Volume of nitrogen at minimum pressure
VR
= Total usable fluid required including safety factor
= Minimum operating pressure of accumulator
= Volume of nitrogen at maximum pressure
= Total accumulator volume of (nitrogen and fluid)
Figure 21
System Pressure and Volume Diagram
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Therefore, for a 3000 system with 1000 psi pre-charge pressure,
VR
V3
=
P3
P3
P2
P1
53.07
=
=
1000
1000
1200
3000
106.14 gallons
Alternate quick calculation,
Table J.1
Surface BOP Quick Sizing Table
Accumulator
Pre-Charge
5000 psi
3000 psi
Sizing Factor
1500 psi
1000 psi
2.58
3.0
Multiply gallons to close all preventers by 3.0 for a 3000 psi BOP control system
with 1000 psi pre-charge:
= 35.38 gal x 3.0 =
c)
106.14 gallons
Determine the number of accumulator bottles required
Divide the total accumulator volume (nitrogen and fluid) by the nominal accumulator
capacity. The nominal accumulator capacity is the accumulator size in gallons, less
1 gallon to allow for bladder/float displacement.
Using 11-gallon accumulator bottles:
Total Accumulator Volume
Nominal Accumulator Capacity
=
106.14
10.00
Number of Eleven Gallon Bottles
=
10.61 or 11
Total Accumulator Volume
=
110 Gallons
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6.3
Alternate Size Calculations
Another method of sizing the accumulator capacity is as follows:
Take a 10-gallon nominal accumulator bottle and a pre-charge pressure of 1000
psi.
Let,
V
= Total volume of bottle (excluding volume occupied by the bladder)
Vx = Volume of nitrogen (N2) in the bottle at x psi.
Calculate Vx for pressures of 1500 psi and 3000 psi.
Solution Bottle #1 (see Figure J.22)
We know by definition that
V1000 psi
=
10 gallons of N2
and by using Boyles’ Law, we can calculate the values of Px at 1500 psi
and 3000 psi.
Solution Bottle #2 (see Figure J.22)
P1 V1
1500 psi (V1500)
V1500
=
=
=
P2 V2
1000 psi (10 gal)
6.67 gallons of N2
Solution Bottle #3 (see Figure J.22)
P1 V1
3000 psi (V3000)
V3000
=
=
=
P2 V2
1000 psi (10 gal)
3.33 gallons of N2
Thus, for a 3000 psi accumulator with 1000 psi pre-charge,
V1000
=
3V3000
This verifies the Sizing Factor of 3 shown in Table J.1.
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Figure J.22
Accumulator Volumes at Varying Pressures
1,000 psi
3.33
gals
6.67
gals
6.67
gals
3.33
gals
Using the fluid requirements from the previous calculation,
35.38 gallons to close all preventers
Calculate the number of bottles required to close this equipment and leave
1500 psi on the bottles.
Taking a 10-gallon (nominal) bottle from 3000 psi to 1500 psi renders us
6.67 gal – 3.33 gal = 3.34 gallons of usable fluid
Thus, we will require ....
35.38 gal
= 10.59 bottles
3.34 gal/bottle
.... to close this equipment.
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This value rounded up to the nearest full bottle,
equals (11) 10 gallon bottles
or 110 gallons accumulator capacity.
Check the requirement to provide sufficient accumulator capacity supplying
1.5 times the volume necessary to close all BOP equipment units with a
minimum pressure of 1200 psi (200 psi above pre-charge).
P1 V1
1200 psi (V1200)
V1200
=
=
=
P2 V2
3000 psi (3.33 gal)
8.33 gal
Useable Fluid
=
10 gal – 8.33 gal
=
1.67 gal
(3000 psi to 1200 psi)
We know that for a 10 gallon bottle, there is 5 gallons of usable fluid, (6.67
gal – 1.67 gal), when the pressure is reduced from 3000 psi to 1200 psi.
Total Gallons to Close All BOP Units
50% Safety Factor
Total Gallons of Usable Fluid Required (VR)
35.38
17.69
53.07
Thus, the number of 10 gallon bottles required will be
53.07 gal / 5 gal/bottle = 10.6 bottles
rounded up to (11) 10 gallon bottles
Therefore, both calculations for a 3000 psi accumulator (with 1000 psi precharge) show the same requirement stated in different manners.
• Have 1 times the fluid volume to close all BOP equipment with the
remaining bottle pressure of 1500 psi or greater.
• Have 1.5 times the fluid volume to close all BOP equipment with the
remaining bottle pressure of 1200 psi or greater.
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Surface BOP Quick Sizing Example
Preventer
Type
Manufacturer
Annular
Pipe & Blind Rams
Pipe & Blind Rams
HCR Valve
Hydril (GK)
Shaffer
Shaffer
McEvoy (E)
Size
Working
Pressure
13-5/8"
13-5/8"
13-5/8"
4-1/16"
10000 psi
10000 psi
10000 psi
10000 psi
Total Gallons to Close
Gallons
to Close
37.18
21.16
21.16
1.00 (open)
80.50
Will a 180 gallon 3,000 psi KOOMEY accumulator unit with (18) 11-gallon
accumulator bottles and 1000 psi pre-charge meet Saudi Aramco sizing criteria?
Volume Needed:
7.0
80.50 x 3.0 = 241.5 gals, or (25) 11-gallon bottles
Preventer Units
7.1
Annular Preventers
Introduction
When included in a particular BOP stack, the annular preventer is normally the first
preventer used to shut-in the well. Annulars can close and seal on almost anything in
the wellbore, and in some models, completely shut-off the open hole in emergency
situations.
With most annular preventers, closure is accomplished by applying hydraulic
pressure to raise a contractor piston. As the piston travels upwards, it displaces and
deforms a rubber-sealing element radially inward, eventually contacting and sealing
around the outside of pipe in the hole. Compression of the rubber throughout the
sealing area assures a seal against any shape.
Annular Preventers
§
§
§
§
§
Hydril ‘MSP’
Hydril ‘GK’
Hydril ‘GL’
Shaffer ‘Spherical’
Cameron Type ‘D’
Annular preventers with threaded caps are considered acceptable.
Note:
Current Revision:
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Never use pipe dope on the screwed-cap threads.
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7.1.1
Hydril ‘MSP’
The Hydril ‘MSP’ preventer is a low pressure (2,000 psi) annular preventer,
which is best suited for diverter applications. While the preventer can close
completely on an open hole, this is not recommended. In the closed position,
wellbore pressure acts upon the contractor piston to increase sealing
effectiveness. The screwed top of the model shown in Figure J.23 makes it
difficult and time consuming to change the sealing element, however, a
latched-top version is also available.
Figure J.23
Hydril ‘MSP’ Annular Preventer
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7.1.2
Hydril ‘GK’
The Hydril ‘GK’ preventer is a highly wellbore pressure assisted annular
preventer which is designed for land applications. (The 15M psi ‘GK’ is not
wellbore pressure assisted). This preventer can close on an open hole in an
emergency, but damage to the sealing element may result and element life
will be reduced. In the closed position, element wear can be determined
through an access port located in the top of the preventer. The lifting eyes
shown in Figure J.24 should be used to lift the annular preventer only, never
the entire stack.
Figure J.24
Hydril ‘GK’ Annular Preventer
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7.1.3
Hydril ‘GL’
The Hydril ‘GL’ preventer is designed primarily for subsea use but also finds
application in the deeper land operations. The outstanding feature of the ‘GL’
preventer is its secondary closing chamber, which can be used to
compensate for marine riser hydrostatic pressure effects in deep water. The
secondary chamber also allows additional closing force to be placed on the
contractor piston, which may be necessary in some instances since this
preventer is only slightly wellbore pressure assisted. The secondary
chamber port should never be plugged; either connect the port to the
accumulator or leave it open. The ‘GL’ preventer shown in Figure J.25 has a
latched head for easier sealing element change.
Figure J.25
Hydril ’GL’ Annular Preventer
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7.1.4
Shaffer ‘Spherical’ Preventer
The ‘Spherical’ preventer manufactured by Shaffer derives its name from the
semi-circular profile on the inside of the cover. Closing pressure moves the
contractor piston upwards, and deforms the sealing element upwards and
radially inwards along the profile until a seal is made against the pipe in the
hole. The ‘Spherical’ preventer can also close on open hole but this is not
recommended. For Shaffer preventers greater than 13-3/8”, and closed on
pipe greater than 7-5/8”, the closing pressure should be reduced below 1,500
psi to prevent pipe deformation. Charts, which specify the proper closing
pressure, can be obtained from all annular preventer manufacturers. The
‘Spherical’ preventer shown in Figure J.26 is only slightly wellbore pressure
assisted and has no provisions for measuring element wear without removing
the cover.
Figure J.26
Shaffer ‘Spherical’ Annular Preventer
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7.1.5
Cameron Model ‘D’ Annular Preventer
The Cameron Model ‘D’ preventer uses two elastomer elements consisting of
a donut and a rubber packer. When closing pressure is applied, the
contractor piston moves upwards against the donut, which deforms inward
onto the outside of the rubber packer. This action displaces the rubber
packer radially inward to produce the seal. The packer is internally steel
reinforced to help prevent excessive deformation of the packer under
pressure. Since the Model ‘D’ preventer is not wellbore pressure assisted,
closing pressure above 1,500 psi may be needed in extreme circumstances
to affect a seal. Most sizes of the Model ‘D’ preventer use less closing fluid
than the Hydril and Shaffer equivalents, and have a smaller overall height.
The Cameron Model ‘D’ annular preventer is shown in Figure J.27.
Figure J.27
Cameron Model ‘D’ Annular Preventer
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7.2
Sealing Elements
All preventer manufacturers provide sealing elements of different composition, which
are designed for use in specific wellbore environments. Tables J.2 and J.3 list some
of these types of sealing elements for annulars.
Table J.2
Hydril Sealing Elements
Packing
Type
Color
Code
Natural Rubber
Black
R
Water-base mud,
-300 to 2250 F.
Synthetic
(or Nitrile)
Red
S
Oil-base mud with aniline
points between 200 and
1900 F, and H2S service.
Neoprene
Green
N
Oil-base mud with
operating temperature
between – 300 and 1700 F.
Table J.3
Letter
Code
Recommended Usage
Shaffer Sealing Elements
Packing
Color
Letter
Recommended Usage
Type
Code
Code
__________________________________________________________________
Natural Rubber
Red
1 or 2
Low temperature
operations in waterbase mud.
Buna (Nitrile)
Blue
5 or 6
Oil and water-base
mud. H2S in oil-base
mud.
Neoprene
Black
3 or 4
H2S in water-base
mud.
Note:
Current Revision:
Previous Revision:
Currently the temperature rating of annular sealing elements is approximately
0
180 F for Cameron, Hydril, and Shaffer.
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7.3
Stripping With Annular Preventer
Annular preventers will allow for stripping pipe because they have the ability to
maintain a seal while passing tool joints and have a better abrasion resistance than
pipe ram preventers.
Special attention should be given to the annular preventer during the stripping
operations. The accumulator pressure regulator will maintain constant closing
pressure. The response of most regulators is slow and requires that the tool joints be
moved through the preventer slowly in order that the regulator be given time to react,
thus avoiding damage and excess wear to the packing element.
The sealing element can be changed without removing the drillpipe. When it
becomes necessary to change the sealing element, the rams below the annular
preventer should be closed and locked. The top of the annular preventer is removed
and the rubber-sealing element lifted out. This element is then cut between the metal
ribs, the rubber parted, and then the old split rubber element is pulled from around
the drillpipe. The new rubber-sealing element is cut (never sawed) between the metal
rib reinforcements and the new element installed in a method reversed from the
removal sequence. All replacement elements must be supplied by the original
equipment manufacturer (OEM).
Note:
7.4
Some Cameron sealing elements cannot be cut in this manner.
Ram Type Preventers
Acceptable units are:
§
§
§
§
Hydril Type ‘V’ Ram Preventer
Shaffer Type ‘LWS’ Ram Preventer
Shaffer Type ‘SL’ Ram Preventer
Cameron Type ‘U’ Ram Preventer
7.4.1
Hydril Type ‘V’ Ram Preventer
The Hydril Type ‘V’ ram preventer is designed for land applications and is
available in a range of working pressures from 3M to 15M psi. The Hydril ram
preventer can be equipped with automatic ‘multi-position’ locks or manual
locks, which can lock the preventer in the closed position. The bonnet doors
swing open on hinges to gain access to the cavity of the preventer and to
change the ram blocks. Hydril ram blocks are loaded from the top onto the
operating rod. A Hydril Type ‘V’ single ram preventer is shown in Figure J.28.
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Figure J.28
Hydril Type ‘V’ Ram Preventer
7.4.2
Shaffer Type ‘LWS’ Ram Preventer
The Shaffer ‘LWS’ (Light Weight Steel”) preventer is designed for land
applications and is available with working pressures ranging from 2,000 to
10,000 psi. Like the Hydril preventer, the bonnet doors on all Shaffer
preventers swing open to gain access to the rams. The ‘LWS’ have a selffeeding action. This preventer can only be locked manually. A Shaffer ‘LWS’
ram single preventer is shown in Figure J.29.
Figure J.29
Shaffer Type ‘LWS’ Ram Preventer
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7.4.3
Shaffer Type ‘SL’ Ram Preventer
The Shaffer Type ‘SL’ is a ram preventer which can be fitted with an
automatic locking provision called ‘Posi-Lock’ (acceptable locking device).
The ‘SL’ preventers are trimmed for H2S service and special rams are
available which can be used to hang-off the drillpipe. The Shaffer hydraulic
system is routed through the door hinges and into the operating cylinder.
Shaffer preventers (and all hinged door preventers) should never be
“pumped open” by applying closing pressure, as this will almost surely
damage the operating rod and the foot. A Shaffer Type ‘SL’ triple ram
preventer is shown in Figure J.30.
Figure J.30
Shaffer Type ‘SL’ Ram Preventer
7.4.4
Cameron Type ‘U’ Ram Preventer
The Cameron Type ‘U’ preventer is a wellbore pressure assisted ram
preventer suitable for surface or subsea installations. All Type ‘U’ preventers
manufactured since 1979 are equipped for H2S service. The outstanding
feature of the Type ‘U’ preventer is its ability to “pump open” the bonnet
doors. After removing four bonnet bolts, closing pressure can be applied.
This will open the bonnets for easy top-load ram changing. A Cameron Type
‘U’ single ram preventer is shown in Figure J.31.
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Figure J.31
Cameron Type ‘U’ Ram Preventer
7.5
Ram Construction
7.5.1
Hydril Rams
Hydril rams are constructed of a front packer and an upper seal, which are
attached to a solid steel ram block. The packer or the seal can be replaced
independently of the other. Hydril rams also have a replaceable seal installed
in the upper ram cavity, which should be checked if the preventer still leaks
after ram seal replacement. The ram block is installed in the preventer by
sliding down over a foot attached to the end of the operating rod. The front
packers of opposing rams make contact upon closure and the upper seals
prevent pressure from exiting about the rams. Various Hydril rams are
shown in Figure J.32.
Figure J.32
Hydril Rams
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7.5.2
Cameron Rams
Cameron rams consist of a front packer element and an upper seal, which
are installed onto a single solid steel ram block. Cameron rams have a “selffeeding” feature, which allows additional elastomer material to be extruded as
wear is experienced. This is accomplished by bonding two steel plates to the
upper and lower surface of the ram-packing element. When the preventer is
closed, the steel plates make contact first which forces them into an area
inside the ram block which is normally occupied by the elastomer material.
This movement extrudes the elastomer material towards the center of the
preventer, thus producing a seal. The Cameron ram construction is shown in
Figure J.33.
Figure J.33
Cameron Rams
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7.5.3
Shaffer Rams
Shaffer rams are constructed of a single elastomer seal installed between a
steel ram block and a steel ram holder. The elastomer seal is attached to the
ram block with two retaining screws, and this assembly is then secured to the
ram holder with two large retracting screws. Shaffer rams are loaded from
the side onto the operating rod. The Shaffer ram construction is shown in
Figure J.34.
Figure J.34
Shaffer Rams
7.6
Variable Bore Rams
Pipe rams are designed to close on one size of pipe only. All manufacturers of ram
preventers offer variable bore rams, which can close and seal on a range of pipe
diameters. These rams can be especially useful when a tapered string is in use or
when sub-base space limitations restrict the addition of another ram preventer. Also,
since the tube of aluminium drillpipe has a larger diameter near the tool joints than at
the center, an effective seal cannot always be assured when regular pipe rams are in
use. Variable bore rams (VBR) may be the best solution for this problem.
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Variable bore rams have limited hang-off potential, depending on the size of the pipe
on which they are sealing. Most variable bore rams are constructed in a similar
fashion with the key element being a feed-able rubber packer. A Cameron VBR is
shown in Figure J.35.
Figure J.35
Variable Bore Rams
Variable bore rams are optional for tapered drill string applications on Class ‘A’
stacks, but must meet the minimum acceptable limits for H2S and temperature.
The minimum acceptable ratings for H2S and temperature for VBR are,
3000 psi stack
5.0% H2S and 250°F
5000 psi stack
10.0% H2S and 250°F
10000 psi stack
20.0% H2S and 250°F
The Cameron Extended Range High Temperature VBR-II Packer (3-1/2” to 5-7/8”
pipe sizes) for the Cameron 13-5/8” U Type blowout preventer is acceptable for 3M
and 5M applications. The VBR was successfully tested to 250 degrees F with a
CAMLAST elastomer rated for 20% H2S. See Section S for details. At this point in
time, this the only VBR approved for use in Saudi Aramco operations.
The VBR should not be used in the master ram position.
7.7
Shear Blind Rams
Shear blind rams (SBR) shear the pipe in the hole, bending the lower section of
sheared pipe to allow the rams to close and seal. SBR can be used as blind rams
during normal operations. SBR are available for H2S service with a blade material of
hardened alloy service. Tandem boosters and bonnets large bore shear bonnets will
be required for cutting 5” or 5-1/2” drillpipe.
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An important point to remember about SBR is that they require high operating
pressure (approx. 2800 psi) to shear pipe and affect a seal. This depends on the size
and weight of pipe in use, size of preventer, and model of ram itself. Consideration
should be given to dedicating accumulator fluid to the SBR independent of the
remainder of the accumulator reserve.
As of October 2000, Saudi Aramco has approved the conditional use SBR.
SBR are required on,
q
q
q
q
q
Class ‘A’ 10000 psi stacks (All Deep Gas Expl./Dev. Wells)
Offshore Class ‘A’ 5000 psi stacks (All Offshore Wells)
Onshore Class ‘A’ 5000 psi stacks (Expl./Dev. Wells >10 % H2S)
Gas Cap Wells (Either 3000 or 5000 Class ‘A’ Stacks)
Populated Wells (All Wells in Populated Areas)
Cameron and Shaffer are acceptable manufacturers for SBR. Both manufacturers
have met the Saudi Aramco requirements for pressure applications to 10M psi.
The minimum acceptable ratings for H2S and temperature for SBR are,
3000 psi stack
5000 psi stack
10000 psi stack
5.0% H2S and 250°F
10.0% H2S and 250°F
20.0% H2S and 300°F
The Cameron H2S SBR construction is shown in Figure J.36.
Figure J.36
Cameron Shear Blind Rams
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7.8
Secondary Seals
It is very important that wellbore pressure be isolated from the operating cylinder on
all ram preventers. Normally a primary lip seal provides this function. The lip seal is
installed in the bonnet through which the operating rod passes. If fluid pressure
should bypass the primary seal and enter the operating cylinder, it is possible that the
ram preventer could be forced open. To prevent this occurrence, a series of
secondary seals are provided which may include:
§
§
§
8.0
Back-up O-rings
Plastic packing injection seal
Vent to the atmosphere (weep hole)
Accessory Blowout Prevention Equipment
8.1
Pit Volume Totalizers
Various devices will indicate gain or loss of drilling fluids from the mud pits. The
volumes should be integrated or totaled from all pits to read out on a chart (or charts)
near the driller’s position. Warning devices (horns, lights) are necessary to alert the
crew to a change in pit volume. Several of these charts and warning devices should
be installed in places such as the mud logging unit, the Toolpusher’s office, or the
Drilling Representative’s office. These should be installed on all rigs drilling in areas
with hazardous or uncertain formation pressures, and kept on at all times, even when
out of the hole, changing bits, or logging. These devices may employ either air
pressure or electric signals to monitor the pit volume. A typical pit volume totalizer
system is shown in Figure J.37.
Figure J.37
Pit Volume Totalizer
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8.2
Mud Flow Indicators
Flowline monitoring devices detect early changes in the flow pattern of the drilling
fluid system. Installed near the wellhead, they “sense” and respond before the pit
volume devices do, thus giving the driller early warning of a mud return change, so
that proper action can be taken immediately. These devices should be installed and
kept operating continuously, even when out of the hole. There are two popular types
of Flow Indicators on the market today; electrical differential and flow sensor type.
The differential flow meter measures the difference between the fluid input and
outflow for the well and records the difference on a strip chart. The flow sensor type
uses a paddle installed in the flow line, which is deflected by increasing mud returns.
8.3
Mud Gas Separators
8.3.1
Degassers
Degassers remove gas entrained in the drilling fluid during normal drilling
operations, preventing re-circulation of gas-cut mud. Circulating gas-cut mud
into the hole can lead to reduction of the bottom-hole hydrostatic pressure
and possibly a well kick. Compensating for entrained gas with weighting
material unnecessarily increases costs. The degasser should be operated at
least daily. Degassers also serve as a mechanical oxygen scavenger,
extending the life of the drill string.
Degassers are available in both atmospheric and vacuum models.
Atmospheric models occupy less space and are generally easier to maintain,
but the vacuum types are generally more efficient. Vacuum degassers must
have a 1” vent line, with check valve, tied into the gas buster outlet.
8.3.2
Gas Busters
Gas busters (poor boy degassers) generally are the first line of defense from
gas around the location. The gas buster is an open top vessel normally
connected to the end of the choke manifold. Most gas busters are
constructed from a length of large diameter pipe with a series of interior
baffles to cause a rolling/spreading of the drilling fluid. A siphon arrangement
at the bottom permits mud to flow to the shale shaker while maintaining a
fluid head to hold the gas in the upper part of the vessel. The gas vent pipe at
the top shall be large enough to permit gas to be vented at a safe distance
away from the rig, without much back-pressure. The vent line(s) shall consist
of 8” flanged or clamped steel line (minimum of 240’ in length, from the gas
buster) of the same pressure integrity (or greater) of the gas buster. Vent
line(s) shall terminate in a flare pit, positioned away from the reserve/waste
pits to prevent ignition of any waste hydrocarbons while circulating gas from
the wellbore.
Gas busters are more efficient with clear fluids. Low viscosity fluids allow the
entrained gas to break out easily under the atmospheric pressure of the
vessel. Gas separation in viscous fluids is less; consequently, the flow rate to
the gas buster may have to be reduced in order to handle larger amounts of
gas. Gas blow-by is a term to describe over-loading the gas buster as
pressure builds inside, displacing fluid in the mud leg and allowing the gas to
enter the pit area.
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Gas busters should be cleaned-out periodically. Never circulate cement
returns through a gas buster. Gas busters have a tendency to shake/rattle
when they are circulated through and should always be securely anchored.
Gas buster designs for ‘deep gas rigs’ and ‘oil development rigs’ are shown in
Figure J.38 and J.39, respectively. The minimum internal capacity for existing
gas busters is 35 barrels deep gas rigs and 17.5 barrels for oil rigs.
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All gas busters shall be built in compliance to ASME Boiler and Pressure
Vessel Code, Section VIII, Division I, with all materials meeting requirements
of NACE Standard MR-01-75 (Latest Revision). All welding on the vessel
shall meet ASME requirements. New gas busters shall be hydrostatically
tested to 190 psi to give a maximum working pressure of 150 psi, as per
ASME.
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There should be a by-pass line upstream of the separator directly to the flare
line and a valve on the separator inlet line to protect the separator from high
pressure. The mud discharge line from the separator must have a vacuum
breaker stacked vent line if the discharge line outlet is lower than the bottom
of the separator. This is to prevent siphoning gas from the separator to the
mud pits. The vacuum breaker stack must be as high as the separator.
8.4
Full-Opening Safety Valve
Safe operations require that a Full-Opening Safety Valve fit each size of drill pipe/ drill
collar in use and be kept in the open position on the rig floor (including a closing
/opening wrench). Then, should the well begin to flow when the kelly is detached,
such as during trips or when making connections, the correct size can be stabbed
into the drill pipe tool joint and made up. It is good practice to install a valve as a
precaution when the drill pipe is left in the slips during rig repair or any other time that
the kelly is not picked up. Care should be taken that all valves have the proper
threads and will go through the BOP stack and casing, so that they could be stripped
into the hole below a back-pressure valve (Inside BOP). A safety valve and
appropriate cross-over are also required when running casing. Note that the term ‘full
opening’ does not mean that the ID of the valve is the same as the pipe, but rather
that the bore through the valve is not restricted. A drill string Full-Opening Safety
Valve is shown in Figure J.40.
Figure J.40
Full-Opening Safety Valve
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8.5
Inside BOP
The Inside BOP is a back-pressure type valve (or float valve) that allows stripping or
running drill pipe into the hole without mud flow upward through the valve. It can be
stabbed and made up on the drill pipe only at very low flow rates. The best method is
to stab and close the Full-Opening Safety Valve first, then install the Inside BOP if the
decision is made to go back into the hole. The ‘dart-type’ Inside BOP is one of the
more widely used tools. The dart is used to hold the tool open, making it possible to
install the tool while mud is flowing from the well. Release of the dart permits the
valve to close. The upper sub is then removed and additional drillpipe may be added
as desired. The ‘dart type’ Inside BOP is shown in Figure J.41.
Figure J.41
Inside BOP (Dart Type)
Also available is a ‘drop-in’ Inside BOP, which can be pumped down the drillpipe.
This tool lands and seats in a special sub installed in the bottom-hole assembly.
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8.6
Drilling Chokes
The prime function of a drilling choke is to create a back-pressure on the well, which
will increase bottom-hole pressure sufficiently to control formation flow while the well
is circulated. Chokes are available in either positive or adjustable styles for flow
control, with a variety of sizes and pressure ranges. An adjustable choke can better
regulate pressure than a positive choke, which has a fixed opening.
Hydraulic chokes are more easily adjusted and permit accurate regulation of choke
pressure. An important feature of most hydraulic chokes is that the choke itself can
be replaced in the manifold, but is controlled remotely from a panel, which also
displays the casing and drillpipe pressures. One such remote hydraulic choke is
shown in Figure J.42.
Figure J.42
Cameron Drilling Choke
8.7
Trip Tank
A circulating tank will be used on all rigs while tripping out or back in the hole. The trip
tank shall have two (2) 60 barrel compartments, complete with two (2) independent
measuring devices (a mechanical float-operated pit level indicator, graduated in
inches, and an electro-mechanical device). Calculated versus actual volumes shall be
monitored and recorded in a log book.
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The log book will be used on each well so that the following data can be recorded:
1)
2)
3)
4)
Volume and weight of slug
Number of strokes that the slug is pumped
Time for slug to stabilize and flow to stop in annulus
Amount of mud to fill hole per *five stands…...if the volume of mud
used to fill the hole is not correct for any interval, stop pulling and
determine the reason the hole is not taking mud properly
*
5 stands for DP, 2 stands for HWDP, and every stand for DC
5)
6)
Total volume of mud per trip to fill hole (calculated and measured)
Leave drill pipe wiper rubbers off pipe for first five stands to observe
hole
A circulating trip tank is shown in Figure J.43. For details on tripping procedures, see
Section C of this manual.
Figure J.46
Figure J.43
Circulating Trip Tank
Circulating Trip Tank
Note:
5 stands of 5” 19.5 /ft/ drill pipe pulled from 9-5/8” 53.5# /ft. casing will lower the
fluid level 56’, if there is no loss/gain from the hole and the float is working properly.
For example:
.007645 bbl/ft. displacement in .070765 bbl/ft capacity
(0.070765 – 0.007645) / 0.007645 = 8.26’ of drill pipe pulled per foot of fluid
drop in casing and inside drillpipe
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8.8
Stroke Counter
The Stroke Counter offers the Driller an alternative means of measuring fluid volume
used to fill the hole on trips. In order to use the stroke counter properly, the Driller
must know two things. First, the Driller must know the fluid displacement for the
particular pipe and hole size being used. Second, the amount of volume discharged
per stroke of the pump in operation must be known. This knowledge gives the Driller
the ability to check for correct volumes required for fill-up while tripping.
Using the stroke counter to measure hole fill-up is less accurate than using a trip
tank, and is therefore not recommended. Also, there is a tendency to use the kill line
for hole filling purposes when the rig pumps and stroke counters are used. This
action is never recommended. The kill line is an emergency piece of equipment
and should not be used for routing hole fill-up during trips.
Stroke counters also provide a means of correctly displacing special fluids or lost
circulation pills. Finally, a stroke counter is especially useful to determine pumped
volumes while executing well control procedures.
8.9
Gas Detectors
These devices usually found in mud logging units, are useful in detecting abnormal
pressure sections as well as shows of hydrocarbons. Rig Supervisors should monitor
the trip gas, connection gas, and background gas for any significant change. The
presence of gas in the mud can be one of the more useful indicators of abnormal
pressure. Gas Detectors can sometimes be misleading however, and the important
things to look for are the relative trends and magnitudes, rather than the individual
number of gas units reported.
8.10 Mud-Logging Units
Mud logging companies furnish personnel and equipment to analyze well cuttings,
mud and cuttings gas, drilling rate vs. formation, and gas type. They also provided
detailed mud analysis and predict and analyze hydrocarbon shows. These useful
units, personnel, and equipment should be fully utilized, for safety and economy.
8.11 Mud Weight Recorders
These devices periodically measure and record the mud weight. The output is useful
for detecting light or heavy streaks in the mud due to ‘slugging’ or other causes. The
Rig Supervisor should not depend wholly on these devices, and the mud personnel
should check the mud weight routinely as well. The accuracy of these devices should
be verified by frequent manual weight checks, particularly with high mud weights.
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8.12 Drilling Rate Recorders
These devices are very useful as correlation tools, particularly if electric logs are
available from other wells in the area. The records can be used to detect and
correlate formation tops and types, as well as in selecting bits and estimating their
useful lives. A sudden increase in penetration rate can be the first signs of a well kick.
8.13 Bowl Protectors
Bowl protectors (or wear bushings) protect the hanger bowl and the smallest ID of a
casing or tubing head spool during extended periods of drilling. In most nipple-up
procedures, the bore of the BOP, and its corresponding flange size, are always
greater than the bore of the head or spool immediately below the stack.
Consequently, the most prolonged contact the drill pipe, tools or tubing has with the
surface equipment is at this point. This is aggravated if the derrick is not positioned
exactly over the hole, and the pipe rides off-center.
Bowl protectors shall be used during all drilling operations on wells requiring
more than 21 days of duration. For the latest specifications on Bowl Protectors,
contact the manufacturer of the wellhead equipment being used.
8.14 Drillpipe Float Valves
The Drillpipe Float Valve provides an instantaneous shut-off against pressures below
the bit when the well is shut-in and prevents back-flow up through the drill string. In
essence a one-way check valve, the drillpipe float allows full flow through the valve
under normal circulating conditions. Allowing formation fluids to flow into the drill
string can be especially hazardous because the drillpipe can become evacuated very
quickly. Also, if the drill string is contaminated by formation fluid when the well kicks,
it will be impossible to accurately calculate the mud weight necessary to kill the well.
Saudi Aramco’s policy is to run a Drillpipe Float Valve at all times (except when
planned operations preclude running a float: as testing, treating, or squeezing).
The drillpipe float shall be positioned directly above the bit.
Another advantage of the float valve is that it prevents cuttings from entering the drill
string during a connection, which could plug the bit.
8.15 Valve Removal Plugs
The valve removal plug (VR plug) is a threaded one-way check valve that can be
installed through an outlet valve on a casing head, casing spool, or tubing spool into a
female thread in the outlet. This isolates the valve from any pressure and allows for
removal of the outlet valve for its repair or replacement. Once the valve has been
repaired or replaced, it can be re-installed and the VR Plug is removed.
VR plugs shall be removed from the wellhead in order to have access to the
annulus. This should be confirmed prior to nippling-up the wellhead.
If a VR plug is removed from the blind flange side of the wellhead prior to
installation, it must be replaced prior to the rig move/well completion. Under no
circumstances should a VR plug be left in a wellhead outlet that has a gate valve
installed.
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Note:
VR plugs are intended for short-term use only, and should not be considered as
a long-term replacement for wellhead valves.
Valve removal plugs are not required on side outlets of the ram preventers. Figures
J.44 and J.45 illustrate examples of a VR Plug and Lubricator.
Figure J.44
Valve Removal Plug
Figure J.45
Lubricator
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SECTION J - EQUIPMENT REQUIREMENTS
8.16 Back Pressure Valves
8.16.1 One-Way Check Valves
A Back Pressure Valve, or tubing plug, is usually a One-Way Check Valve
that is installed in a specially machined profile in the tubing hanger or plug
bushing. The One-Way Check Valve is designed to prevent the flow of fluids
and gases through the hanger, but still allows the pumping of fluid into the
tubing string. They are installed in the well to remove the production tree and
allow the initial nipple-up of the BOP stack, to install the tree while nippling
down the BOP stack, and while heavy lifts are being made over the wellhead.
The One-Way Check Valve can be installed or removed with either the tree
or BOP stack nippled up on the tubing head. They can also be installed with
or without pressure on the tubing. Installation of the One-Way Check Valve
through the tree with pressure on the well requires the use of a lubricator.
Wellhead manufacturers have various designs for Back Pressure Valves
depending on the size and make of the hanger and wellhead. Only
specifically trained personnel should perform the installation and removal of
Back Pressure Valves.
A Back Pressure Valve (one-way check valve) shall be set before rigdown or rig-up operations. Figure J.46 shows one model of a One-Way
Check Valve.
Figure J.46
One-Way Check Valve
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SECTION J - EQUIPMENT REQUIREMENTS
8.16.2 Two-Way Check Valves
A Two-Way Check Valve (TWCV) is similar to a Back Pressure Valve but is
specifically designed to plug the tubing in order to pressure test the tree or
BOP stack. The TWCV uses a two-way plunger that will hold tubing pressure
from below or moves down and seals test pressure from above. Tubing
pressure can be bled down by inserting the retrieving/running tool, which will
offset the plunger and allow pressure to by-pass. The TWCV is not to be
used for nipple-up or nipple-down operations. When performing these
operations a conventional BPV shall be installed. When nipple down, nipple
up, operations are complete the BPV shall be removed and the TWCV
installed and the equipment can be tested.
Figure J.47 shows one model of a Two-Way Check Valve.
Figure J.47
Two-Way Check Valve
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SECTION J - EQUIPMENT REQUIREMENTS
8.17 Coflex Hose
Coflex flexible steel hose (or a combination of flexible hose and hard line) may be
used for kill or emergency kill line on 3M, 5M, and 10M psi applications and choke
line on 3M and 5M psi applications, if the following requirements are satisfied,
§
§
§
§
§
§
§
§
Coflon lined and monogrammed to API Specification 16C. Hoses
currently in the field, not monogrammed, may continue to be used for the
remaining service life. However as hoses are replaced, they must be
monogrammed.
All other components of the hose and end-fittings in possible contact with
wellbore fluids meet Sour Service NACE STANDARD MR-01-75 (Latest
Revision)
All end-fittings shall be flanged, welded, integral, or hubbed connections
(which are molded to the hose and monogrammed to API Specification 6A)
Re-certification by OEM every 3 years
Certified for drilling service (no weep holes)
Same working pressure (or greater) as the BOP stack
Properly supported/anchored, where necessary, when used as choke line
Number of connections minimized when flexible hose is used in
combination with hard line
Coflex flexible steel hose may be used for flowline on 10,000 psi well testing
applications, if the following requirements are satisfied,
§
§
§
Same as above requirements
Only if expected application has CO2 + H2S < 30%
Certified for flowline service, complete with weep holes
8.18 Weco Connections
In high-pressure applications, especially with gas, the Weco hammer union lip-seal
elastomer will most likely experience the typical ‘explosive decompression’
phenomena. The gas will migrate into the elastomer and deform/damage the lip-seal.
The likelihood of a leak is even greater at higher temperatures and when the gas
contains a high concentration of CO2. This problem has been encountered several
times on deep gas wells. A metal-to-metal seal (API Flanged or Gray-Lock
connection) will prevent this unwanted phenomena.
Integral or welded Figure 1502 connections are acceptable downstream of the buffer
tank on the choke manifold for all land applications, provided they are monogrammed
to API Specification 6A. Weco connections are not acceptable on the well test line
(downstream of the choke manifold) for offshore operations.
Figure 602 connections are not allowed on any drilling or workover operation.
8.19 Chiksans
Chiksans are sections of pipe with hammer unions and two swivels in each joint. The
primary use of chiksans is in high pressure pumping and cementing operations.
Washouts can develop in the packing element in the swivel during long-term use
applications. Chiksan-type joints are not acceptable as kill line, emergency kill
line or choke line.
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SECTION K - MAINTENANCE AND TESTING REQUIREMENTS
Table of Contents
1.0
2.0
Maintenance of Blowout Prevention Equipment ........................ K - 2
Testing of Blowout Prevention Equipment ................................... K - 4
2.1
2.2
2.3
2.4
2.5
2.6
2.7
3.0
4.0
5.0
6.0
General Pressure Testing Requirements ....................................... K - 4
Specific Requirements for Class ‘A’ 10,000 psi BOP Stack.......... K - 6
Specific Requirements for Class ‘A’ 5,000 psi BOP Stack............ K - 7
Specific Requirements for Class ‘A’ 3,000 psi BOP Stack............ K - 8
Specific Requirements for Class ‘B’ 3,000 psi BOP Stack............ K - 9
Specific Requirements for Class ‘C’ or ‘II’ Workover Stack ....... K - 10
Specific Requirements for Class ‘D’ Diverter Stack .................... K - 11
Pressure Testing Procedure ............................................................. K - 11
3.1
Function Testing and Flow Testing .............................................. K - 12
3.2
Fill the Stack with Water................................................................. K - 12
3.3
Casing Test (if required) ................................................................ K - 12
3.4
Blind Rams (if required) ................................................................. K - 13
3.5
Annular Preventer .......................................................................... K - 14
3.6
Upper Pipe Rams ............................................................................ K - 15
3.7
Positive Sealing Chokes................................................................. K - 16
3.8
Choke Manifold (continued)........................................................... K - 17
3.9
Choke Manifold (continued)........................................................... K - 18
3.10
Choke Manifold (continued)........................................................... K - 19
3.11
Choke Line HCR Valve.................................................................... K - 20
3.12
Choke and Kill Line Manual Valves............................................... K - 21
3.13
Master Pipe Rams ........................................................................... K - 22
3.14
Small Pipe Rams ............................................................................. K - 23
3.15
Kelly, Surface Circulating Equipment, and Safety Valves .......... K - 24
3.16
Wellhead Valves .............................................................................. K - 24
Accumulator Testing ............................................................................ K - 25
Hang-Off Limitations while Testing ............................................... K - 28
Test Pressure Requirements for Casing Rams ........................ K - 28
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SECTION K - MAINTENANCE AND TESTING REQUIREMENTS
1.0
Maintenance of Blowout Prevention Equipment
Blowout prevention equipment is emergency equipment and must be maintained in its
proper working condition at all times. The Drilling Foreman can best insure that Saudi
Aramco is provided with equipment that performs to our specifications by being an active
participant in the maintenance requirements of the BOP equipment.
rd
Changes in this 3 Edition of the Saudi Aramco Well Control Manual are indicated by a
bold vertical line in the right margin, opposite the revision.
Several maintenance items, which the Drilling Foreman should verify on a daily basis (by
reviewing the Driller’s pre-tour checklist or by personal observation), are listed below:
1) Examine the fluid level in the accumulator. Make sure it is at the proper level and
proper pressures are indicated on the accumulator, manifold, and annular pressure
gauges.
2) Verify the control lines are run to prevent damage by trucks or dropped tools.
3) Confirm the preventer controls are either in their proper opened or closed position
(not neutral) and that leaks are not evident.
4) Assure the preventer stack is well guyed so that vibrations are minimized while
drilling.
5) All preventers must be operated at least each time a trip is made. Alternate trip
closures between the remote stations and the accumulator. The annular preventer
does not have to be operated to complete shut-off. DO NOT close the pipe rams on
open hole.
6) The emergency kill line and choke/kill lines shall be washed out as required to
prevent mud solids settling. Clear water should be used to flush and fill the lines
(except in extremely cold weather, where diesel or glycol should be used).
Other maintenance requirements are as follows:
7) DO NOT circulate green cement through the preventer stack or choke manifold.
Always thoroughly flush with water any piece of blowout prevention equipment, which
has come in contact with green cement and verify the equipment is clear upon the
next nipple-up.
8) Make sure the rig is centered over the well to reduce drill string and BOP equipment
contact and abrasion.
9) DO NOT use the kill line as a fill-up line during trips.
10) If possible, install the ram preventers so that the ram doors are positioned above and
shield the valves installed on the casing head below.
11) All rigs shall maintain a logbook of BOP schematics detailing the components
installed in each ram cavity. The logbooks shall contain the part number, description
and installation date of ram blocks, top seals, ram or annular packers and
bonnet/door seals. To be witnessed and co-signed by the Contract Toolpusher and
Saudi Aramco Drilling Foreman (or Liaisonman).
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12) Only OEM parts are acceptable when repairing or redressing the BOPE. Furthermore,
only an approved OEM high-temperature lubricant is acceptable for valve
maintenance.
13) At least one spare set of ram seals (top seals and packer rams) for all rams including
packer rams for each size of tubing or drill pipe, as well as bonnet seals, must be on
the rig site.
14) Ram blocks shall not be dressed until ready to use.
15) All BOP rubber goods shall be kept in a cool place and remain in the original
packaging with expiration dates.
16) Preventer assemblies shall be dismantled between wells to inspect for internal
corrosion and erosion and to check flange bolts.
17) Manufacturer‘s installation, operation, and maintenance (IOM) manuals should be
available on the rig for all BOP equipment installed on the rig.
18) New ring gaskets shall be installed on each nipple-up at each connection, which has
been parted. Ring gaskets should never be reused.
19) Studs and nuts should be checked for proper size and grade. Using the appropriate
lubricant, torque should be applied in a criss-cross manner to the flange studs. All
bolts should then be re-checked for the proper torque as prescribed in API
Specification 6A.
20) Field welding shall not be performed on any BOP equipment. All repairs to BOP
equipment must be performed at an OEM facility.
21) A Maintenance Log for each piece of BOP equipment shall be maintained. This log
shall include, at a minimum, records of all service and inspections performed on the
BOP. The log will travel with the Contractor-owned equipment and shall be kept in the
BOP shop for Saudi Aramco-owned equipment.
22) All newly manufactured BOP equipment shall be API monogrammed.
23) A full OEM Certification of the BOP, choke manifold (including chokes), and all
related equipment (i.e. closing unit, kill line valves, choke line valves, coflex hoses,
etc.) shall be required at contract start-up and contract renewal with a maximum
period of 3 years between OEM re-certification.
24) The BOP should be opened, cleaned, and visually inspected after every nipple down,
including servicing the manual tie-down screws.
25) Elastomers exposed to well fluids shall be changed at a maximum of every 12
months, unless visual inspection requires changing earlier. However, it is acceptable
to use seal elements for 30” annulars up to 36 months (provided inspections are
satisfactory, properly documented, and the expiration date of the elastomer is not
exceeded). Seal elements for all other annulars (21-3/4” and smaller) shall be
replaced no later than every 12 months, as per policy.
26) All BOP stacks and accumulators must have documentation of last inspection and
certification.
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SECTION K - MAINTENANCE AND TESTING REQUIREMENTS
2.0
Testing of Blowout Prevention Equipment
The objective of BOP equipment testing is to eliminate all leaks and to determine that the
equipment will perform under unplanned pressure conditions. This is accomplished by
verifying:
Ø
Ø
Ø
2.1
Specific functions are operationally ready
Pressure integrity of installed BOP equipment
Compatibility between control system and BOP equipment
General Pressure Testing Requirements
All BOP equipment pressure tests shall be conducted in accordance with the
following guidelines.
1) Rig crews must be alerted when pressure test operations are underway. Only
necessary personnel shall remain in the test area.
2) All tests shall be performed using clear water.
3) The low-pressure test of each piece of BOP equipment shall be conducted at a
pressure of 300 psi.
4) The high-pressure test is specified in the following sections, by BOP class.
5) The low-pressure test shall be performed first. DO NOT test to the highpressure and then bleed down to the low pressure. The higher pressure could
initiate a seal after the pressure is lowered and thereby misrepresent the lowpressure test.
6) BOP equipment (including blind rams and shear blind rams) shall be
pressure tested as follows:
•
•
•
•
When installed
Before drilling out each string of casing
Following the disconnection or repair of any wellbore pressure seal in
the wellhead/BOP stack (limited to the affected components only)
Not to exceed 14 days (± 2 days)
7) All valves located downstream of the valve being tested shall be placed in the
OPEN position.
8) OPEN casing valves to the atmosphere when using a test plug to test the BOP
stack to prevent possible leaks from rupturing the casing.
9) OPEN annular valves when testing to prevent pack-off leaks from pressuring
up outer casing strings.
10) Vent the cup tester through the drillpipe when testing the upper 60 feet of
casing to prevent possible leaks from rupturing the casing or applying pressure
to the open hole.
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11) Test all valves on the wellhead individually to their rated working pressure on
installation (using a VR plug) and to 80% of casing burst on subsequent
pressure tests, with a cup tester at located + 90’.
12) Casing rams shall be tested to the maximum anticipated surface pressure
(refer to Section K, 6.0 for specific test pressures), with a joint of casing
connected to a test plug with appropriate cross-over.
13) Variable Bore Rams (VBR) shall be tested with all sizes of pipe in use,
excluding drill collars and bottom-hole tools.
14) DO NOT close annular preventers on open hole or pipe with ESP cable (or
wireline) for pressure tests. Annulars shall only be closed in these situations in
an emergency. Annulars shall be tested with the smallest OD pipe to be used.
15) All pressure tests must be held for a minimum duration of ten (10) minutes
with no observable pressure decline.
16) Only authorized personnel shall go in the test area to inspect for leaks when the
equipment is under pressure.
17) Tightening or repair work shall be done only after pressure has been released
and all parties have agreed that there is no possibility of trapped pressure.
18) A pressure test is required after the installation of casing rams or tubing rams.
This test is limited to the components affected by the disconnection of the
pressure containment seal. The bonnet seals and rams shall be tested using a
test joint connected to a test plug, or cup tester, with appropriate crossover.
19) The initial pressure test performed on hydraulic chambers of annular
preventers should be at least 1500 psi. Initial pressure tests on hydraulic
chambers of rams and hydraulically operated valves should be to the maximum
operating pressure recommended by the manufacturer. Test should be run on
both the opening and closing chambers. Subsequent pressure tests on
hydraulic chambers should be upon re-installation.
20) All pressure tests shall be conducted with a test pump. Avoid the use of rig
pumps for pressure testing. Cement units are acceptable.
21) All test results must be documented on a pressure chart, with the following
information,
• Date of Test
• Well Name
• Driller
• Toolpusher
• Saudi Aramco Representative
21) Test stumps are an acceptable method for pressure testing the BOP stack at
the rig site. The bottom connection (and any other connection not tested) must
be tested with a test plug upon installation of the BOP stack.
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SECTION K - MAINTENANCE AND TESTING REQUIREMENTS
2.2
Specific Pressure Testing Requirements for Class ‘A’ 10M BOP Stack
1) The initial high-pressure test of the following equipment shall be conducted
upon installation at the rated working pressure of the weakest component:
• Wellhead
• Ram-Type Preventers (including fixed PR, VBR, and SBR)
• Kill Line and Valves
• Emergency Kill Line and Valves
• Choke Line and Valves
• Choke Manifold
2) Subsequent high-pressure test(s) of the above equipment shall be conducted to
a pressure greater than the *maximum anticipated surface shut-in pressure.
Note: For Khuff development wells (Jilh Dolomite casing point)
Initial high-pressure test is 10,000 psi (full working pressure)
*Subsequent high-pressure test(s) are 8,500 psi
For Pre-Khuff wells (Jilh Dolomite casing point and below)
Initial high-pressure test is 10,000 psi (full working pressure)
*Subsequent high-pressure test(s) are 10,000 psi
For K1/MK1 wells only (where NU occurs above Jilh Dolomite casing point)
Initial high-pressure test is 10,000 psi (full working pressure)
*Subsequent high-pressure test(s) are 5,000 psi minimum
3) The high-pressure test (initial and subsequent) of the annular preventer shall be
conducted at 70% of the rated working pressure.
4) All pressure tests, excluding casing tests, must be done with a test plug, due to
the minimum yield strength (burst rating) of the 13-3/8” 72# and 9-5/8” 53.5#
casing. Test plugs must be checked to insure the plug fits the casing head.
5) The initial high-pressure test of the upper/lower kelly cocks, inside BOP, and
safety valves shall be conducted to their rated working pressure. Subsequent
high-pressure test(s) shall be conducted at the maximum anticipated surface
shut-in pressure.
6) Rotary hoses, standpipe, vibrator hoses, and piping to pumps shall all be tested
to 5000 psi.
7) The initial pressure test on the closing unit valves, manifold, gauges, and BOP
hydraulic lines shall be at the rated working pressure of the closing unit (3,000
psi). Subsequent pressure shall be performed on each well installation at the
same pressure or after repairs to the hydraulic circuit.
8) At nipple up, the casing shall be tested to 80% of burst rating.
9) The casing string in use shall be tested with a cup tester to 80% burst rating
every 14 days (along with the scheduled BOP test). This will provide a pressure
test of the casing valves in addition to verifying casing integrity.
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SECTION K - MAINTENANCE AND TESTING REQUIREMENTS
2.3
Specific Pressure Testing Requirements for Class ‘A’ 5M BOP Stack
1) The initial high-pressure test of the following equipment shall be conducted
upon installation at the rated working pressure of the weakest component:
•
•
•
•
•
•
Wellhead
Ram-Type Preventers (including fixed PR, VBR, and SBR)
Kill Line and Valves
Emergency Kill Line and Valves
Choke Line and Valves
Choke Manifold
2) Subsequent high-pressure test(s) of the above equipment shall be conducted to
a pressure greater than the maximum anticipated surface shut-in pressure.
This test pressure will be determined by the particular application (i.e.
formations exposed, fracture gradient or estimated fracture gradient, casing
burst rating).
3) The high-pressure test (initial and subsequent) of the annular preventer shall be
conducted at 70% of the rated working pressure.
Note:
A cup tester may be used if the high-pressure test does not exceed 80% of
the casing burst rating.
4) The casing cup tester must be the appropriate size/weight for the application.
When using this tester, care must be taken that the total load applied to the drill
string (cup area times test pressure, plus the weight of the suspended drill
string) does not exceed the string’s tensile limit.
5) The upper/lower kelly cocks, inside BOP, safety valves, rotary hose, standpipe,
vibrator hose, and piping to pumps shall be tested to same high-pressure
tests (initial and subsequent), as the BOP equipment, but not to exceed their
rated working pressure.
6) The initial pressure test on the manifold and BOP hydraulic lines shall be at the
rated working pressure of the closing unit (3,000 psi). Subsequent pressure
shall be performed on each well installation at the same pressure or after
repairs to the hydraulic circuit.
7) At nipple up, the casing shall be tested to 80% of burst rating.
8) The casing string in use shall be tested with a cup tester to 80% burst rating
every 14 days (along with the scheduled BOP test). This will provide a pressure
test of the casing valves in addition to verifying casing integrity.
Note: BOP equipment may have a higher working pressure than required, due to
rig equipment availability. The high-pressure test requirement in these
situations shall be site-specific (limited by the WP rating of wellhead).
Current Revision:
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SECTION K - MAINTENANCE AND TESTING REQUIREMENTS
2.4
Specific Pressure Testing Requirements for Class ‘A’ 3M BOP Stack
1) The initial high-pressure test of the following equipment shall be conducted
upon installation at the rated working pressure of the weakest component:
•
•
•
•
•
•
Wellhead
Ram-Type Preventers (including fixed PR, VBR, and SBR)
Kill Line and Valves
Emergency Kill Line and Valves
Choke Line and Valves
Choke Manifold
2) Any subsequent high-pressure test(s) of the above equipment shall be
conducted at 2500 psi or maximum anticipated surface shut-in pressure
(whichever is greater), as determined by the particular application (i.e.
formations exposed, fracture gradient or estimated fracture gradient, casing
burst rating).
3) The high-pressure test (initial and subsequent) of the annular preventer shall be
conducted at 2100 psi (70% of the rated working pressure).
Note:
A cup tester may be used if the high-pressure test does not exceed 80% of
the casing burst rating.
4) The casing cup tester must be the appropriate size/weight for the application.
When using this tester, care must be taken that the total load applied to the drill
string (cup area times test pressure, plus the weight of the suspended drill
string) does not exceed the string’s tensile limit.
5) Test plugs must be checked to insure the plug fits the casing head.
6) The upper/lower kelly cocks, inside BOP, safety valves, rotary hose, standpipe,
vibrator hose, and piping to pumps shall be tested to same high-pressure
tests (initial and subsequent), as the BOP equipment, but not to exceed their
rated working pressure.
7) The initial pressure test on the manifold and BOP hydraulic lines shall be at the
rated working pressure of the closing unit (3,000 psi). Subsequent pressure
shall be performed on each well installation at the same pressure or after
repairs to the hydraulic circuit.
8) At nipple up, the casing shall be tested to 80% of burst rating.
Note:
Current Revision:
Previous Revision:
BOP equipment may have a higher working pressure than required. The
high-pressure test requirement in these situations shall be site-specific
(limited by the working pressure rating of wellhead).
October 2002
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SECTION K - MAINTENANCE AND TESTING REQUIREMENTS
2.5
Specific Pressure Testing Requirements for Class ‘B’ 3M BOP Stack
1) The initial high-pressure test of the following equipment shall be conducted
upon installation at the rated working pressure of the weakest component:
•
•
•
•
•
•
Wellhead
Ram-Type Preventers
Kill Line and Valves
Emergency Kill Line and Valves
Choke Line and Valves
Choke Manifold
2) Any subsequent high-pressure test(s) of the above equipment shall be
conducted at 2500 psi or maximum anticipated surface shut-in pressure
(whichever is greater), as determined by the particular application (i.e.
formations exposed, fracture gradient or estimated fracture gradient, casing
burst rating).
3) The high-pressure test (initial and subsequent) of the annular preventer shall be
conducted at 2100 psi (70% of the rated working pressure).
Note:
A cup tester may be used if the high-pressure test does not exceed 80% of
the casing burst rating.
4) The casing cup tester must be the appropriate size/weight for the application.
When using this tester, care must be taken that the total load applied to the drill
string (cup area times test pressure, plus the weight of the suspended drill
string) does not exceed the string’s tensile limit.
5) Test plugs must be checked to insure the plug fits the casing head.
6) The upper/lower kelly cocks, inside BOP, safety valves, rotary hose, standpipe,
vibrator hose, and piping to pumps shall be tested to same high-pressure
tests (initial and subsequent), as the BOP equipment, but not to exceed their
rated working pressure.
7) The initial pressure test on the manifold and BOP hydraulic lines shall be at the
rated working pressure of the closing unit (3,000 psi). Subsequent pressure
shall be performed on each well installation at the same pressure or after
repairs to the hydraulic circuit.
8) At nipple up, the casing shall be tested to 80% of burst rating.
Note:
Current Revision:
Previous Revision:
BOP equipment may have a higher working pressure than required. The
high-pressure test requirement in these situations shall be site-specific
(limited by the working pressure rating of wellhead).
October 2002
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SECTION K - MAINTENANCE AND TESTING REQUIREMENTS
2.6
Specific Pressure Testing Requirements for Class ‘C’ or ‘II’ 3M BOP Stack
1) The initial high-pressure test of the following equipment shall be conducted
upon installation and at the rated working pressure of the weakest member:
•
•
•
•
•
Wellhead
Double Ram Preventer
Kill Line and Valves
Choke Line and Valves
Choke Manifold
2) Any subsequent high-pressure test(s) of the above equipment shall be
conducted at 2500 psi or maximum anticipated surface shut-in pressure
(whichever is greater), as determined by the particular application (i.e.
formations exposed, fracture gradient or estimated fracture gradient, casing
burst rating).
3) The high-pressure test (initial and subsequent) of the annular preventer shall be
conducted at 2100 psi (70% of the rated working pressure).
Note:
A cup tester may be used if the high-pressure test does not exceed 80% of
the casing burst rating.
4) The casing cup tester must be the appropriate size/weight for the application.
When using this tester, care must be taken that the total load applied to the drill
string (cup area times test pressure, plus the weight of the suspended drill
string) does not exceed the string’s tensile limit.
5) The upper/lower kelly cocks, inside BOP, safety valves, rotary hose, standpipe,
vibrator hose, and piping to pumps shall be tested to same high-pressure
tests (initial and subsequent), as the BOP equipment, but not to exceed their
rated working pressure.
6) The initial pressure test on the manifold and BOP hydraulic lines shall be at the
rated working pressure of the closing unit (3,000 psi). Subsequent pressure
shall be performed on each well installation at the same pressure or after
repairs to the hydraulic circuit.
7) At nipple up, the casing shall be tested to 80% of burst rating.
Note: When testing a Class ‘II’ 3M Workover stack on a Power Water Injection well
equipped with a ball master valve, the following must be observed:
a) Check the ball valve for leaks with wellhead pressure, from below, prior
to nippling-up the BOP stack.
b) Report any observed leak for decision to spot a cement isolation plug.
c) Test the blind ram on the ground against a blind flange prior to nippling-up
the BOP stack. This will provide a pressure test on the blind ram without
relying on the ball valve, which may leak at higher pressure. The pipe ram
and annular can be tested with a cup tester after nippling up.
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2.7
Specific Pressure Testing Requirements for Class ‘D’ Diverter Stack
1) Activate the ‘close/open sequence’ with drillpipe or test mandrel in the diverter
to verify control functions. DO NOT attempt to close the diverter on open hole
except in an emergency.
2) Pump water through the diverter system at low pressure and high rates.
Examine entire system for leaks, excessive vibration, and proper tie down.
3) The low-pressure test on the diverter shall be conducted upon installation and
at 300 psi.
4) The high-pressure test shall be based on 80% rated working pressure of the
weakest component in the diverter system.
5) Function test the diverter daily.
3.0
Pressure Testing Procedure
The recommended pressure testing procedure for a Class ‘A’ 10,000 psi BOP hook-up is
given below. This test procedure can be easily amended and made applicable for the
other classes of preventer stacks. Although the actual testing sequence may vary
somewhat, the ultimate objective must be achieved: To test each individual preventer,
valve, and all associated lines in the BOP system from the wellbore direction at a
300 psi low-pressure and then a specified high-pressure.
The pressure source is shown down the drillpipe and through a perforated sub or ported
test plug (excluding blind ram or casing test); although, a BOP side outlet may be
used. The annular and pipe rams are tested individually in this manner. The blind rams
are tested after removing the drillpipe and applying pressure through the kill line, between
closed rams and test plug.
Note:
In the case of the Class ‘A’ 10,000 psi (non-tapered string, where a lower set of
blind rams are positioned below the kill line), the test pressure must be applied
through the side outlet of the BOP.
In order to test each individual valve on the kill line, choke line, and manifold; proceed
after pressure testing the far outside valves, (all other valves open) by opening these
valves and closing each inside adjacent valve, pressure testing, and working inward to the
stack.
Note: The steps in the following procedure should be performed in numerical sequence.
The instructions assume that at the beginning of each step, the equipment is
arranged as in the end of the previous step. Therefore, if this particular procedure
is not followed in sequence, erroneous test results may be obtained.
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3.1
Function Testing and Flow Testing
Before applying test pressure to the preventers, perform the following:
1) Close and open all preventers. DO NOT CLOSE pipe rams or annular
preventer on open hole.
2) Pump through the kill line, flow line, mud-gas separator, and choke lines with
water to make sure none are plugged.
3.2
Fill the Stack with Water
Drain the mud from the BOP stack and fill with clear water.
3.3
Casing Test
A casing test is generally conducted at nipple-up when testing DV or float
equipment. In addition, this test is required every 14 days (along with the
scheduled BOP test), with the use of a cup tester, to provide a pressure test on
casing head valves and verify casing integrity.
To conduct a casing test, perform the following:
1) Connect the pressure source to the kill line and open kill line valves #4 and #5.
Figure K.1 Casing Test
Shear Blind Rams
Shear Blind Rams
#3a
Note:
VERY IMPORTANT - Monitor valves #1, #2, #3 and #3a for leaks/well flow.
2) Open all valves and chokes on choke manifold. Close valve #7 on choke line.
3) Close outer casing head valves #1 and #3a.
4) Close the blind/shear blind rams (or upper pipe rams, if pipe in the hole).
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5) Pump into the well through the kill line monitoring/recording the test pressure at
the test pump. For all casing strings other than drive pipe or structural casing,
conduct the test to 80% of the minimum internal yield (burst) of the casing.
6) To test inner casing head valves, close valves #2 and #3 and open outer valves
#1 and #3a. See Figure K.1.
Note:
3.4
No manufacturer recommends opening rams, which are holding pressure.
Damage to the ram rubbers, ram blocks and ram cavities may occur.
Shear Blind Ram Test (or Blind Rams for other BOP Stack Configurations)
To pressure test the Shear Blind Ram (or Blind Ram), the following is required:
1) Land test plug in the casing head and remove running tool from the wellbore.
2) Connect the pressure source to the kill line and open kill line valves #4 and #5
(see Figure K.2).
Figure K.2
Shear Blind Ram Test
Shear Blind Rams
#3a
Note:
Monitor valves #1, #2, #3 and #3a for well flow.
3) Open all valves and chokes on the choke manifold.
4) Open all casing head valves and close the choke line valve #7.
5) Close the shear blind rams.
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6) Pump into the well through the kill line. Monitor and record the test pressure at
the test pump. Conduct the low-pressure test first at a pressure of 300 psi.
Conduct the high-pressure test next at the pressure specified in previous
requirements (Section K 2.2 for Class ‘A’ 10M).
Note:
3.5
This test will also evaluate the choke line HCR valve and thereby eliminate
the need for Step 3.11.
Annular Preventer
Test the annular preventer as follows:
1) Land the test plug and test joint in the casing head.
2) Connect the pressure source to the test joint at the rig floor.
3) Close the kill line HCR (valve #4) and open all other kill line valves (the kill line
check valve should be crippled).
4) First, open all choke line and choke manifold valves. Then close the outermost
choke manifold valves #15, #16, #17, and #18 (before buffer tank). See Figure
K.3.
Figure K.3
Annular Test
Shear Blind Rams
#19
#3a
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5) Verify that the casing head valves #2 and #3 are open.
6) Close the annular preventer and pump into the well through the test joint.
Conduct the low-pressure test first at a pressure of 300 psi. Conduct the highpressure test next at a pressure equal to 70% of the rated working pressure
of the annular preventer. Verify the accuracy of the gauge installed downstream
of choke manifold valve #19 by observing the test pressure.
3.6
Upper Pipe Rams
Without changing the choke manifold or testing arrangement, immediately test the
upper pipe rams as follows.
1) Close choke manifold valve #19 (see Figure K.4).
2) Close the upper pipe rams and pump into the well through the test joint.
Conduct the low-pressure test first at a pressure of 300 psi. Conduct the highpressure test next at the pressure specified in previous requirements.
Confirm that choke manifold valve #19 is not leaking by observing a zero
pressure indication on the downstream gauge.
Figure K.4
Upper Pipe Rams
Shear Blind Rams
#3a
Note:
Current Revision:
Previous Revision:
Monitor valves #1, #2, #3 and #3a for well flow.
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3.7
Positive-Sealing Choke Test
If the chokes are designed to be positive sealing, test them as described below;
otherwise, proceed to Step 3.8.
1) Open outermost choke manifold valves #15, #16, and #18.
2) Close positive-sealing chokes (see Figure K.5).
3) Close the upper pipe rams and pump into the well through the test joint.
Conduct the low-pressure test first at a pressure of 300 psi. Conduct the highpressure test next at the pressure specified in previous requirements.
Figure K.5
Positive-Sealing Choke Test
Shear Blind Rams
#3a
Note:
Current Revision:
Previous Revision:
Monitor valves #1, #2, #3 and #3a for well flow.
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3.8
Choke Manifold Valves (continued)
Continue testing the choke manifold valves by performing the following:
1) Open outermost choke manifold valves #15, #16, #17, and #18.
2) Open chokes.
3) Close choke manifold valves #11, #12, and #14 (see Figure K.6).
4) Close the upper pipe rams and pump into the well through the test joint.
Conduct the low-pressure test first at a pressure of 300 psi. Conduct the highpressure test next at the pressure specified in previous requirements.
Figure K.6
Choke Manifold Valves
Shear Blind Rams
#3a
Note:
Current Revision:
Previous Revision:
Monitor valves #1, #2, #3 and #3a for well flow.
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3.9
Choke Manifold Valves (continued)
Continue testing the choke manifold valves by performing the following:
1) Open choke manifold valves #11, #12, and #14.
2) Close choke manifold valves #9, #10, and #13 (see Figure K.7).
3) Close the upper pipe rams and pump into the well through the test joint.
Conduct the low-pressure test first at a pressure of 300 psi. Conduct the highpressure test next at the pressure specified in previous requirements.
Figure K.7
Choke Manifold Valves
Shear Blind Rams
#3a
Note:
Current Revision:
Previous Revision:
Monitor valves #1, #2, #3 and 3a for well flow.
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3.10 Choke Manifold Valves (continued)
1) Open choke manifold valves, #9, #10, and #13.
2) Close choke manifold valve #8 (see Figure K.8).
3) Close the upper pipe rams and pump into the well through the test joint.
Conduct the low-pressure test first at a pressure of 300 psi. Conduct the highpressure test next at the pressure specified in previous requirements.
Figure K.8
Choke Manifold Valves
Shear Blind Rams
#3a
Note:
Current Revision:
Previous Revision:
Monitor valves #1, #2, #3 and #3a for well flow.
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3.11 Choke Line HCR Valve
Test the choke line HCR valve by performing the following:
1) Open choke manifold valve #8.
2) Close outer choke line HCR (valve #7). See Figure K.9.
3) Close the upper pipe rams and pump into the well through the test joint.
Conduct the low-pressure test first at a pressure of 300 psi. Conduct the highpressure test next at the pressure specified in previous requirements.
Figure K.9
Choke Line HCR Valve
Shear Blind Rams
#3a
Note:
Current Revision:
Previous Revision:
Monitor valves #1, #2, #3 and #3a for well flow.
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3.12 Choke and Kill Line Manual Valves
Test the inner choke and kill line valves by performing the following:
1) Open choke line HCR (valve #7).
2) Close choke line manual valve #6.
3) Open kill line HCR (valve #4).
4) Close kill line manual valve #5 (see Figure K.10).
5) Close the upper pipe rams and pump into the well through the test joint.
Conduct the low-pressure test first at a pressure of 300 psi. Conduct the highpressure test next at the pressure specified in previous requirements.
Figure K.10
Choke and Kill Line Manual Valves
Shear Blind Rams
#3a
Note:
Monitor valves #1, #2, #3 and #3a for well flow.
Note:
No manufacturer recommends opening rams, which are holding pressure.
Damage to the ram rubbers, ram blocks and ram cavities may occur.
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3.13 Master Pipe Rams
Test the master pipe rams by performing the following:
1) Open the upper pipe rams (see Figure K.11).
2) Close the master pipe rams and pump into the well through the test joint.
Conduct the low-pressure test first at a pressure of 300 psi. Conduct the highpressure test next at the pressure specified in previous requirements.
Figure K.11
Master Pipe Rams
Shear Blind Rams
#1
#1
#2
#2
#3
#3a
Note:
Monitor valves #1, #2, #3 and 3a for well flow.
Note:
No manufacturer recommends opening rams, which are holding pressure.
Damage to the ram rubbers, ram blocks and ram cavities may occur.
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3.14 Small Pipe Rams
Test the small pipe rams by performing the following:
1) Open the master pipe rams (see Figure K.12).
2) Pull the large test joint and test plug. Run a small test joint and plug.
3) Close the small pipe rams and pump into the well through the test joint.
Conduct the low-pressure test first at a pressure of 300 psi. Conduct the highpressure test next at the pressure specified in previous requirements.
Figure K.12
Small Pipe Rams
Shear Blind Rams
#1
#2
#3
#3a
Note:
Monitor valves #1, #2, #3 and #3a for well flow.
Note:
No manufacturer recommends opening rams, which are holding pressure.
Damage to the ram rubbers, ram blocks and ram cavities may occur.
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3.15 Kelly, Surface Circulating Equipment, and Safety Valves
1) Pick up kelly and install full-opening safety valve on bottom of lower kelly valve.
2) Using an adaptor, connect to an independent test pump or cement pump.
3) Open appropriate standpipe valves and all kelly valves.
4) Fill the system with water and close standpipe valve to test the standpipe, rotary
hose, swivel, and kelly.
5) Conduct the low-pressure test first at a pressure of 300 psi.
6) Conduct the high-pressure test next at the pressure specified in previous
requirements.
7) By alternating closing upstream and opening downstream valves, all the kelly
valves could be tested without pressuring up again, although it may not possible
to operate the upper kelly valve under pressure.
8) The inside BOP (float type) can be tested similarly by installing below the fullopening safety valve and opening all valves through the standpipe.
3.16 Wellhead Valves
Test all valves on the wellhead individually to their rated working pressure on
installation (using a VR plug) and to 80% of casing burst on subsequent pressure
tests, with a cup tester at located + 90’.
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4.0
Accumulator Tests
These tests are for the purpose of determining the operating condition of the accumulator
and BOP system. They shall be performed every 14 days, at the same time the BOP
equipment is pressure tested, and at any other time deemed necessary by the Saudi
Aramco Foreman. The results shall be noted on the Saudi Aramco BOP Pressure Test
Report (see Figure K.13, or Form # 2.0 in Section S of this manual). To analyse the
performance of the accumulator, the results of each test should be compared with results
of several previous tests. Any increase in closure or recharge time indicates an immediate
need for a thorough examination of the accumulator system. The accumulator test shall
include the following,
•
•
•
•
Note:
Record the accumulator capacity and useable volume
Record the accumulator pressure
Record the pre-charge pressure and last date checked
Record the closing and opening times for each component
Alternate accumulator bi-weekly tests between the main nitrogen unit (with
charging system isolated) and air/electric back-up system (with bottle banks
isolated).
Preventer functions should also be operated remotely to insure proper
operation of all functions from the remote stations.
The accumulator test shall also comply Saudi Aramco’s general requirements as follows:
§
Closing time for ram preventers should not exceed 30 seconds.
§
Closing time for annular preventers (less than 18-3/4”) should not
exceed 30 seconds.
§
Closing time for annular preventers (18-3/4” and larger) should not
exceed 45 seconds.
§
The accumulator must have enough stored fluid under pressure to
close all preventers, open the choke hydraulic control gate valve (HCR),
and retain 50% of the calculated closing volume with a minimum of 200
psi above pre-charge pressure, without assistance of the accumulator
pumps.
§
The accumulator-backup system shall be automatic, supplied by a
power source independent from the power source to the primary
accumulator-charging system, and possess sufficient capability to
close all blowout components and hold them closed.
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Figure K.13
Saudi Aramco BOP Pressure Test Form
NOTE:
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Figure K.13
Saudi Aramco BOP Pressure Test Form
ALTERNATE BI-WEEKLY TESTS WITH
CHARGING SYSYTEM ISOLATED
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5.0
Hang-Off Limitations While Testing
Many times, a portion of the bottom-hole assembly will be hung-off below the test plug
while conducting a BOP test. This is done for a variety of reasons including:
•
•
Leaves pipe in the hole to circulate through in case the well kicks.
Shortens the trip time by not having to pull completely out of the hole.
IT MUST BE REMEMBERED however, that hanging-off weight below the test plug
reduces the maximum allowable BOP test pressure. Figure K.14 shows the maximum
allowable hang-load for a given BOP test pressure for the wellhead manufacturers used
by Saudi Aramco. This chart should be reviewed before hanging-off and testing BOP
equipment.
Figure K.14
Maximum Hanging Load for Different Bowl Sizes and BOP Test Pressures
For Gray, FMC, Cameron, and Wood Group Wellhead Equipment
Maximum Hanging Load (lbs) for Given BOP Test Pressure
Bowl
Size
0
psi
1000
psi
2000
psi
3000
psi
4000
psi
5000
psi
6000
psi
7000
psi
8000
psi
9000
psi
10,000
psi
11”
580,000
580,000
580,000
580,000
580,000
580,000
543,000
466,000
389,000
312,000
235,000
13”
580,000
580,000
580,000
580,000
580,000
515,000
388,000
261,000
134,000
7,000
20”
580,000
580,000
580,000
580,000
580,000
580,000
-
-
-
-
-
26”
580,000
580,000
580,000
580,000
580,000
580,000
-
-
-
-
-
6.0
Test Pressure Requirements for Casing Rams
Casing rams (and annular preventer) shall be pressure tested with a test plug and casing joint to
the following pressures prior to running casing or liner. The following table lists the specific test
pressure for casing rams relative to casing point.
Casing Point
Arab-D and Above
Base Jilh Dolomite
Top of Khuff Fm.
Khuff-D Anhydrite
Pre-Khuff TD
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500 psi
750 psi
1500 psi
1500 psi
1500 psi
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SECTION L – DIVERTING OPERATIONS AND EQUIPMENT
Table of Contents
Introduction............................................................................................ L-2
1.0
Diverting vs. Shutting-In ............................................................ L-2
2.0
Diverter Systems......................................................................... L-3
2.1
2.2
2.3
2.4
2.5
2.6
2.7
2.8
3.0
4.0
5.0
Annular Preventer ............................................................................ L-4
Diverter Spool................................................................................... L-4
Diverter Valves ................................................................................. L-4
Overboard Lines............................................................................... L-5
Diverter Control Stations ................................................................. L-5
Mud-Gas Separator (MGS) ............................................................... L-7
Kill Mud............................................................................................. L-7
Pressure Testing the Diverter System............................................. L-8
2.8.1 Upon Initial Nipple-Up ............................................................ L-8
2.8.2 While Drilling Ahead under Diverting Conditions..................... L-8
Diverting Procedure.................................................................... L-8
Considerations while Drilling Surface Hole.............................. L-9
Guidelines for Training of Crews............................................. L-10
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SECTION L – DIVERTING OPERATIONS AND EQUIPMENT
Introduction
The occurrence of shallow gas zones, particularly offshore, can be extremely dangerous and
presents some unique well control considerations. Since the gas is shallow, any flow from the
formation will reach the surface very quickly. Thus, very little time is available for detecting the kick
and either shutting-in the well or diverting the flow.
Many wells with shallow casing strings have insufficient integrity at the shoe to withstand the
pressures imposed by shutting-in. Closing-in a shallow well with little or no shoe integrity can cause
the shoe to breakdown and allow formation fluids to broach back to the surface. A broached shoe
can seriously jeopardize a bottom supported rig (i.e. jack-up, platform, land rig) and its crew. For
bottom supported rigs and land rigs, diverting is often the only viable alternative to shutting-in when
shallow gas kicks are encountered.
Diverting is a method of directing the flow from an unloading well in order to minimize physical
damage to rig personnel and equipment. Diverting equipment and procedures are designed to
impose as little backpressure as possible on the weak downhole formations. Diverting is not a well
control procedure, per se, and a successful diverting operation is one that allows the well to bridge
over or deplete itself without loss of life or equipment.
1.0
Diverting vs. Shutting-In
In many instances while drilling surface hole, the shoe integrity is insufficient to withstand
the increased pressures associated with shutting-in. Therefore, if the well begins to unload,
the flow must be directed such that physical damage is minimized and to afford time to
allow evacuation and/or remedial action to be taken. It must be stated, however, that if
there is a known producible sand, a BOP system or modified BOP system must be
installed prior to the penetration of the sand. This would allow some type of proven well
control procedures to be taken. To use any type of proven well control procedure, there
must be enough formation integrity to allow the well to be shut in and/or backpressure
applied such that the well could be killed. Three governing criteria for use of a diverter
system as opposed to a BOP stack are:
•
Diverter - When there is no zone of known production potential (i.e., any shallow
hydrocarbons which are encountered are expected to deplete rapidly)
•
Diverter - When there is not enough formation integrity to withstand the pressure
of the formation fluids from broaching around a shallow casing string
•
BOP
Current Revision:
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- When penetrating shallow productive sands (i.e., where the sand is not
expected to deplete rapidly); when drilling adjacent to another well on a
platform or at a multiwell location that is capable of producing
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SECTION L – DIVERTING OPERATIONS AND EQUIPMENT
2.0
Diverter Systems
Diverter systems are used as a way to direct an uncontrolled flow from a shallow zone, not
as a means to kill the well. To minimize the chance of human error or equipment
malfunction, the system must be kept as simple as possible. The system should consist of
an annular preventer, drilling (diverter) spool, two divert valves and two overboard lines (as
shown in Figure L.1). The only question as to the hook up lies in the position of the diverter
spool and annular preventer. The flow should be directed overboard through lines with a
minimum of turns, since the greatest amount of erosion will occur at the point the flow
changes direction. It has been determined that at flow velocities greater than 50 fps, fluid
erosion is the major problem while diverting. In most divert cases; this flow velocity has
been exceeded. To minimize the chance of premature failure caused by erosion, the lines
must be kept as straight as possible and be targeted at every sharp turn.
Figure L.1
Diverter Hook-up
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SECTION L – DIVERTING OPERATIONS AND EQUIPMENT
In offshore operations where the annular preventer and diverter spool are placed close to
mean sea level with the work deck a considerable distance above, the normal procedure
would be to use hose or flexible pipe to connect the overboard lines to the diverter spool.
This results in a large distance of the line being unsupported, hanging from the barge
which presents a hazard and amplifies the chance of premature failure. To eliminate this, a
marine riser, with a pressure rating equal to the conductor pipe, should be utilized. This
riser would bring the annular preventer and diverter spool directly to the large diameter,
steel overboard lines. Unsupported diverter lines should not be installed.
2.1
Annular Preventer
A 20” 2M bag-type annular preventer should be used when possible because of its
field proven dependability. When a larger bore preventer is necessary, it should be
replaced with a 20” 2M preventer as soon as possible. The annular preventer must
be visually inspected for damage prior to installation. All flange bolts, both top and
bottom, must be used.
2.2
Diverter Spool
The diverter spool must be of a pressure rating equal to or greater than that of the
annular preventer, with two 6” minimum ID side outlets. No adapters or swages
should be used to install the divert valves. The spool should be inspected to assure
its integrity prior to installation. All bolts must be installed and new ring gaskets used
to minimize the possibility of leaks.
2.3
Diverter Valves
The diverter valves should be installed immediately adjacent to the diverter spool.
This is to compensate for an overboard line failure, since the valve being adjacent to
the diverter spool eliminates any chance of problems in piping between the spool
and valve. Many valve failures have occurred due to internal rust build-up. You
should verify that all diverter valves are in good condition and not rusted so that full
opening or full closure is not impeded.
Saudi Aramco's recommended guideline is for two 6” ID lines and full opening
valves, if there are no more than two turns in the divert lines before going overboard.
If there are more than two turns in the lines, 10” lines and valves are recommended.
The design of diverter systems should emphasize a uniform internal diameter
throughout. Any changes in internal diameter in the system will cause severe erosion
problems. In addition, all divert valves should be hydraulically operated. The
advantages of hydraulic operation are:
•
•
•
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They are consistent with the control station.
Hydraulic control lines will be less likely to be damaged during
operations because they are high pressure lines and are part of the rig.
A hydraulic actuator can develop a greater force using a smaller
chamber as compared to an air-operated valve. This will result in a
more compact valve, which will be easier to handle and install.
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The one item strongly recommended is that the pressure rating of the valves be
consistent with the system. Although the divert valves will not be intended to close in
the well, there is a distinct possibility that pressure may be held against a valve. For
example, if a well is being diverted overboard through the port side and suddenly
plugs up, the starboard valve must be able to hold and operate with this pressure
being applied. In some cases, dynamic pressure surges due to a water hammer
effect may create pressures in excess of static bottomhole pressures.
In a study of divert situations, it was found that the single most common cause of
failure in the diverter system was the malfunction of the divert valves. No evidence
was found to determine whether a ball valve is more or less reliable than a gate
valve but the hydraulic gate valve has been proven in field use for BOP systems. As
a result, the selection of a gate valve is preferable whenever possible. Again, all
valves should be routinely function tested to insure they are not rusted in position.
Certain operations require a booster pump to be installed on the drive pipe close to
the water level to reduce lost return problems. If this pump is being used, it must
have a remote valve installed adjacent to the drive pipe with a pressure rating
consistent with the system. Its operations must be tied into the diverter panel such
that it will be closed automatically when the diverter is closed.
2.4
Overboard Lines
The overboard lines should be of the same pressure integrity as the rest of the
system for the same reason as the divert valves. If a line plugs, it must be able to
withstand pressure for the time it takes to open the opposite line. The lines must be
installed as straight as possible since changes in flow direction can cause significant
erosional problems at the area of change.
Most of the offshore rigs in use today have the capabilities of moving the derrick to
allow the drilling of another well without moving the rig which could result in moving
the overboard lines. If at all possible, hard piping from the divert valves to the
overboard lines should be used. In the case where hard piping is not possible,
flexible hoses could be used to connect the overboard lines with the divert valves.
These flexible lines must be of a pressure rating consistent with the system and have
API flanges built in the hose for connecting. A collapsible hose with hose clamps is
not adequate.
The hoses and overboard lines must be securely anchored to accommodate the
severe forces to which they will be subjected.
2.5
Diverter Control Stations
The component most often lacking in consistency and definition is the control station
that will be used to execute the divert function. Simplicity and reliability of a diverter
system demands the control station to be readily accessible and simple in operation,
leaving no room for error. The system should operate as a remote station to the main
accumulator system. The diverter control station should consist of two levers in a
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SECTION L – DIVERTING OPERATIONS AND EQUIPMENT
panel that are labeled as to their function. One lever should be used to divert the flow
overboard. When this handle is moved to Divert, the 4-way valve on the main
accumulator for the annular preventer will shift to the close position, closing the
annular preventer. Simultaneously, the 4-way valves on the main accumulator for
both port and starboard divert valves will shift to the open position, opening both
overboard lines. If at this time the need arises to close the upwind overboard line, the
second lever on the control station should be used. This lever, when moved to port,
will shift the starboard 4-way valve on the main accumulator to the close position and
shift the port four way valve to the open position, if closed, opening the port divert
valve. No combination of these handles should allow the well to be shut in. A diverter
control station rigged-up this way is shown in Figure L.2.
Figure L.2
Diverter Control Panel
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SECTION L – DIVERTING OPERATIONS AND EQUIPMENT
Two separate diverter control stations are required; one on the rig floor, and the
other station at a safe and remote distance from the rig. The diverter control stations
will be air operated, supplied by the rig’s continuous air supply. As a safety
precaution, the control stations should contain an air reserve bottle with adequate
volume to function each operation two times, independent of rig air.
The major advantages of a separate diverter control system are:
•
•
•
•
•
•
•
•
2.6
It has the sole function of controlling the divert operation.
It will be a permanent fixture of the rig.
Activation of the system will simply require the air supply to be turned
on.
The chance of human error in diverting a well is eliminated.
The Drilling Foreman will have a complete understanding of how the
system works no matter what rig he is on.
By using the main accumulator system, the stored energy of the system
is utilized.
The control lines from the unit to the component are high-pressure steel
lines that are permanently installed on the rig.
When drilling, each individual component is controlled by using the
handle on the main accumulator. This will allow you to do any remedial
work without affecting the operations of the diverter control station.
Mud-Gas Separator (MGS)
By definition, the diverter system is used to divert the flow away from the rig. The
MGS, by design, is an integral part of the rig. Thus, if the flow were directed to the
MGS, it would in effect be directed to the rig. As a result, any malfunction in the MGS
can and has caused considerable damage and/or loss of life. The inability of the
MGS to handle high flow rates can create an extremely hazardous situation. It is
recognized that under certain conditions, the availability of a MGS as part of the
system could be of use in circulating raw drilling fluid, which is simply gas cut. The
primary concern with using the MGS is if the flow rate becomes excessive and is not
recognized, the results could be catastrophic. Also, the use of an MGS requires
additional valving and controls to the diverter system. As was stated earlier, the
diverter system must be kept as simple as possible. Therefore, the mud-gas
separator should not be used as part of the diverter system.
2.7
Kill Mud
It is the general opinion in our operations that a pit of kill mud could prove to be an
asset. In the early stages of a divert situation, the pumping of a weighted mud could
balance the formation and kill the well. The weight of the kill mud must be
determined by testing the formation below the casing shoe or from a known fracture
gradient. If a shallow casing shoe could not support the hydrostatic pressure of the
kill weight mud, the entire divert operation would be in vain. Thus, the use of (or
avoidance of) kill mud should be addressed in the diverter contingency plan.
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SECTION L – DIVERTING OPERATIONS AND EQUIPMENT
2.8
Pressure Testing the Diverter System
Diverter systems are required to be pressure tested and function tested on a regular
basis. The required tests are described below.
2.8.1
Upon Initial Nipple-Up
•
Pressure test the diverter bag, vent lines, spool, and diverter valves to
200 psi. This test may be conducted with a test plug, or in conjunction
with the conductor pipe pressure test before drilling out the shoe.
Record the test on a test chart and make a written notation of the test in
the tour report.
•
Function test all equipment and circulate through the overboard lines to
ensure they are free from obstruction. Make a record of the test in the
tour report.
Note:
2.8.2
3.0
Verify that each diverter valve is functioning both fully opened and
fully closed. This should be done visually.
While Drilling Ahead under Diverting Conditions
•
Pressure test the diverter bag, spool, diverter valves, and vent lines to
200 psi at least once every seven days. This test will require a test plug.
Record the test on a test chart and make a written notation of the test in
the tour report.
•
Function test all equipment (open and close) at least once every 24
hours. Make a written notation of the test in the tour report.
Diverting Procedure
Upon noticing the first positive indication the well is flowing:
1)
Sound the alarm
2)
Close the diverter, at which time both divert valves overboard will open automatically
3)
Notify the Drilling Foreman and Toolpusher
4)
Alert all non-essential personnel to prepare for possible evacuation
5)
Shut down the pumps and check for flow through the overboard lines
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Note:
6)
If flowing, start pumps at a fast rate (pumping mud from the active system or kill pit).
Note:
4.0
Shutting down the pumps to check for flow may result in greater influx
flow rates. Continuous pumping is recommended, especially if there
was a positive indicator of flow.
The pumps should be lined up to switch over to seawater in the event
all the mud is pumped away without a kill. If the situation has
progressed this far, realize that ECD, the chance of the formation
bridging over or depleting the reservoir are the only lines of defence
that exist for controlling the divert situation.
7)
Station one of the rig floor personnel to monitor the water area around the rig for
possible broaching of the blowout to the surface.
8)
Eliminate all sources of ignition.
Considerations While Drilling Surface Hole
1)
A diverter system should be used where there is insufficient formation integrity to
close the well in. A diverter system should not be used if there are known
productive sands, which will not readily deplete. In these instances, casing must be
set above the sand and blowout preventer stack installed.
2)
The diverter system should be made as simple as possible in its hook-up and
operation.
3)
The minimum diverter system should consist of an annular preventer, diverter
spool with two outlets of 6” minimum ID, two hydraulic valves with a
minimum of 6” ID and two overboard lines with a minimum of 6” ID. All
components should be consistent in their pressure rating. The overboard lines must
be well anchored and as straight as possible.
4)
A diverter valve should be installed on each overboard line. There should be no
additional valves or lines tied into the overboard lines downstream of the diverter
valves.
5)
A hydraulic valve, with a pressure rating consistent with the system, must be used
when a booster pump is installed. The valve should be hooked up such that it
closes when the diverter closes.
6)
Diverter systems that require long unsupported sections of pipe to connect the
divert valves with the overboard lines should be eliminated by utilizing marine risers
to bring the diverter spool up to the work deck.
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SECTION L – DIVERTING OPERATIONS AND EQUIPMENT
5.0
7)
Hoses connecting the overboard lines with the diverter valves are not
recommended.
8)
Utilize two separate control stations specifically designed to control the diverter
system. These stations should be tied into the existing accumulator system.
9)
A mud-gas-separator should not be tied into the diverter system.
10)
Several hole volumes of kill mud should be available for emergency pumping. The
weight of the kill mud must not exceed that which would break the formation down.
11)
The diverter system should be tested to 200 psi and function tested when installed.
12)
A step-by-step procedure for a divert situation should be reviewed by all personnel
involved and posted on the rig floor. Drills on this procedure should be performed
until the crews become proficient.
13)
Consideration of drilling a pilot hole to casing point as compared to a full gauge hole
on the first pass should be made. A pilot hole will allow for higher values of ECD
and should bridge over easier as compared to the full gauge hole.
Guidelines for Training of Crews
Since a diverting operation is so very critical and also difficult in that everything is
happening quickly, special training for everyone in the drilling crew is required. It is the
Drilling Foreman’s responsibility to see that the crews are trained and have defined
responsibilities during the operation. Several items are listed below which should be
included as part of the rig crew's training.
1)
Go over each component of the diverter stack explaining its purpose and operation.
2)
Explain the control stations (i.e., position and operation of each control valve).
Emphasize that the well is not to be shut in at any time. If manifolding does not
provide for simultaneous opening of the hydraulically operated valve and closing of
the annular preventer, be sure that it is understood that closing procedure is to:
•
•
Open valves on the drilling spool
Close annular preventer
3)
Explain that the pumps are not to be stopped unless so ordered.
4)
Assign positions and responsibilities for each crewmember. This should be
determined by the Toolpusher.
5)
Establish warning and abandon rig alarms.
6)
Establish contingency plan for fluid type and fluid density to be pumped.
7)
Establish evacuation procedure.
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SECTION M – TRAINING AND WELL CONTROL DRILLS
Table of Contents
Introduction........................................................................................... M-2
1.0
Pit Drills ...................................................................................... M-2
1.1
1.2
1.3
2.0
3.0
Equipment ....................................................................................... M-2
Frequency........................................................................................ M-2
Procedure ........................................................................................ M-3
Trip Drills .................................................................................... M-4
2.1
Frequency........................................................................................ M-4
2.2
Procedure ........................................................................................ M-4
Accumulator Drill ....................................................................... M-5
3.1
Procedure ........................................................................................ M-5
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SECTION M – TRAINING AND WELL CONTROL DRILLS
Introduction
Shutting-in the well quickly to minimize the size of the influx is a major element of successful well
control. Drilling crews can only get proficient in this action through training and practice. The Drilling
Foreman should ensure that the Contract Toolpusher administers training in the areas of kick
detection and shut-in procedures until proficiency is demonstrated. The training must be repetitive
and frequent enough so that shutting-in the well becomes automatic whenever a kick is detected.
The Drilling Foreman can judge the level of crew shut-in proficiency through the use of pit drills and
trip drills. These drills should always be coordinated with the contract toolpusher. Proper drills and
training can prevent panic and provide for orderly operation if a kick should occur. The following
discussions describe how to conduct the drills and provide a basis for crew evaluation.
1.0
Pit Drills
The pit drill is designed to simulate an actual kick while drilling ahead and is designed as
both a teaching and a testing tool. While drilling ahead, it teaches the drilling crews to be
alert for positive indicators of a kick and provides practice in the proper Saudi Aramco shutin procedures. It also defines and reinforces the assigned duties of every member of the
drilling crew in well control situations. Pit drills are conducted unannounced so that realism
is created and so the crews can be observed under actual operating conditions.
Pit drills train the Driller to be constantly aware of the fluid level in the mud pits and the
return mud flow, much as the driver of an automobile subconsciously checks his
speedometer. This training is expected to prepare the driller to detect a kick at the first
surface indication and with a minimum of reservoir fluid influx. He will then be able to take
correct preventive action, lessening chances of disaster. Pit drills should be supervised by
the Contract Toolpusher and coordinated through the Drilling Foreman.
1.1
Equipment
All equipment required for pit drills is to be installed prior to drilling and kept in good
operating condition. A multi-float pit level indicator and flow show device must be
available. A pre-arranged horn or siren signal is an essential part of the pit drill. At
the signal, each crewmember must go immediately to his assigned post and execute
his assigned duties. The Drilling Foreman should note the times required (in
minutes) for various aspects of the pit drills and record them on the tour report. The
number and times for these drills should be relayed to the office.
1.2
Frequency
One or more pit drills should be conducted each day until the crews become
proficient; then at least twice weekly per crew, or more often if deemed advisable by
the Drilling Foreman. Pit drills should be held at least one each day on offshore
wells, wildcats, and wells where above-normal bottomhole pressure could exist. New
drillers should be given special drills and thorough explanation of this practice. It is
one of the most important safety measures that can be initiated and followed.
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SECTION M – TRAINING AND WELL CONTROL DRILLS
Drills are to be conducted during both routine and special operations. Typical times
would be while drilling, shut down for equipment repairs, logging, waiting on orders,
circulating, the Driller has gone to eat and is replaced by one of his men, the Driller is
talking to someone, or any other time there is open hole and blowout preventers
installed.
1.3
Procedure
1)
The Toolpusher simulates the kick by raising a float in the mud pits or by
raising the arm on the flow show indicator and making a note of the time.
The Drilling Foreman should assist in observing the crew and recording
completion times.
2)
The Driller must detect the kick and sound the alarm. The time of the alarm
should be noted. Upon hearing the alarm, all members of the drilling crew
should immediately execute their assigned duties.
3)
The Driller should prepare to shut in the well using the approved Saudi
Aramco Shut-in Procedure While Drilling. The Drilling Foreman should be
on the rig floor to announce to the driller that the exercise is only a drill and
to stop him before he actually closes the blowout preventers. The time
should be noted when the driller is prepared to shut in the well.
4)
Members of the drilling crew should report back to the rig floor having
completed their assigned duties. These duties may include:
Driller
Shut in the well (simulated)
Record drillpipe pressure and casing pressure
Record time
Measure pit gain
Check choke manifold for valve positioning and leaks
Derrickman
Weigh sample of mud from suction pit
Check volumes of barite, gel, and water on location
Floor Hand #1
Check accumulator pressures and pumps
Check BOP stack for leaks and proper valve positions
Turn on water jets to diesel exhausts
Floor Hand #2
Assist Driller on rig floor
Floor Hand #3
Assist Derrickman on mud pits
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SECTION M – TRAINING AND WELL CONTROL DRILLS
2.0
Trip Drills
The trip drill is designed to train the drilling crews to recognize and respond to kick
indications, which occur while tripping pipe. Like the pit drill, the trip drill is useful for both
teaching and testing purposes. The pit drill also proves that essential detection equipment
is installed and in good operating condition.
The trip drill is supervised by the Contract Toolpusher with the knowledge of the Saudi
Aramco Drilling Foreman. All parts of the well control system must be kept hooked up and
in good condition, ready for drills.
2.1
Frequency
When a new rig is picked-up, trip drills should be conducted during each trip (both
while pulling out and going into the hole) while the bit is up in the casing. When the
crew becomes proficient, trip drills should be conducted at least twice weekly per
crew, conditions allowing.
2.2
Procedure
1)
The Toolpusher simulates the kick by raising a float in the mud pits and
making a note of the time. The Drilling Foreman should assist in observing
the crew and recording completion times.
2)
The Driller must detect the kick and sound the alarm. The time of the alarm
should be noted. Upon hearing the alarm, all members of the drilling crew
should immediately execute their assigned duties.
3)
The Driller should prepare to shut in the well using the approved Saudi
Aramco Shut-in Procedure While Tripping. This will include spacing out
and stabbing/closing the full open safety valve. After the safety valve is
installed and the Driller is ready to close the preventers, the Drilling Foreman
should announce to the Driller that the exercise is only a drill and that it is not
necessary to close the preventers. The time should be noted when the driller
is prepared to shut-in the well.
4)
Members of the drilling crew should proceed with their assigned duties and
report back to the rig floor upon completion. These duties may include:
Driller
Shut in the well (simulated)
Record drillpipe and casing pressure
Record time
Measure pit gain
Check choke manifold for valve positioning and leaks
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Derrickman
Weigh sample of mud from suction pit
Check volumes of barite, gel, and water
Floor Hand #1
Check accumulator pressures and pumps
Check BOP stack for leaks
Turn on water jets to diesel exhausts
Floor Hand #2
Stab safety valve. Close safety valve
Stab inside BOP. Open safety valve
Assist Driller on rig floor
Floor Hand #3
Assist Derrickman on mud pits
3.0
Accumulator Drill
Accumulator drills are designed to verify that the accumulator/closing system is in good
working order and that it is properly sized for the particular blowout preventer stack.
Accumulator performance must be proven with an accumulator drill when the blowout
preventers are first installed (which verifies proper sizing), and every 14 days thereafter in
conjunction with the weekly BOP pressure tests (which checks for hydraulic leaks).
Results of the accumulator drill, including closing times of the rams and annular preventer,
and initial final accumulator pressures are to be reported on the Blowout Preventer Test
and Equipment Checklist. A notation should also be made on the tour report that an
accumulator drill was conducted.
Accumulator drills must be conducted when the drill pipe is not in open hole, but up in the
casing. At least one joint of drillpipe must be in the hole for the pipe rams to close on. The
Saudi Aramco Drilling Foreman and Contract Toolpusher should witness all accumulator
drills, but the Toolpusher is responsible for the actual supervision of the drill. Use the
remote station to close the preventers every other drill.
3.1
Procedure
1)
Turn off all accumulator-pressurizing pumps.
2)
Record the initial accumulator, manifold, and annular pressures.
3)
Close all of the preventers (EXCEPT THE BLIND RAMS). Substitute a reopening of a pipe ram to simulate the blind ram closure when applicable.
Open the HCR valve.
4)
Measure and record the closing times for each preventer with a stopwatch.
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SECTION M – TRAINING AND WELL CONTROL DRILLS
5)
Record the final accumulator, manifold, and annular pressures.
6)
To pass the accumulator test, all BOPs must have closed in less than 30
seconds with at least:
•
1500 psi accumulator pressure remaining (for a 3000 psi accumulator)
Note:
Equipment that does not meet these requirements either has
insufficient capacity, insufficient precharge or needs repair.
Closing time for annular preventers 20" and larger should not
exceed 45 seconds.
7)
Observe the remaining pressure for at least 5 minutes to detect any possible
am piston seal leaks.
8)
Re-open the BOP and turn the accumulator pump(s) back on.
9)
Record the time required to charge system back up (re-charge time).
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SECTION M – TRAINING AND WELL CONTROL DRILLS
Table of Contents
Introduction........................................................................................... M-2
1.0
Pit Drills ...................................................................................... M-2
1.1
1.2
1.3
2.0
3.0
Equipment ....................................................................................... M-2
Frequency........................................................................................ M-2
Procedure ........................................................................................ M-3
Trip Drills .................................................................................... M-4
2.1
Frequency........................................................................................ M-4
2.2
Procedure ........................................................................................ M-4
Accumulator Drill ....................................................................... M-5
3.1
Procedure ........................................................................................ M-5
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SECTION M – TRAINING AND WELL CONTROL DRILLS
Introduction
Shutting-in the well quickly to minimize the size of the influx is a major element of successful well
control. Drilling crews can only get proficient in this action through training and practice. The Drilling
Foreman should ensure that the Contract Toolpusher administers training in the areas of kick
detection and shut-in procedures until proficiency is demonstrated. The training must be repetitive
and frequent enough so that shutting-in the well becomes automatic whenever a kick is detected.
The Drilling Foreman can judge the level of crew shut-in proficiency through the use of pit drills and
trip drills. These drills should always be coordinated with the contract toolpusher. Proper drills and
training can prevent panic and provide for orderly operation if a kick should occur. The following
discussions describe how to conduct the drills and provide a basis for crew evaluation.
1.0
Pit Drills
The pit drill is designed to simulate an actual kick while drilling ahead and is designed as
both a teaching and a testing tool. While drilling ahead, it teaches the drilling crews to be
alert for positive indicators of a kick and provides practice in the proper Saudi Aramco shutin procedures. It also defines and reinforces the assigned duties of every member of the
drilling crew in well control situations. Pit drills are conducted unannounced so that realism
is created and so the crews can be observed under actual operating conditions.
Pit drills train the Driller to be constantly aware of the fluid level in the mud pits and the
return mud flow, much as the driver of an automobile subconsciously checks his
speedometer. This training is expected to prepare the driller to detect a kick at the first
surface indication and with a minimum of reservoir fluid influx. He will then be able to take
correct preventive action, lessening chances of disaster. Pit drills should be supervised by
the Contract Toolpusher and coordinated through the Drilling Foreman.
1.1
Equipment
All equipment required for pit drills is to be installed prior to drilling and kept in good
operating condition. A multi-float pit level indicator and flow show device must be
available. A pre-arranged horn or siren signal is an essential part of the pit drill. At
the signal, each crewmember must go immediately to his assigned post and execute
his assigned duties. The Drilling Foreman should note the times required (in
minutes) for various aspects of the pit drills and record them on the tour report. The
number and times for these drills should be relayed to the office.
1.2
Frequency
One or more pit drills should be conducted each day until the crews become
proficient; then at least twice weekly per crew, or more often if deemed advisable by
the Drilling Foreman. Pit drills should be held at least one each day on offshore
wells, wildcats, and wells where above-normal bottomhole pressure could exist. New
drillers should be given special drills and thorough explanation of this practice. It is
one of the most important safety measures that can be initiated and followed.
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SECTION M – TRAINING AND WELL CONTROL DRILLS
Drills are to be conducted during both routine and special operations. Typical times
would be while drilling, shut down for equipment repairs, logging, waiting on orders,
circulating, the Driller has gone to eat and is replaced by one of his men, the Driller is
talking to someone, or any other time there is open hole and blowout preventers
installed.
1.3
Procedure
1)
The Toolpusher simulates the kick by raising a float in the mud pits or by
raising the arm on the flow show indicator and making a note of the time.
The Drilling Foreman should assist in observing the crew and recording
completion times.
2)
The Driller must detect the kick and sound the alarm. The time of the alarm
should be noted. Upon hearing the alarm, all members of the drilling crew
should immediately execute their assigned duties.
3)
The Driller should prepare to shut in the well using the approved Saudi
Aramco Shut-in Procedure While Drilling. The Drilling Foreman should be
on the rig floor to announce to the driller that the exercise is only a drill and
to stop him before he actually closes the blowout preventers. The time
should be noted when the driller is prepared to shut in the well.
4)
Members of the drilling crew should report back to the rig floor having
completed their assigned duties. These duties may include:
Driller
Shut in the well (simulated)
Record drillpipe pressure and casing pressure
Record time
Measure pit gain
Check choke manifold for valve positioning and leaks
Derrickman
Weigh sample of mud from suction pit
Check volumes of barite, gel, and water on location
Floor Hand #1
Check accumulator pressures and pumps
Check BOP stack for leaks and proper valve positions
Turn on water jets to diesel exhausts
Floor Hand #2
Assist Driller on rig floor
Floor Hand #3
Assist Derrickman on mud pits
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SECTION M – TRAINING AND WELL CONTROL DRILLS
2.0
Trip Drills
The trip drill is designed to train the drilling crews to recognize and respond to kick
indications, which occur while tripping pipe. Like the pit drill, the trip drill is useful for both
teaching and testing purposes. The pit drill also proves that essential detection equipment
is installed and in good operating condition.
The trip drill is supervised by the Contract Toolpusher with the knowledge of the Saudi
Aramco Drilling Foreman. All parts of the well control system must be kept hooked up and
in good condition, ready for drills.
2.1
Frequency
When a new rig is picked-up, trip drills should be conducted during each trip (both
while pulling out and going into the hole) while the bit is up in the casing. When the
crew becomes proficient, trip drills should be conducted at least twice weekly per
crew, conditions allowing.
2.2
Procedure
1)
The Toolpusher simulates the kick by raising a float in the mud pits and
making a note of the time. The Drilling Foreman should assist in observing
the crew and recording completion times.
2)
The Driller must detect the kick and sound the alarm. The time of the alarm
should be noted. Upon hearing the alarm, all members of the drilling crew
should immediately execute their assigned duties.
3)
The Driller should prepare to shut in the well using the approved Saudi
Aramco Shut-in Procedure While Tripping. This will include spacing out
and stabbing/closing the full open safety valve. After the safety valve is
installed and the Driller is ready to close the preventers, the Drilling Foreman
should announce to the Driller that the exercise is only a drill and that it is not
necessary to close the preventers. The time should be noted when the driller
is prepared to shut-in the well.
4)
Members of the drilling crew should proceed with their assigned duties and
report back to the rig floor upon completion. These duties may include:
Driller
Shut in the well (simulated)
Record drillpipe and casing pressure
Record time
Measure pit gain
Check choke manifold for valve positioning and leaks
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Derrickman
Weigh sample of mud from suction pit
Check volumes of barite, gel, and water
Floor Hand #1
Check accumulator pressures and pumps
Check BOP stack for leaks
Turn on water jets to diesel exhausts
Floor Hand #2
Stab safety valve. Close safety valve
Stab inside BOP. Open safety valve
Assist Driller on rig floor
Floor Hand #3
Assist Derrickman on mud pits
3.0
Accumulator Drill
Accumulator drills are designed to verify that the accumulator/closing system is in good
working order and that it is properly sized for the particular blowout preventer stack.
Accumulator performance must be proven with an accumulator drill when the blowout
preventers are first installed (which verifies proper sizing), and every 14 days thereafter in
conjunction with the weekly BOP pressure tests (which checks for hydraulic leaks).
Results of the accumulator drill, including closing times of the rams and annular preventer,
and initial final accumulator pressures are to be reported on the Blowout Preventer Test
and Equipment Checklist. A notation should also be made on the tour report that an
accumulator drill was conducted.
Accumulator drills must be conducted when the drill pipe is not in open hole, but up in the
casing. At least one joint of drillpipe must be in the hole for the pipe rams to close on. The
Saudi Aramco Drilling Foreman and Contract Toolpusher should witness all accumulator
drills, but the Toolpusher is responsible for the actual supervision of the drill. Use the
remote station to close the preventers every other drill.
3.1
Procedure
1)
Turn off all accumulator-pressurizing pumps.
2)
Record the initial accumulator, manifold, and annular pressures.
3)
Close all of the preventers (EXCEPT THE BLIND RAMS). Substitute a reopening of a pipe ram to simulate the blind ram closure when applicable.
Open the HCR valve.
4)
Measure and record the closing times for each preventer with a stopwatch.
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SECTION M – TRAINING AND WELL CONTROL DRILLS
5)
Record the final accumulator, manifold, and annular pressures.
6)
To pass the accumulator test, all BOPs must have closed in less than 30
seconds with at least:
•
1500 psi accumulator pressure remaining (for a 3000 psi accumulator)
Note:
Equipment that does not meet these requirements either has
insufficient capacity, insufficient precharge or needs repair.
Closing time for annular preventers 20" and larger should not
exceed 45 seconds.
7)
Observe the remaining pressure for at least 5 minutes to detect any possible
am piston seal leaks.
8)
Re-open the BOP and turn the accumulator pump(s) back on.
9)
Record the time required to charge system back up (re-charge time).
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SECTION N – HYDROGEN SULFIDE (H2 S) CONSIDERATIONS
Table of Contents
Introduction............................................................................................ N-2
1.0
Fact and Hazards of Hydrogen Sulfide ..................................... N-2
1.1
1.2
1.3
1.4
1.5
1.6
2.0
3.0
4.0
5.0
6.0
Danger Areas....................................................................................N-2
Smell .................................................................................................N-2
Toxicity .............................................................................................N-2
Human Tolerance .............................................................................N-3
Flammability .....................................................................................N-3
Solubility...........................................................................................N-3
Symptoms, First Aid Response, and Safety Precautions ....... N-3
2.1
Symptoms.........................................................................................N-3
2.1.1 Irritation Case ........................................................................N-3
2.1.2 Acute Case ............................................................................N-3
2.2
First Aid ............................................................................................N-5
2.3
Safety Precautions...........................................................................N-5
Equipment, Corrosion and Mud Treatment .............................. N-6
3.1
Equipment ........................................................................................N-6
3.1.1 Ram Type Blowout Preventers...............................................N-6
3.1.2 Annular Preventer..................................................................N-6
3.1.3 Spools and Cross ..................................................................N-6
3.1.4 Gasket Materials....................................................................N-6
3.1.5 Fasteners ..............................................................................N-6
3.1.6 Valves ...................................................................................N-6
3.1.7 Chokes ..................................................................................N-7
3.1.7 Accumulator Units..................................................................N-7
3.1.8 Remote Choke Control Panel.................................................N-7
3.2
Corrosion Reduction and Mud Treatment.......................................N-7
Supervisory Responsibilities in a H2S Area............................. N-8
4.1
Personnel..........................................................................................N-8
4.1.1 Drilling Manager.....................................................................N-8
4.1.2 Drilling Superintendent...........................................................N-9
4.1.3 Wellsite Supervisor (Drilling Foreman) ..................................N-9
4.1.4 Man-in-Charge.......................................................................N-9
4.2
Overall Planning...............................................................................N-9
Additional Equipment and Safety Requirements ................... N-10
Contingency Plan...................................................................... N-11
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SECTION N – HYDROGEN SULFIDE (H2 S) CONSIDERATIONS
Introduction
Drilling into areas where formations contain, or are suspected to contain, hydrogen sulfide requires
that additional precautions to be taken to insure the safety of personnel and equipment. As this gas
is extremely dangerous, all personnel associated with such operations must be thoroughly
indoctrinated in the hazards of hydrogen sulfide.
The degree of danger depends upon the concentration in the air breathed. It must be remembered
that changes in atmospheric conditions, wind, gas composition, etc., can quickly increase the H2S
concentration. Poor ventilation in enclosed spaces around or near a drilling rig where H2S is
present can cause a dangerous concentration of H2S to occur.
The American Petroleum Institute (API) defines H2S wells as those wells capable of
producing atmospheric concentrations of 20 parts per million (ppm) or greater.
1.0
Facts and Hazards of Hydrogen Sulfide
1.1
Danger Areas
H2S is heavier than air and on still days tends to accumulate in low places. However,
if it is sufficiently warmer than the surrounding air, H2S will rise. Thus, even
personnel working in high places (such as the Derrickman), should do so with
caution when there is a possibility of H2S.
1.2
Smell
H2S, in very small concentrations, smells like rotten eggs, but after one sniff in a
sufficiently high concentration the sense of smell is reduced.
After 2-15 minutes exposure of 100-150 ppm concentration, H2S can no longer be
detected by smell. On occasion, this has caused men to die even though they were
in a safe area.
1.3
Toxicity
The maximum allowable concentration of H2S for an eight-hour period is 20 ppm or
0.002% by volume. At 500-700 ppm, a person will lose consciousness and death
could occur in one-half to one hour. At 1000 ppm concentration, unconsciousness
occurs immediately, breathing stops and death occurs within minutes. As stated
earlier, H2S is almost as poisonous as hydrogen cyanide and 5 to 6 times more
dangerous than carbon monoxide.
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SECTION N – HYDROGEN SULFIDE (H2 S) CONSIDERATIONS
1.4
Human Tolerance
A resistance to H2S cannot be developed by working around it, but the effect is also
not cumulative. A person revived after breathing even a high concentration may not
be permanently injured.
1.5
Flammability
H2S is a colorless, flammable gas; its explosive limits (percent by volume in air) are
wide, 4.3% to 45.5%. In contrast, the explosive limits for natural gas range only from
4.8% to 13.5%.
1.6
Solubility
H2S is highly soluble in water and hydrocarbons such as gasoline, kerosene, and
crude oil. At atmospheric pressure, water will absorb approximately three times its
own volume of H2S.
2.0
Symptoms, First Aid Response, and Safety Precautions
2.1
Symptoms
2.1.1
Irritation Case
Exposure to low concentrations (50 to 100 ppm) of H2S will cause
coughing, eye irritation, and loss of sense of smell after 2 to 15
minutes; altered respiration, pain in the eyes and drowsiness after
15 to 30 minutes; and throat irritation after 1 hour. With prolonged
exposure these symptoms gradually increase in severity, and death
occurs in 8 to 48 hours.
2.1.2
Acute Case
Breathing of H2S concentrations of 500 to 1000 ppm or higher will
cause almost immediate loss of consciousness. Breathing will
become hard; cramps, paralysis, and loss of color are other effects.
Table N.1 lists the symptoms of H2S poisoning relative to time of
exposure.
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SECTION N – HYDROGEN SULFIDE (H2 S) CONSIDERATIONS
Table N.1
Toxicity of Hydrogen Sulfide to Humans
H2S
0–2
2 – 15
Concentration
Minutes
Minutes
15 – 30
Minutes
30 – 60
Minutes
Mild conjunctivitis;
respiratory tract
irritation
50 – 100 ppm
Coughing;
Irritation of eyes;
loss of sense of
smell
Loss of sense of
smell
Irritation of eyes;
loss of sense of
smell
100 – 150 ppm
150 – 250 ppm
250 – 350 ppm
Disturbed
respiration; pain in
eyes; sleepiness
Throat and eye
irritation
Throat and eye
irritation
Irritation of eyes
Painful secretion of
tears; weariness
Irritation of eyes;
loss of sense of
smell
Difficult respiration;
coughing; irritation
of eyes
500 – 600 ppm
Coughing; collapse
and
unconsciousness
Respiratory
disturbances;
irritation of eyes;
collapse
Serious eye
irritation; light shy
palpitation of heart;
a few cases of
death
600 – 1500 ppm
Collapse;
unconsciousness
and death
Collapse;
unconsciousness
and death
H2S
Concentration
1 – 4 Hours
4 – 8 Hours
8 – 48 Hours
Increased
symptoms
Hemorrhage and
Death
Serious irritation
effect
Hemorrhage and
Death
350 – 450 ppm
Throat irritation
Increased irritation
of eyes and nasal
tract; pain in head;
weariness
Severe pain in
eyes and head;
dizziness;
trembling of
extremities; great
weakness and
death
50 – 100 ppm
100 – 150 ppm
150 – 250 ppm
250 – 350 ppm
350 – 450 ppm
500 – 600 ppm
600 – 1500 ppm
Salivation and
mucous discharge;
sharp pain in eyes;
coughing
Difficulty breathing;
blurred vision; light
shy
Light shy; pain in
eyes; difficulty
breathing;
conjunctivitis
Dizziness;
weakness;
increased irritation;
death
Death
Death
Hemorrhage and
Death
Death
Data secured from experiences on dogs, which have susceptibility similar to humans.
Source: United States National Safety Council Data Sheet D-chem. 16
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SECTION N – HYDROGEN SULFIDE (H2 S) CONSIDERATIONS
2.2
2.3
First Aid
1)
Remove victim from contaminated area into fresh air as soon as possible.
2)
If breathing has stopped, start artificial respiration immediately.
3)
Keep victim warm and at rest.
4)
Get victim to doctor, but continue artificial respiration enroute if breathing
stops.
5)
If oxygen resuscitator if available, use it in lieu of artificial respiration, as
concentrated oxygen will more quickly oxidize H2S into the blood; however,
begin with artificial respiration rather than wait for resuscitator.
6)
For conjunctivitis (irritation of eyes), wash eyes with 1% boric acid solution,
followed by 10% Argyrol drops. Ophthalmic boric acid ointment will also give
some relief.
Safety Precautions
1)
Keep upwind of H2S source.
2)
Keep proper air breathing apparatus on location, and school all personnel in
its operation and maintenance. H2S drills should begin prior to drilling into
formations containing or possibly containing H2S, so all persons will react
immediately at warning signal.
3)
Have adequate H2S detection devices in key areas around drilling rig, with
responsibilities for monitoring them clearly defined.
4)
Train all personnel in artificial respiration and other first aid techniques
pertaining to treating H2S poisoning.
5)
Restrict drilling locations to only those persons necessary to operations.
Provide adequate warning signs at all access points around the rig.
6)
Install blower fans in main areas to dissipate H2S. Keep ammonia available
to neutralize contaminated areas.
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SECTION N – HYDROGEN SULFIDE (H2 S) CONSIDERATIONS
3.0
Equipment, Corrosion and Mud Treatment
3.1
Equipment
3.1.1
Ram Type Blowout Preventers
The ram bodies must be heat treated and certified for H2S service
by the manufacturer. The following parts must be new parts and
certified for H2S service:
•
•
•
•
•
3.1.2
Bonnet Seals (2)
Connecting Rod Seals (2)
Connecting Rod (heat treated)
Ram Packer
Ram Rear Seal
Annular Preventer
The body must be heat treated and certified for H2S service by the
manufacturer. The rubber element can be natural rubber or Buna N;
both are suitable for H2S service. The upper and lower piston and
piston head seals should be new when the preventer is installed.
3.1.3
Spools and Cross
The spools and crosses must be flanged, low carbon steel types
certified for H2S service, with a maximum Rockwell hardness of
Rc22.
3.1.4
Gasket Materials
New connected 316 stainless steel ring gaskets (API RX or BX)
must be used.
3.1.5
Fasteners
Bolts are to be new, continuous thread steel with American Society
for Testing Materials (ASTM) A-194 Class 2H heavy nuts. Bolting
should be ASTM A-193 B-7, drawn at 1275 °F to 1325 °F to produce
hardness between Rockwell Rc 25, yield strength of 80,000 psi, and
a tensile strength of 100,000 psi.
3.1.6
Valves
Materials for valves in sour gas (H2S) service must conform to the
United States National Association of Corrosion Engineers (NACE)
Standard MR-01-75 (1999 Revision). All valves must be certified for
H2S service by the manufacturer and be flanged.
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SECTION N – HYDROGEN SULFIDE (H2 S) CONSIDERATIONS
3.1.7
Chokes
Chokes must also conform to the general specifications in NACE
Standard MR-01-75 (1999 Revision) and be flanged.
3.1.7
Accumulator Units
Accumulators should be located in a safe place easily accessible to
rig personnel in an emergency. When the accumulator is not
permanently fixed, it should be located a safe distance upwind from
the rig in the direction of the prevailing wind. Each location should be
equipped with a sufficient number of remote control panels so that
the BOP can be controlled from a position upwind of the prevailing
wind.
3.1.8
Remote Choke Control Panel
A remote choke control panel to operate the choke manifold should
be set a safe distance up wind from the rig in the direction of the
prevailing wind.
3.2
Corrosion Reductions and Mud Treatment
The most dramatic type of H2S corrosion is brittle failure of steel. H2S also results in
a normal acid type generalized and pitting corrosion. Sources of H2S include
formation water, make up water, sour crude or gas, electro-chemical reactions,
degradation of sulfur-containing organic compounds, and bacterial activity.
1)
The most important effects of H2S on the mechanical behavior of steel are:
•
•
•
a reduction in ductility
a lowering of the fracture stress
a susceptibility to delayed brittle fracture
These effects are due to the reaction of hydrogen sulfide with steel, which produces
atomic hydrogen. The hydrogen atom, smaller than the lattice structure of steel, can
migrate into steel in a fashion similar to fine sand passing through a coarse sieve.
When two hydrogen atoms come together within the steel lattice, a hydrogen
molecule is formed, causing a 20:1 expansion. Pressure created by the expansion,
added to the stress already present, can cause a brittle material to fail. Thus, higher
strength steels, which exhibit brittleness, are much more susceptible to hydrogen
embrittlement than are lower strength steels.
2)
Tests on hydrogen-charged specimens show that:
•
•
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Steel can lose more than 90% of its ability to withstand a sustained
tensile load.
Embrittlement failure of high-strength material occurs at lower stress
levels than for lower strength material. Tubular materials above
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SECTION N – HYDROGEN SULFIDE (H2 S) CONSIDERATIONS
•
•
approximately 95,000 psi strength are not recommended for H2S
service.
There is little effect on 75,000 psi or lower yield strength steel (Rc22).
Stress accelerates embrittlement failure. As corrosion inhibition
programs are expensive, they should not be undertaken unless
experience has shown them to be needed. When a known or suspected
H2S zone is to be penetrated, minimum protection should be a filming
amine inhibitor added to the mud and applied directly to the drill pipe,
inside and out. Other steps (but not all) can be taken to reduce or
monitor corrosion during drilling operations, as listed below:
– Maintain the pH at 10.0 or higher (particularly with oil base and
invert-emulsion muds, which have the built-in corrosion
inhibition of alkaline water).
– Do not use anionic inhibitors such as chromates.
– Use oxygen scavengers and bactericides only in relatively
constant volume systems (due to high cost).
– Use weight loss coupons to monitor the corrosion rate and
inhibitor effectiveness, if operations are to be prolonged in a
corrosive environment.
Keeping the hydrostatic pressure of the mud above the formation pressure is very
important in H2S bearing formations. Between trips, drill pipe used in H2S areas
should be sprayed or otherwise treated with amine inhibitor. This should also be
done weekly to the outsides of the BOP stack, wellhead and choke manifold. The
method and products for H2S inhibitors are varied, depending on the mud system
and operating conditions. Each condition should be checked with a corrosion
engineer or the product’s representative.
4.0
Supervisory Responsibilities in a H2S Area
Since H2S can be lethal, a clear-cut assignment of responsibilities is extremely important
so that each man on the drilling location knows exactly what to do in an emergency. This
means setting up detailed contingency plans and training programs for safety.
4.1
Personnel
The responsibilities listed below are in addition to the normal duties of the position,
and cover only the requirements for safety in H2S areas.
4.1.1
Drilling Manager
The Drilling Manager has the overall responsibility for operations;
approves the final drilling program, and contingency plan; and must
be sure that the necessary precautions have been taken and that an
emergency involving H2S will bring forth maximum response.
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4.1.2
Drilling Superintendent
The Drilling Superintendent prepares, or has prepared, a detailed
drilling program, a safety program, and contingency plans for all
personnel at the wellsite and surrounding residents. He closely
follows the drilling operations and makes sure that all necessary
precautions have been taken. Whenever possible, he makes an
onsite inspection of equipment and training efforts.
4.1.3
Wellsite Supervisor (Drilling Foreman)
The Wellsite Supervisor does onsite supervision of BOP equipment,
as well as its installation and testing, plus training of rigsite
personnel in BOP drills and safety. He checks to be sure that all
equipment has been certified for H2S service; that safety equipment,
such as self-contained breathing apparatus, is available for all
personnel on location (plus extra for visitors); and that corrosion
inhibitors, blower fans, and all other items required for maximum
safety of the drilling operation are available. He must be thoroughly
familiar with the contingency plan for evacuating surrounding areas,
and should assure himself that Contract Toolpushers, Drillers, and
crews know their responsibilities in emergencies.
4.1.4
Man-in-Charge
The ranking Drilling and Workover man on location is the man-incharge. This designation is essential to the proper execution of a
contingency plan. He is in charge of and responsible for
implementing emergency procedures. The Wellsite Supervisor will
fill this job unless one of his supervisors is on location.
4.2
Overall Planning
Proper well planning in H2S areas includes the same information requirements as for
normal wells plus additional precautionary plans and equipment details that must be
completed prior to drilling. These special items include all area and geological
information; detailed plans for special equipment installation, inspection, and testing;
and safety procedures. These items should be in the contingency plan attached to
the drilling program, and be understood by all concerned with the actual drilling
operations. Specifications for equipment should be stated in the original bid requests
to contractors, since the BOP equipment must be certified for H2S service prior to
spudding the well.
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5.0
Additional Equipment and Safety Requirements
In addition to the requirements set forth in 4.0 of this section, the following points should be
considered:
1)
Tubular goods that could possibly be exposed to H2S (surface and protective casing)
should be inspected and their hardness limited to Rc24 or less. Mill tests and records
may be acceptable, if available, in lieu of inspection in the pipe yard.
2)
Drill string components should be limited to maximum yield strength of 95,000 psi.
This will avoid catastrophic failure due to hydrogen embrittlement should the drilling
mud be contaminated with H2S.
3)
Corrosion inhibitors for drill pipe protection (i.e., filming amines) should be on
location and applied before an H2S zone is penetrated.
4)
Drillpipe, safety valves, and all downhole tools should be certified for H2S service.
5)
Two flare lines, manifolded to the choke manifold degasser and the mud gas
separator, should be installed on opposite sides of the well, perpendicular from the
well to the prevailing winds.
6)
Flare stacks should have Liquid Petroleum Gas (LPG) piped to them and be
furnished with automatic igniters. In addition, a flare gun or rifle with tracer
ammunition should be on location as a backup ignition source.
7)
Flare and other lines subject to corrosion by H2S may be susceptible to some sulfide
stress cracking, if the steel contains residual stresses. Yield strength of steel used
should be limited to approximately 95,000 psi maximum and/or a hardness of Rc22.
Also, working stresses should be limited to 80 percent of the yield strength.
8)
All welds and heat affected zones should be stress relieved and their hardness
limited to Rc22. The use of drill pipe for lines subject to H2S service is not
recommended.
9)
NACE, API, and ASTM specifications are guides for acceptable materials.
10)
Breathing air supply stations, resuscitators, and SCBA units should be located
strategically, one of the latter assigned to each man on location.
11)
H2S alarms will be set at 10 ppm (visual warning) and 20 ppm (audio alarm). Mask
up and emergency evacuation will occur at the sound of the 10 ppm alarm. Further
instructions will be provided in the H2S Contingency Plan.
12)
All personnel should have earplugs, or have their drums checked for puncture by a
doctor.
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SECTION N – HYDROGEN SULFIDE (H2 S) CONSIDERATIONS
6.0
Contingency Plan
A contingency plan and an evacuation plan should be prepared for each well capable of
producing an atmospheric concentration of H2S in excess of 20 ppm. Copies of the plans
should be maintained at the rig site and posted so that it is available to all personnel.
These plans should, at a minimum, include:
1)
Responsibilities of personnel, including the man-in-charge, and should define
essential and non-essential personnel;
2)
Location of residences, businesses, parks, schools, mosques, roads, medical
facilities, etc. in a one mile radius from the well; a larger radius may be required
depending on well conditions, terrain, atmospheric conditions and concentrations of
H2S;
3)
Emergency telephone numbers, including emergency services (ambulance, hospital,
doctor, helicopter, etc.), government agencies, operator and contractor personnel,
and service companies;
4)
Emergency and warning procedures;
5)
Safety equipment and supplies;
6)
Training of personnel.
Additional information on H2S Contingency Plans is provided in the Drilling Manual
(Chapter 8C).
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Table of Contents
Introduction........................................................................................... O-2
1.0
Forces Involved.......................................................................... O-3
1.1
1.2
1.3
2.0
3.0
4.0
5.0
6.0
Downward Force ............................................................................. O-3
Upward Force .................................................................................. O-3
Frictional Force ............................................................................... O-3
Stripping ..................................................................................... O-4
2.1
Preparing to Strip............................................................................ O-4
2.1.1 Float Installed ....................................................................... O-4
2.1.2 Float Not Installed or Leaking................................................ O-4
2.2
Stripping through Annular Preventers ........................................... O-4
2.3
Stripping through Ram Preventers................................................. O-5
2.4
Stripping Considerations................................................................ O-5
2.5
Annulus Pressure Control while Stripping .................................... O-5
2.6
Penetrating the Bubble ................................................................... O-9
Snubbing ................................................................................... O-12
3.1
Equipment ......................................................................................O-12
3.1.1 Conventional Units...............................................................O-12
3.1.2 Hydraulic Units ....................................................................O-13
3.1.3 Auxiliary Equipment .............................................................O-13
3.2
Annulus Pressure Control .............................................................O-14
3.3
Special Considerations..................................................................O-14
3.3.1 Safety..................................................................................O-14
3.3.2 Equipment Layout................................................................O-15
Lubricate and Bleed.................................................................. O-16
Bullheading ............................................................................... O-16
Stripping Example Problem ..................................................... O-17
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Introduction
One of the most serious well control problems to be faced by the rig supervisor is to be off bottom
with a gas kick in the wellbore. Due to the migration of this lighter density fluid, a plan of action
must be implemented promptly and safely. Because each situation has its own peculiarities, no
standard set of procedures can be applied in every case. However, the well-trained Drilling
Foreman has several different techniques at his disposal. These options include:
•
•
•
•
•
•
•
Volumetric Control
Stripping to Bottom
Stripping Using Volumetric Control
Snubbing to Bottom
Circulating Off Bottom through Choke
Lubricate and Bleed
Bullheading
Prior to choosing any of these options, many factors should be considered. Some of the more
obvious ones include:
•
•
•
•
•
•
•
•
•
How Far off Bottom is the Pipe
Current Mud Weight
Density of the Kick
Well Depth
Rate of Migration
Pressure Limitation on Casing Shoe
Potential for Stuck Pipe
Rig Crew Capabilities
Proper Equipment for Operation
And, of course, one of the most obvious questions is...
“Do I fully understand the operation I want to perform?”
For many years the issue of - WHAT TO DO? - has been debated among drilling personnel in
offices, in classrooms and in the field. Many times the problem at hand has several possible
answers and many times it seems that there is no good answer to the problem at all. Two facts
remain constant, however, no matter how severe the situation seems. First, the deeper the pipe in
the wellbore, the more options become available and the better the chance for success. Secondly,
time is of the utmost importance and must be efficiently used for accurate decision-making.
Therefore, the Drilling Foreman must be prepared to assess the situation and respond accordingly.
Stripping and snubbing are specialized operations used to trip tubulars into or out of a pressurized
wellbore through the blowout preventers. The objective of these operations is to return the pipe to
bottom where the hole can be circulated to remove the influx from the wellbore and provide
sufficient hydrostatic pressure necessary to kill the well.
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1.0
Forces Involved
To adequately discuss stripping and snubbing, one must become familiar with the forces
involved. As can be seen in Figure O.1, three main forces act on the tubulars during the
operations.
1.1
Downward Force (Wb)
The downward force (W b) is the most obvious and may
be simply stated as the buoyed weight of the tubulars:
Equation O.1
1.2
Wb
=
W air (489 – MWpcf)
489
Wb
W air
MW
=
=
=
Buoyed Weight (lbs)
Air Weight of the Tubulars (lbs)
Mud Weight (pcf)
Upward Force (Fp)
The upward force on the tubulars (Fp) may be
simplified as the net force exhibited by the well
pressure on the cross-sectional area of the tubular in
the blowout preventer, and is represented by:
Equation O.2
1.3
Fp
=
P
OD
=
=
P
(π xOD2)
4
Shut-in Well Pressure (psi)
OD of the Pipe in the BOP (in)
Figure O.1
Stripping/Snubbing Forces
Frictional Force (Ff)
The third force involved is the frictional force (Ff) due to the movement of the tubular
through the blowout preventer that is closed on the pipe. This force acts in the
direction opposite to the direction of the pipe movement, impeding that movement.
The frictional force is difficult to measure since it is a function of the closing pressure
of the BOP, the type of rubber used in the preventer, the fluid used for lubrication
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and the steel pipe roughness. This force has generally been estimated at between
zero and twenty thousand pounds. However, in practice it has been customary to
slack off the pipe and observe the value on the weight indicator.
2.0
Stripping
If the pipe is off bottom when a kick is taken, stripping back to bottom may be required.
Stripping through BOP equipment can be accomplished by using either the annular
preventers or the ram preventers. Utilizing the ram preventers requires two preventers.
Saudi Aramco’s stack configurations are not designed for stripping through the ram
preventers. Although it can be done, it requires using the lower ram preventer, which is the
master ram of the preventer stack. Stripping through the ram preventer can easily damage
the pressure seal of the ram. If the lower ram is damaged, repair work can only be
performed after the well is killed. We will discuss the process of stripping through rams;
however, it is not recommended as standard practice, unless a ram other than the
lower is used.
If the upward force (Fp) generated by the well pressure acting on the cross-sectional area
of the pipe is greater than the weight of the drill string (Wb), it is necessary to force the pipe
through the preventer. This process is called snubbing. Annular pressure control theory for
snubbing operations is the same as for stripping operations.
2.1
Preparing to Strip
Assuming that the reason the pipe was off bottom was that it was being tripped, the
shut-in procedure resulted in installation and closure of a full opening safety valve on
the drill pipe. Therefore, if the decision is made to strip, then the following
preparatory procedure is used:
2.1.1
Float Installed
1) Open safety valve and insure that the float is holding.
2) Remove the safety valve if float is holding. Once the full open safety
valve goes below the rotary, it no longer functions as a safety valve
and becomes an unnecessary sub.
2.1.2
Float Not Installed or Leaking
1) Install inside BOP on top of full open safety valve.
2) Open full open safety valve and check inside BOP. Leave safety valve
open.
2.2
Stripping through Annular Preventers
Annular preventers are so constructed to allow drill pipe to be stripped through them
and maintain a pressure seal around the pipe. To prevent premature damage to the
rubber sealing while stripping, the closing hydraulic force should be reduced to a
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minimum. This minimum is reached when the bag just starts leaking a slight amount
of mud while will aid in lubrication. This may be hard to monitor unless all the fluid
above the closed annular is drained or removed.
While stripping the tool joint through the preventer, the pressure regulator should
automatically adjust the closing pressure allowing the tool to go through without
undue force. The annular preventer 4-way valve should be inspected to insure that it
does not contain a check valve.
2.3
Stripping through Ram Preventers
Stripping through ram preventers requires the use of two preventers. Also it is
necessary to have a drilling cross with outlets between the preventers. The
drilling cross with outlets is required to allow room between the rams for tool joints
and to provide a means to equalize pressure across the rams. As the pipe is stripped
through one set of rams the other set is opened. When a tooljoint reaches the closed
rams, the other set must be closed and pressure equalized across the first set (then
opened allowing the tool joint to pass). This process is repeated alternating stripping
thorough one ram then the other until the pipe reaches bottom.
2.4
Stripping Considerations
If it is necessary to strip in or out of the hole, it will be necessary to have accurate
pressure gauges, which read in the desired range. It may be advisable to order out a
new packing element for the annular preventer. Extra safety valves and inside
blowout preventers should be available. All drill pipe protectors should be removed.
A method to fill the drillpipe and to monitor volumes of mud is essential. A snubbing
unit will be required if the pipe is out of the hole. All personnel should thoroughly
understand their assignments.
2.5
Annulus Pressure Control while Stripping
The primary idea used in stripping is knowing how much and how fast to bleed mud
from the well during the procedure. In order to minimize the size of the influx, the
Drilling Foreman should have a full understanding of the basic principals of bubble
migration and pipe displacement.
The first thing that must be determined is if the kick is migrating up the hole or not.
This is vital in the decision making process as it will, along with other factors, dictate
whether or not the technique of volumetric control is used during the stripping
operation. This is easily determined by observing the shut-in casing pressure. If,
after the wellbore has stabilized, the casing pressure starts to increase it is safe to
say that the kick is migrating up the hole. Should the casing pressure remain
constant (and is below the pressure needed to fracture the formation at the weak
point in the hole), it is an indication that the kick is migrating very slowly or not at all.
Once it is decided that migration is or is not a major factor, calculations can be made
and action can be taken to begin stripping in the hole. In the event that the kick is not
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migrating up the hole matters are simplified a great deal. As pipe is lowered into the
well the amount of mud to be bled is simply:
Equation O.3
Volume Bled
=
Pipe Capacity + Pipe Displacement
This is easily accomplished by maintaining a constant casing pressure during
stripping. Alternatively, if pressures allow, a length of pipe can be run and then the
volume of mud is bled. In either case it is very important that the mud volume be
accurately measured.
While stripping in the hole, it is necessary to control the well to prevent a pressure
increase due to displacement of mud by the drill pipe and to allow for expansion of
the gas influx. This is down by bleeding off a calculated volume of mud from the
annulus. The following example shows how this can be accomplished:
Assume, in this example that the bit is off bottom and the influx is below the bit. The
influx volume is 20 barrels; the mud weight is 75 pcf. The drill string contains a float
so the drill pipe pressure cannot be read directly on a continual basis. The hole size
is 9-7/8” and the drill pipe is 5” OD. The original shut-in drill pipe pressure and the
shut-in casing pressure are determined to be 520 psi. They are the same because
the influx is below the bit and the hydrostatic head in the drill pipe is equal to the
hydrostatic head in the annulus. The influx cannot be circulated out until the drill pipe
is stripped back to bottom or until the bit is below the influx.
The procedure to follow in string the pipe into the hole and in controlling the well is
listed in the following steps:
1) Start stripping pipe into the hole.
2) Bleed off a mud volume equal to the drill pipe displacement without
allowing casing pressure to drop. This volume is the capacity of the
pipe plus the displacement of the steel in the pipe. The volume bled for
a 93’ stand of 5” drill pipe is:
Volume Bled
=
=
=
=
Capacity + Displacement
(93’ x 0.0178) + 0.711
1.66 + 0.711
2.4 bbls.
3) If the influx is gas the casing pressure will increase, even though mud
is released to allow for the pipe displacement. This increase is due to
gas migration and must be handled by the volumetric control method.
Permit the casing pessure to increase approximately 200 psi. This is a
safety factor to assure the BHP stays above the formation pressure.
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We will use an arbitary safety factor of 180 psi in this example:
Casing Pressure
Note:
=
=
520 + 180
700 psi
It is possible to let the casing pressure rise simply by
not bleeding off mud to allow for pipe displacement.
When casing pressure reaches 700 psi, then
bleeding can begin following the steps below.
4) Keep an accurate record of mud released. Maintain casing pressure at
700 psi while compensating for pipe displacement and bubble
expansions. Nine (9) barrels of mud represents and expansion of 96’
for the gas in the open hole (below the bit) and is equivalent to 50 psi.
Now let the casing pressure increase another 50 psi and continue this
procedure until the top of the expanded gas column is reached.
It is important to note that the gas is in the open hole and not in the 97/8” x 5” annulus; therefore, the capacity factor for the expansion
increment is the open hole capacity factor, not the annulus capacity
factor.
5) When the bit enters the top of the gas column the hydrostatic head in
the annulus will be reduced because the bubble will increase in height.
This will cause a rapid increase in casing pressure. This increase must
be allowed in order to maintain constant BHP. In this example it is
assumed that the bubble was allowed to expand in two 50 psi
increments. This gives the bubble a height in the open hole of 402 ft:
Height of Gas
=
=
=
Volume / Cap. Factor
(20 + 9 + 9) / 0.0945
402 ft.
The casing pressure at this point is 800 psi.
Casing Pressure
=
700 + 50 + 50 = 800 psi
The pipe volume, assuming 300’ of 7” collars, will expand the bubble
to a height of 641 feet.
Annular Capacity
(opposite collars)
=
=
Amount of Gas
(opposite drill pipe) =
=
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0.0471 bbl x 300’
14 bbl
38 bbl - 14 bbl
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Height of Gas
=
=
=
300 ft + 24 bbl/0.0704 bbl/ft
300 + 340.91
641 ft
This corresponds to a decrease in hydrostatic pressure of 96 psi.
Increase in
Height of Gas
Decrease in HP
=
=
641 ft - 402 ft
239 ft
=
=
=
239 ft x (mud gradient-gas gradient)
239 x (0.53 - 0.12)
96 psi
To compensate for this decrease in HP the casing pressure must be
followed to increase 96 psi to 896 psi without bleeding off any mud in
excess of the pipe volume.
6) Continue stripping in hole and bleeding off mud to allow for the pipe
volume.
7) Compensate for gas migration by allowing expansion. Remember that
the gas is now in the annulus and a 50 psi pressure increment
corresponds to 6-3/4 bbls of mud.
Once the gas is above the bit, it can be circulated out using the
Driller’s method before stripping is continued. This would be for the
person in charge of the operation to decide upon.
The above example can be tabulated as shown in Table O.1.
Table O.1
Cumulative
Stands
Stripped
1
2
15
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Cumulative
Volume
Displaced (bbls)
2.4
4.8
36.0
O-8
Cumulative
Volume
Bled (bbls)
3.0
5.2
45.0
Casing
Pressure
(psi)
700
700
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After 15 stands, the difference in volume bled (to maintain 700 psi
casing pressure) and theoretical volume displaced is 9 barrels, or 50
psi. Therefore, let the casing pressure rise to 750 psi to compensate
for the lost hydrostatic pressure, and then continue with the bleed-offs.
Table O.1 (continued)
Cumulative
Stands
Stripped
16
17
18
19
20
21
30
2.6
Cumulative
Volume
Displaced (bbls)
38.4
40.8
43.2
45.6
48.0
50.4
72.0
Cumulative
Volume
Bled (bbls)
50.0
81.0
Casing
Pressure
(psi)
710
720
730
740
750
750
750
Penetrating the Bubble
During the course of taking a kick while the pipe is off bottom several questions
arise. Questions such as depth of the kick zone and location of the kick in relation to
the bit need to be considered. Many times quite a few stands of pipe are pulled
before the kick is detected and the kick will be below the bit. When this is the case
there will be a time during the stripping operation that the drillstring will penetrate the
bubble. When this happens, certain adjustments to the procedure being used must
be made in order to maintain a constant bottomhole pressure. For a given kick
volume, the height occupied in the open hole will be significantly less than the height
occupied in the drillstring by hole annulus. As a result, in order to satisfy the basic
equation given below:
Equation. O.4
BHP
=
HPm + HPk + SP
BHP
HPm
HPk
SP
=
=
=
=
Bottomhole Pressure (psi)
Hydrostatic Pressure of the Mud (psi)
Hydrostatic Pressure of the Kick Fluid (psi)
Surface Pressure (psi)
where:
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When the hydrostatic pressure changes due to a change in the height of the bubble,
the surface (i.e., casing) pressure must also change. The amount of surface
pressure change needed to offset the change in hydrostatic is simplified by:
Equation O.5
∆Surface Pressure =
(PGM - PGG) x (∆H)
where:
PGM
PGK
∆H
= Pressure Gradient of the Mud
= Pressure Gradient of the Kick Fluid
= Kick Height in the Drillstring by Hole
Annulus – Kick Height in the Open Hole
When the bubble moves into a different hole geometry, the choke will have to be
adjusted so that the casing pressure rises or declines by this amount; then this new
value is used as a new starting point for the rest of the stripping operation. An
estimation of the point in time when the drillstring will penetrate the bubble can be
made so that the Drilling Foreman will be ready to make the choke adjustment. In
order to determine when this will happen, two calculations must be made. First, an
estimation of the bubble migration rate (if any) can be calculated from the rise in
casing pressure by:
Equation O.6
∆CP
MR
=
_______________
.007 x MW x Hrs
where:
MR
∆CP
MW
Hrs
=
=
=
=
Migration Rate (ft/hr)
Change in Casing Pressure (psi)
Mud Weight (pcf)
Time of Casing Pressure Change (hrs)
Once the calculation has been made, the migration can be drawn graphically as in
Figure O.2.
The plot of depth vs. time can be used to determine where the bubble is in the hole
at any time. Secondly, an estimation of tripping speed must be made. This is a
subjective number also expressed in ft/hr. Plotting the trip speed on the same graph
as the migration as in Figure O.2 shows the two lines intersecting. The point at the
intersection gives not only the time when the bit penetrates the bubble but also an
approximation of the depth. The problem can also be solved mathematically by:
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Figure O.2
Bubble Penetration
D = Depth pipe intercepts bubble
T = Time pipe intercepts bubble
Bubble
Depth
Depth x 1000 (ft)
D
Bit
Depth
T
Equation. O.7
DBubble - DBM
T
=
MR + TS
where:
DBubble
DBM
MR
TS
= Depth of the Bubble (ft)
= Depth of the Bit (ft)
= Migration Rate (ft/hr)
= Tripping Speed (ft/hr)
Either solution will yield the same result. Caution should be used however, due to the
fact that this is a simplified solution to the problem. Factors such as bubble
expansion, changing bubble density and others are not taken into consideration.
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3.0
Snubbing
When the net upward force is greater
than the net downward force, a
condition known as pipe light exists. In
order to return the pipe to bottom so
that the well can be killed, it is
necessary to force, or snub the pipe in
the hole. During snubbing operations,
the pipe is pushed in the hole while the
well has pressure on it. Many times the
force required to push the pipe in is
significant due to higher than normal
well pressures. As a result, more
blowout prevention equipment is usually
installed. However, not all snubbing
operations require elaborate hookups.
Nevertheless, as in all well control
situations, a few basic principals govern
and should be utilized in all snubbing
work.
3.1
Figure O.3
Conventional Snubbing Unit
Equipment
All snubbing units require two
sets of slips for handling pipe.
One set, called the traveling slips,
is used to actually force the pipe
into the wellbore. The second set,
called stationary slips, are used to
hold the pipe in place while the
travelling
slips
are
being
repositioned. There are two
different types of snubbing units
widely used in industry today.
Both types employ traveling and
stationary slips.
3.1.1
Conventional Units
One of the first kinds of snubbing units used is what is known as the
conventional snubber. In a conventional unit, the rig’s hoisting
equipment is used in combination with the rig’s blowout prevention
equipment. The stationary slips are usually attached to the BOP
stack and the traveling slips are used in conjunction with a pulley
system and the blocks. Raising the traveling block causes the
traveling snubbers that grip the pipe to move down, forcing the pipe
in the hole. After each downward stroke, the stationary snubbers
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grip the pipe until the traveling
snubbers are moved to get
another bite. The procedure is
repeated until the snubbing
force is no longer needed.
Figure
O.3
shows
a
conventional snubbing unit
hookup.
3.1.2
Figure O.4
Hydraulic Snubbing Unit
Hydraulic Units
Hydraulic units perform the
same
function
as
conventional units in the
same manner. Once again,
the two sets of slips are used
in alternating fashion until the
net
downward
force
overcomes the net upward
force. Hydraulic units use
hydraulic pistons, or jacks, to
move the traveling slips and
force the pipe into the hole.
These snubbers have gained
popularity in recent years, as
they do not require that a rig
be on the well. All of the
functions of the unit and BOP
stack are operated from the
workbasket on top of the jack.
The main disadvantage of the
hydraulic unit is that it takes
quite a bit more time to rig up
and
usually
requires
additional blowout preventers.
Figure O.4 shows a modern
hydraulic snubber.
3.1.3
Auxiliary Equipment
There is a wide range of
equipment that is used in
conjunction with snubbing
operations that should be
mentioned. One of the most
important is the stripping
rubber that is used on many
snubbing jobs. When wellbore
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pressures are not too high, it is common to use a stripping rubber as
the main well control device instead of stripping through the annular
or ram-to-ram. The rubber is sized to the pipe being run and sits in a
housing on top of the BOP. As this is one of the most important
pieces of equipment on location, care should be taken to insure that
the rubber and its housing are up to the specifications required of
the rest of the BOP stack and that the rubber is frequently checked
for wear. Many snubbing hookups have a great deal of valves and
chokes rigged up in the stack. Often, these valves are hydraulically
operated plug valves and the chokes are positive type chokes.
Regardless of the type of valve or choke, all of the equipment should
conform to Saudi Aramco and API specifications.
3.2
Annulus Pressure Control
At some point in time, the net forces will change direction and be downward. This is
the condition previously referred to as pipe heavy and the snubbing force is no
longer needed. This point is called the balance point and can be calculated by:
Equation O.8
Fp
L
=
AW x BF
where:
L
Fp
AW
BF
= Length of Pipe (ft)
= Upward Force (lbs)
= Unit Air Weight of Pipe (lbs/ft)
= Buoyancy Factor
Sound judgement must be used when applying the equation because such factors
as bubble migration and bubble penetration and their relation to casing pressure
should be considered.
3.3
Special Considerations
There are many uses for hydraulic snubbing units today. In fact, many people know
the equipment as hydraulic work-over rigs. As a result, the number of different well
control situations that can arise from the various workover situations are too
numerous to detail. However, there are guidelines which apply to almost all snubbing
unit hookups.
3.3.1
Safety
One of the main responsibilities of the Saudi Aramco Drilling
Foreman is to provide a safe work environment. Snubbing
operations are inherently dangerous. Any time that pipe is being
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forced into the hole, safety becomes a major concern. Several items
need to be examined when planning and rigging up to perform a
snubbing operation. In addition to the purpose of the snubbing
operation, be it on a drilling rig or a work-over, there is an extensive
list of questions that need to be addressed by the Saudi Aramco
personnel involved or the snubbing contractor in order to insure a
safe operation. Some of the questions to consider:
•
•
•
•
•
•
•
•
•
Snubbing force required
BOP stack configuration and control station location
Escape route for personnel working in the basket
Shutdown system for any nearby producing wells
Structural support and guidelines for snubbing unit
Quantity of spare parts required
Firefighting equipment required
H2S contingency plans
Applicable governmental regulations
The best way to insure a safe snubbing operation is to do adequate
planning with the snubbing contractor involved. Each snubbing
contractor has their own set of safety procedures that have evolved
through years of experience that should be discussed and reviewed
before the job begins. API RP 54 has a few suggestions as to safety
equipment used for snubbing, and should be consulted during the
planning phase.
3.3.2
Equipment Layout
Another important consideration while rigging up is the equipment
layout. The modern hydraulic snubbing units in use today require
quite a bit of equipment to operate. As a result, in confined areas it is
important that the equipment be properly located for accessibility.
BOP control stations and closing units should be a sufficient
distance from the well. Engines and hydraulic power packs need to
be strategically located away from flow lines and the well. Pumping
units for well control need to be spotted so that the snubbing unit
operator can clearly see the pump operator. All flow lines and
pressure release lines need to be given special attention during
rigging up so that other equipment does not interfere with well
control operations. API RP 54 provides some good suggestions but
pre-job planning is usually the best way to optimize the wellsite
space available.
Many times the snubbing unit is rigged up very high in the air. This
means that communication with the Drilling Foreman on location, as
well as other personnel involved in the operation, is difficult at times.
Special consideration should be given to providing a means of
communicating with the personnel in the snubbing basket. This will
insure a much safer and efficient operation for all.
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4.0
Lubricate and Bleed
Often during major well control situations there comes a time when gas has reached the
surface. This is the point in time that the surface pressure is the highest due to reduced
hydrostatic pressure in the well. When this occurs, the best way to remove the gas is by
circulating. However, circulation is not always possible and the well must be lubricated.
The theory involved in lubricating and bleeding is the same as that for volumetric control.
Surface pressure is replaced with hydrostatic pressure by pumping mud into the well on
top of the gas. The gas and mud are allowed to change place in the hole and some of the
surface pressure is bled off. The ‘lubricate and bleed’ procedure is listed in the following
steps.
1)
2)
3)
4)
5)
5.0
Calculate the hydrostatic pressure that will be exerted by 1 barrel of mud.
Slowly pump a given volume of mud into the well. The amount chosen will depend
on many different well conditions and may change throughout the procedure. The
rise in surface pressure can be calculated by applying Boyle's Law (P1V1 = P2V2)
and realizing that for every barrel of mud pumped into the well the bubble size
decreases by 1 barrel.
Allow the gas to migrate back to the surface. This step could take quite some time
and is dependent on a number of factors such as mud weight and viscosity.
Bleed gas from the well until the surface pressure is reduced by an amount equal to
the hydrostatic pressure of the mud pumped in. It is very important to bleed only gas.
If at any time during the procedure mud reaches the surface and starts bleeding, the
well should be shut in and gas allowed to migrate.
Repeat Steps 4.2 through 4.4 until all of the gas has been bled off or a desired
surface pressure has been reached.
Bullheading
Another specialized well control technique is bullheading. Bullheading has been used for a
number of reasons for quite some time and is still one of the primary well control methods
for certain situations. A number of questions arise when considering bullheading. Concerns
such as those listed below and others should be addressed before any bullheading-type
well control procedure is attempted. The important thing to remember about bullheading is
that it IS NOT a constant bottomhole pressure method. As a result, there are inherent
complications and dangers when using this technique.
•
•
•
•
•
•
•
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Casing shoe strength
Relative permeability of formations to oil, gas, water and mud
Surface pressure limitations
Pump rate
Bubble migration rate
Volume of mud to pump
Fluid weight and type used
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6.0
Stripping Example Problem
“Ali Al-Qahtani”, the Saudi Aramco Drilling Foreman, had a bad feeling about this trip. He
knew when he left bottom that he was in a transition zone and that the well was stable but
something just didn't feel right. After watching the crew pull 30 stands and carefully
monitoring his fill-ups, Ali began to feel a little better. But when the crew started to install
the pipe wiper rubber they noticed that the well was flowing. Ali had the crew stab the
safety valve, quickly closed the annular preventer and recorded the following information:
Hole Size:
Drill Pipe:
Hole Capacity:
Ann. Capacity:
Shoe Test:
Casing Shoe:
8-1/2”
5” NC 50
0.0702 bbl/ft
0.0459 bbl/ft
116 pcf
4500’ MD/TVD
Kick Size:
Mud Weight:
TD:
Bit Depth:
SICP:
15 bbl
87 pcf
11,500’ MD/TVD
8700’
450 psi
Ali knew he would have to strip back to bottom to kill the well. He had the crew install the
inside BOP and open the safety valve. Once he was sure that the inside BOP was holding
Ali went about the business of determining his safety factor for volumetric control.
Shoe Pressure
or,
= (TVDshoe x Mud Weight x 0.007) + SICP
= (4500 x 87 x 0.007) + 450
= 3190 psi
He knew the shoe would break down at a pressure of,
Shoe Fracture
Pressure
= (TVDshoe x Shoe Test x 0.007)
= (4500 x 116 x 0.007)
= 3654 psi
Ali realized that he had plenty of room for a 200 psi safety factor (3654 - 3190 = 463 psi).
He calculated his pressure increment by dividing the safety factor by 3,
Pressure
Increment
200 psi
=
3
= 67 psi, or 70 psi
Ali then had to calculate his mud increment. After a moment of thought, he decided that he
should use the hole capacity factor in the equation because the kick was well below the bit.
Mud
Increment
PI x HCF
=
MW x 0.007
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Mud
Increment
70 x 0.0702
=
87 x 0.007
= 8.1 bbl
Ali knew that as long as the kick was below the bit for every 8.1 bbl he bled off, the
hydrostatic pressure is reduced by 70 psi.
After checking the casing pressure gauge and seeing that it read only 460 psi Ali knew that
he had time to do some more calculations. He realized that he needed to know when
during the stripping operation he would intercept the bubble so that he could change his
mud increment. Ali got with his toolpusher and they decided that the crew would strip into
the hole at a rate of 1000 feet per hour. He then checked the casing gauge and saw that
the casing pressure was now 530 psi. He looked at his watch and saw that it had been 10
minutes since the well had stabilized.
The calculation was then easy,
Change in Casing Pressure
Migration Rate
=
0.007 x Mud Weight x Hours
530 - 450
=
0.007 x 87 x 0.167
= 787 ft/hr
Ali decided to use 800 ft/hr as the migration rate and 1000 ft/hr as the stripping speed. He
then solved for the time of bubble penetration.
Depthbubble - Depthbit
Time
=
Migration Rate + Trip Speed
11500 - 8700
=
800 + 1000
= 1.55 hours
So after 1-1/2 hours the bubble would be in the drillpipe by hole annulus and a different
mud increment would have to be calculated.
Mud
Increment
PI x ACF
=
0.007 x MW
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SECTION O – STRIPPING AND SNUBBING
70 x 0.0459
=
0.007 x 87
= 5.3 bbls
The volume of mud to be bled due to pipe displacement and capacity was the only
calculation left for Ali. He looked up the factors in his well control manual.
Pipe Capacity
= 0.0178 bbl/ft X 93 ft/stand
= 1.655 bbl/stand capacity
Pipe Displacement = 0.607 bbl/93 ft stand
Volume to Bleed
= Capacity + Displacement
= 1.655 + 0.607
= 2.262 bbl/stand
Ali felt that he was now ready to strip in the hole. He looked over all of his calculations and
realized that he had forgotten to include the change in surface pressure due to bubble
elongation when the bit entered the bubble. The surface pressure would have to increase
to make up for the lost hydrostatic when the kick entered a new hole geometry. Ali knew
that he needed to decide on a reasonable gradient for the kick. He settled on 0.12 psi/ft.
Calculation of the kick height in the open hole and in the annulus also had to be done.
Kick Height
in Open Hole
Kick Size
=
Hole Capacity Factor
15 bbl
=
0.0702 bbl/ft
= 214 ft
Kick Height in
Drillpipe by Hole
Annulus
Kick Size
=
Ann. Capacity Factor
15 bbl
=
0.0459 bbl/ft
= 327 ft
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SECTION O – STRIPPING AND SNUBBING
Ali now substituted the proper values into the equation.
∆Surface
Pressure
= (PGM - PGG) x (∆H)
= [(87 x 0.007) - 0.12] x (327 - 214)
= 55.3 psi
After stripping for approximately 1-1/2 hours not only would the mud increment change
from 8.15 bbl to 5.33 bbl but the casing pressure would also need to rise by 55 psi. This
would insure a constant bottomhole pressure.
Ali headed for the rig floor. He read the casing pressure and saw that it was 650 psi. Ali
allowed surface pressure to increase to allow for a 200 psi safety factor. After the safety
meeting, Ali adjusted the pressure on his annular preventer and the crew began stripping
into the hole.
Ali kept the data from the stripping in a chart in his pipe book.
Cumulative
Stand
Stripped
Casing
Pressure
(psi)
Cumulative
Cumulative Volume
Time
Volume
Volume
(bbls)
(hrs/min)
Displaced
Bled
(bbls)
(bbls)
3
650
6.8
9.1
2.3
2:18
6
650
13.6
18.2
4.6
2:35
9
650
20.4
27.3
6.9
2:52
***Allow casing pressure to rise 70 psi pressure increment through migration.
12
720
27.2
35.2
8.0 / 0.0
3:10
15
770
34.0
42.0
8.0 / 0.0
3:27
18
770
40.8
51.1
10.3 / 2.3
3:45
21
770
47.6
63.0
15.5 / 5.2
4:03
***Allow casing pressure to rise 70 psi pressure increment through migration.
24
840
54.4
72.0
17.7 / 2.2
4:20
27
840
61.2
84.0
23.0 / 5.3
4:37
30
840
68.0
93.0
25.1 / 2.1
4:54
Note how after 1-1/2 hours Ali let the casing pressure rise 50 psi for hole geometry change
and made himself a note to change his mud increment from 8 bbl to 5 bbl. Once he got
safely back on bottom, Ali circulated the kick out using the Driller's Method. He conditioned
the mud and was ready to try the trip all over again.
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SECTION P – TABLES AND CHARTS
Table of Contents
Table P.1 Capacities and Displacement of Drillpipe.......................... P-2
Table P.2 Capacities and Displacement of Drill Collars .................... P-4
Table P.3 Capacities and Displacement of ‘Hevi-Wate’ Drillpipe...... P-5
Table P.4 Capacity of Hole................................................................... P-6
Table P.5 Pump Displacement............................................................. P-7
Pc Max (Part 1) for Driller's Method ...................................................... P-9
Pc Max (Part 2) for Driller's Method .................................................... P-10
Pc Max (Part 1) for Engineer's Method ............................................... P-11
Pc Max (Part 2) for Engineer's Method ............................................... P-12
Volume of Gas at Surface (Driller's and Engineer's Method)........... P-13
Chart Equations for Pc Max Determination....................................... P-14
1.0
2.0
3.0
Driller’s Method Worksheet ....................................................... …P-14
Engineer’s Method Worksheet....................................................... P-14
Volume of Gas at Surface .............................................................. P-14
Theoretical Equations for Pc Max Determination ............................. P-15
1.0
Engineer’s Method ......................................................................... P-15
2.0
Driller’s Method .............................................................................. P-15
3.0
Miscellaneous Supporting Equations ........................................... P-15
4.0
Nomenclature for Theoretical Equations ...................................... P-16
Table P.6 BOP Opening and Closing Volumes ................................ P-17
Ram Type Blowout Preventers ........................................................... P-17
Koomey.................................................................................................................... P-17
Hydril….................................................................................................................... P-17
Bowen Tools, Inc..................................................................................................... P-19
Cameron Iron Works ................................................................................. P-19
Guiberson Division of Dresser Industries.............................................................. P-22
Shaffer.. ................................................................................................................... P-22
Annular Blowout Preventers .............................................................. P-24
Hydril……................................................................................................................ .P-24
Cameron Iron Works ............................................................................................... P-25
Shaffer.. ................................................................................................................... P-25
Regan……................................................................................................................ P-25
Hydraulically Operated Valves ........................................................... P-27
Cameron Iron Works ............................................................................................... P-27
McEvoy Oilfield Equipment..................................................................................... P-27
Shaffer.. ................................................................................................................... P-28
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SECTION P – TABLES AND CHARTS
Table P.1
Capacities and Displacement of Drillpipe
Generalized Equations
(Internal Diameter)2
Internal Capacity = ------------------------1029
(Hole Diameter)2 - (Drillpipe OD) 2
Annular Capacity = --------------------------------------------1029
DRILL PIPE
Pipe Size
OD
(inches)
Nominal
Weight
(lb / ft)
Internal
Capacity
(bbl / ft)
Displacement
(bbl / 93 ft
stand)
2-7/8
10.4
0.0045
0.329
4-1/8
4-1/2
4-5/8
4-3/4
5-7/8
6
6-1/8
6-1/4
6-1/2
6-3/4
0.0085
0.0116
0.0128
0.0139
0.0255
0.0269
0.0284
0.0299
0.0330
0.0362
3-1/2
9.5
13.3
15.5
0.0087
0.0074
0.0066
0.300
0.417
0.495
4-1/2
4-5/8
4-3/4
5-7/8
6
6-1/8
6-1/4
6-1/2
6-3/4
8-1/2
0.0078
0.0089
0.0100
0.0216
0.0231
0.0245
0.0260
0.0291
0.0324
0.0583
4
14.0
0.0108
0.440
5-7/8
6
6-1/8
6-1/4
6-1/2
6-5/8
7-7/8
0.0180
0.0194
0.0209
0.0224
0.0255
0.0271
0.0447
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P-2
ANNULUS
Hole
Diameter
(inches)
Annular
Capacity
(bbl / ft)
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SECTION P – TABLES AND CHARTS
Table P.1
Capacities and Displacement of Drillpipe (continued)
DRILL PIPE
Pipe Size
OD
(inches)
ANNULUS
Hole
Diameter
(inches)
Nominal
Weight
(lb / ft)
Internal
Capacity
(bbl / ft)
Displacement
(bbl / 93 ft
stand)
4-1/2
16.6
20.0
0.0142
0.0129
0.507
0.633
6-1/2
6-3/4
7-7/8
8-3/8
8-1/2
8-3/4
9-1/2
9-5/8
9-7/8
12-1/4
17-1/2
0.0214
0.0246
0.0406
0.0485
0.0505
0.0547
0.0680
0.0703
0.0751
0.1261
0.2778
5
16.3
19.5
25.6
0.0189
0.0178
0.0155
0.503
0.607
0.813
8-3/8
8-1/2
8-3/4
9-1/2
9-5/8
9-7/8
12-1/4
17-1/2
0.0439
0.0459
0 0501
0.0634
0.0657
0 0704
0 1215
0.2733
5-1/2
21.9
24.7
0.0222
0.0212
0.671
0.763
8-3/8
8-1/2
8-3/4
9-1/2
9-7/8
12-1/4
17-1/2
0.0388
0.0408
0.0450
0.0583
0.0653
0.1164
0.2682
Note:
Annular
Capacity
(bbl / ft)
The internal capacity, displacement, and annular capacity values listed in Table
P.1 make no allowances for tool joint dimensions and should NOT be used for
critical displacement operations such as cement squeezing.
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SECTION P – TABLES AND CHARTS
Table P.2
Capacities and Displacement of Drill Collars
DRILL COLLAR
Collar Size
Nominal
OD
Weight
(inches)
(lb / ft)
Internal
Capacity
(bbl / ft)
Displacement
(bbl / 93 ft
stand)
ANNULUS
Hole
Diameter
(inches)
Annular
Capacity
(bbl / ft)
4-1/8 x 2
35
0.0039
1.18
6-1/8
0.0199
4-3/4 x 2-1/4
47
0.0049
1.58
5-7/8
6-1/8
6-1/2
6-3/4
0.0116
0.0145
0.0191
0.0224
6 x 2-1/4
83
0.0049
2.80
7-7/8
8-1/2
8-3/4
0.0253
0.0352
0.0394
6-1/4 x 2-13/16
83
0.0077
2.82
7-7/8
8-3/8
8-1/2
8-3/4
9-7/8
0.0223
0.0302
0 0323
0.0364
0.0568
6-1/2 x 2-13/16
92
0.0077
3.10
8-1/2
8-3/4
9-7/8
0.0292
0.0333
0.0537
6-3/4 x 2-13/16
101
0.0077
3.40
8-1/2
8-3/4
9-7/8
0.0259
0.0301
0.0505
7 x 2-13/16
110
0.0077
3.71
8-3/4
9-7/8
0.0268
0.0471
7-3/4 x 2-13/16
139
0.0077
4.71
9-7/8
12-1/4
0.0364
0.0875
8x3
147
0.0087
4.97
9-7/8
12-1/4
17-1/2
0.0326
0.0836
0.2354
9x3
192
0.0087
6.51
12-1/4
17-1/2
0.0671
0.2189
10 x 3
243
0.0087
8.22
12-1/4
17-1/2
0.0487
0.2004
Table P.3
Capacities and Displacement of ‘Hevi-Wate’ Drillpipe
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SECTION P – TABLES AND CHARTS
‘HEVI-WATE’ DRILLPIPE
Pipe Size
Nominal
(OD)
Weight
(inches)
(lb / ft)
25.3
3-1/2
ANNULUS
Hole
Diameter
(inches)
Internal
Capacity
(bbl / ft)
Displacement
(bbl / 93 ft
stand)
Annular
Capacity
(bbl / ft)
0.0042
0.856
4-1/2
4-5/8
4-3/4
5-7/8
6
6-1/8
6-1/4
6-1/2
6-3/4
8-1/2
0.0078
0.0089
0.0100
0.0216
0.0231
0.0246
0.0261
0.0292
0.0324
0.0583
4
29.0
0.0065
1.006
5-7/8
6
6-1/8
6-1/4
6-1/2
6-5/8
0.0180
0.0194
0.0209
0.0224
0.0255
0.0271
4-1/2
41.0
0.0074
1.388
6-1/2
6-3/4
7-7/8
8-3/8
8-1/2
8-3/4
9-1/2
9-5/8
9-7/8
12-1/4
17-1/2
0.0214
0.0246
0.0406
0.0485
0.0505
0.0547
0.0680
0.0704
0.0751
0.1262
0.2779
5
49.3
0.0088
1.670
8-3/8
8-1/2
8-3/4
9-1/2
9-5/8
9-7/8
12-1/4
17-1/2
0.0439
0.0459
0.0501
0.0634
0.0657
0.0705
0.1215
0.2733
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P-5
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SECTION P – TABLES AND CHARTS
Table P.4
Capacity of Hole
Diameter of Hole
(inches)
Capacity
(gals / ft)
Capacity
(bbls / ft)
Capacity
(ft / bbl)
2-3/4
3
3-1/4
4
4-1/8
4-1/4
4-3/8
4-5/8
4-5/8
4-3/4
4-7/8
5
5-1/4
5-1/2
5-3/4
5-7/8
6
6-1/8
6-1/4
6-1/2
6-5/8
6-3/4
7-1/2
7-5/8
7-3/4
7-7/8
8
8-3/8
8-1/2
8-5/8
8-3/4
9
9-1/4
9-1/2
9-5/8
9-3/4
9-7/8
12
12-1/8
12-1/4
12-3/8
15
17-1/2
.3086
.3672
.4310
.6528
.6942
.7370
.7809
.8262
.8727
.9205
.9696
1.0200
1.1246
1.2342
1.3490
1.4082
1.4688
1.5306
1.5938
1.7238
1.7907
1.8590
2.2950
2.3721
2.4506
2.5302
2.6112
2.8617
2.9478
3.0351
3.1238
3.3048
3.4910
3.6822
3.7797
3.8786
3.9786
5.8752
5.9982
6.1226
6.2481
9.1800
12.4950
.0073
.0087
.0103
.0155
.0165
.0176
.0186
.0197
.0208
.0219
.0231
.0243
.0268
.0294
.0321
.0335
.0350
.0365
.0380
.0411
.0427
.0443
.0547
.0565
.0584
.0603
.0622
.0682
.0702
.0723
.0744
.0787
.0832
.0877
.0900
.0924
.0948
.1399
.1429
.1458
.1488
.2187
.2976
136.0661
114.3333
97.4201
64.3125
60.4738
56.9689
53.7600
50.8148
48.1052
45.6066
43.2987
41.1600
37.3333
34.0165
31.1229
29.8126
28.5833
27.4286
26.3424
24.3550
23.4446
22.5844
18.2933
17.6985
17.1322
16.5926
16.0781
14.6705
14.2422
13.8324
13.4400
12.7028
12.0263
11.4017
11.1074
10.8245
10.5522
7.1458
6.9993
6.8571
6.7193
4.5733
3.3600
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SECTION P – TABLES AND CHARTS
Table P.5
Pump Displacement
DUPLEX PUMPS
Barrels per Inch of Stroke
----------------------------------------------Fluid Piston Rod Diameter (inches) --------------------------------------------Liner
Size
1-1/2
1-3/4
1-7/8
2
2-1/4
2-3/8
2-1/2
2-3/4
3
3-1/8
3-1/4
0.00360
0.00419
0.00482
0.00548
0.00619
0.00694
0.00773
0.00856
0.00943
0.01034
0.01129
0.01228
0.01332
0.01439
0.01550
0.00460
0.00486
0.00535
0.00606
0.00681
0.00760
0.00843
0.00930
0.01021
0.01116
0.01215
0.01318
0.01426
0.01537
0.00398
0.00461
0.00528
0.00599
0.00674
0.00753
0.00836
0.00923
0.01014
0.01109
0.01208
0.01311
0.01418
0.01530
00.0391
0.00453
0.00520
0.00591
0.00666
0.00745
0.00828
0.00915
0.01006
0.01101
0.01200
0.01303
0.01411
0.01522
0.00574
0.00649
0.00728
0.00811
0.00898
0.00989
0.01084
0.01183
0.01296
0.01393
0.01505
0.00564
0.00639
0.00718
0.00801
0.00888
0.00979
0.01074
0.01174
0.01277
0.01384
0.01495
0.00555
0.00629
0.00708
0.00791
0.00878
0.00969
0.01064
0.01164
0.01267
0.01374
0.01485
0.00533
0.00608
0.00687
0.00770
0.00857
0.00948
0.01043
0.01142
0.01246
0.01353
0.01464
0.00510
0.00585
0.00664
0.00747
0.00834
0.00925
0.01020
0.01119
0.01222
0.01330
0.01441
0.00498
0.00572
0.00651
0.00734
0.00821
0.00912
0.01008
0.01107
0.01210
0.01317
0.01429
0.00485
0.00560
0.00638
0.00721
0.00808
0.00900
0.00995
0.01094
0.01197
0.01304
0.01416
(inches)
3-1/2
3-3/4
4
4-1/4
4-1/2
4-3/4
5
5-1/4
5-1/2
5-3/4
6
6-1/4
6-1/2
6-3/4
7
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P-7
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SECTION P – TABLES AND CHARTS
Table P.5
Pump Displacement (continued)
TRIPLEX PUMPS
Liner Diameter
(inches)
3-1/2
3-3/4
4
4-1/4
4-1/2
4-3/4
5
5-1/4
5-1/2
5-3/4
6
6-1/4
6-1/2
6-3/4
7
Displacement
(bbls / inch of stroke)
0.002976
0.003416
0.003886
0.004387
0.004919
0.005480
0.006073
0.006695
0.007348
0.008031
0.008744
0.009488
0.010263
0.011067
0.011902
GENERALIZED PROCEDURES
Step One:
Determine “Barrels / Inch of Stroke” by using the appropriate pump table, or the
following equations:
(Linear Diameter)²
Barrels / Inch of Stroke = --------------------------- (Triplex)
4116
2 X (Linear Diameter)² – (Rod Diameter)²
Barrels / Inch of Stroke = ------------------------------------------------------------ ( Duplex)
6174
Step Two:
Calculate actual pump displacement with the following formula:
Pump Displacement = Barrels / Inch
(Bbls / Stroke)
of Stroke
X
Stroke
Length (Inches)
X
Volumetric
Efficiency
Note: Use Volumetric Efficiency in decimal form (e.g., 95% = 0.95)
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SECTION P – TABLES AND CHARTS
Figure P.1a
Pc Max (Part 1) for Driller's Method
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SECTION P – TABLES AND CHARTS
Figure P.1b
PcMax (Part 2) for Driller's Method
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SECTION P – TABLES AND CHARTS
Figure P.2a
PcMax (Part 1) for Engineer's Method
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SECTION P – TABLES AND CHARTS
Figure P.2b
PcMax (Part 2) for Engineer's Method
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SECTION P – TABLES AND CHARTS
Figure P.3
Volume of Gas at Surface (Driller's and Engineer's Method)
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SECTION P – TABLES AND CHARTS
Chart Equations for PcMax Determination
1.0
Driller's Method Worksheet
(A)
PcMax (Part 1) = SIDP / 2 (psi)
(B)
PcMax (Part 2)
[Fig. P.1a, P.Ib)
where:
2.0
=
(PcMax, 1)2 + (PR) (H1) (r1) (TZ)
= Reservoir Pressure (psi)
= Height of Bubble (ft) {Pit Gain / ACF (DP X CSG)}
= Pressure Gradient of OMW (psi/ft)
= Temperature/Gas Compressibility (Figure P.5) or
= 4.03 - 0.38 ln (PR)
Engineer’s Method Worksheet
(A)
PR
H1
r1
TZ
PcMax (Part 1)
[Fig. P.2] or
= (Internal DP Cap.) (.052) (DMud Wt)
________________________________
(2) (Annulus Capacity Factor)
(B)
PcMax (Part 2)
[Fig. P.3] or
= (PR) (H1) (r2) (TZ)
where:
3.0
PR
H1
r2
TZ
= Reservoir Pressure (psi)
= Height of Bubble (ft) {Pit Gain / ACF (DP X CSG)}
= Pressure Gradient of KMW (psi/ft)
= Temperature/Gas Compressibility (Figure P.5) or
= 4.03 - 0.38 ln (PR)
Volume of Gas at Surface
[from Figures P.4a and P.4b]
Vg
= (Kick Size) (PR) (TZ)
___________________
PcMax
where:
PR
TZ
PcMax
Current Revision:
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= Reservoir Pressure (psi)
= Temperature/Gas Compressibility (Figure P.5)
= Calculated Above (either Driller's or Engineer's Method)
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SECTION P – TABLES AND CHARTS
Theoretical Equations for PcMax Determination
1.0
Engineer’s Method
PcMax
where:
2.0
V
= V2 - V1
V2
PRV1TZ
= ----------PcMax
(D1 (ρ2 - ρ1) - PG ) 2
------------------------2
Driller’s Method
PcMax
where:
3.0
D1 (ρ2 - ρ1) - PG
= ----------------------- +
2
+ (PR) (H1) (ρ2) (TZ)
PR - PG - Dρ1+
= ------------------2
V
= V2 - V1
V2
PRV1TZ
= ----------PcMax
(PR -
PG - Dρ1 ) 2 + (PR)(H1)(ρ1)(TZ)
----------------------------------------------2
Miscellaneous Supporting Equations
D1
H (ft)
VDPC (ft.)
-------------=
AV
V1
_______
=
=
(if answer is equal to or less than drill collar length)
ADC
V1 - (ADC) (L)
---------------------- + L, ft.
AV
(if answer above is greater than drill collar length)
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SECTION P – TABLES AND CHARTS
H1 (ft)
PG
PMA
PMDP
PR
(annulus constant)
AV
= PDP + PMDP - PCI - PMA, psi or
= .12H, psi (.12 is an average gas gradient, psi/ft)
= (D-H)ρ1 or .007 (D-H) M1, psi
= Dρ1 or .007 DM1, psi
= Dρ2 or .007 DM2, psi
ρ1
= .007 M1, psi/ft
ρ2
= .007 M2, psi/ft
VDC
= LCDC, bbl
VDP
= (D-L)CDC, bbl
VDPC
4.0
V1
_______
=
= VDP + VDC, bbl
Nomenclature for Theoretical Equations
ADC
AV
= Annular volume between drill collars and hole, bbl/ft
= Annular volume between drill pipe and hole, bbl/ft
CDC
= Capacity of drill collars, bbl/ft
CDP
= Capacity of drill pipe, bbl/ft
D
D1
H
H1
= Well depth, ft
= Height in annulus that mud in drill string will
occupy when displaced into annulus, ft.
= Height of gas bubble at bottom of hole, ft
= Height of gas bubble using constant annulus, ft
L
M1
= Length of drill collars, ft.
= Old mud weight at time of kick, lb/ft³
M2
= New mud weight required to balance formation
pressure, lb/ft³
PCL = Initial shut-in casing pressure, psi
PcMAX = Maximum surface casing pressure when gas
reaches surface, psi
PDP = Initial shut-in drill pipe pressure, psi
Current Revision:
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SECTION P – TABLES AND CHARTS
Table P.6
BOP Opening and Closing Volumes
Ram Type Blowout Preventers
Model
or
Type
Nominal
Size
(Inches)
Working
Pressure
(Max PSI)
Hydraulic
Vertical Operating
Bore
Pressure
(Inches)
(psi)
Gallons Gallons
to
to
Close
Open
Close
Ratio
Open
Ratio
Koomey
PL
PL
PL
PL
PL
PL
PL
PL
PB
PB
PB
PB
PB
PB
PB
PB
7-1/16
7-1/16
7-1/16
11
11
13-5/8
13-5/8
13-5/8
7-1/16
11
11
13-5/8
13-5/8
13-5/8
18-3/4
18-3/4
3000
5000
10000
5000
10000
3000
5000
10000
5000
5000
10000
5000
10000
15000
10000
15000
7-1/16
7-1/16
7-1/16
11
11
13-5/8
13-5/8
13-5/8
7-1/16
11
11
13-5/8
13-5/8
13-5/8
18-3/4
18-3/4
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1.02
0.80
1.02
3.05
3.05
6.25
5.80
5.80
0.38
1.50
1.50
2.80
2.80
3.54
11.50
11.50
0.96
0.80
0.96
3.05
3.05
5.78
5.80
5.80
0.38
1.50
1.50
2.80
2.80
3.54
11.50
11.50
4.62:1
7.75:1
7.75:1
7.75:1
7.75:1
4.62:1
7.75:1
7.75:1
40.0:1
40.0:1
40.0:1
40.0:1
40.0:1
42.86:1
20.0:1
30.0:1
1.5:1
2.5:1
2.5:1
2.5:1
2.5:1
1.5:1
2.5:1
2.5:1
25.0:1
35.0:1
35.0:1
35.0:1
35.0:1
25.0:1
25.0:1
30.0:1
7-1/16
7-1/16
7-1/16
7-1/16
9
9
11
11
11
11
13-5/8
13-5/8
13-5/8
20-3/4
21-1/4
21-1/4
3000
5000
10000
15000
3000
5000
3000
5000
10000
15000
3000
5000
10000
3000
2000
5000
7-1/16
7-1/16
7-1/16
7-1/16
9
9
11
11
11
11
13-5/8
13-5/8
13-5/8
20-3/4
21-1/4
21-1/4
3000 Max.
3000 Max.
3000 Max.
3000 Max.
3000 Max.
3000 Max.
3000 Max.
3000 Max.
3000 Max.
3000 Max.
3000 Max.
3000 Max.
3000 Max.
3000 Max.
3000 Max.
3000 Max.
1.00
1.00
1.90
3.70
1.90
1.90
3.30
3.30
5.20
8.80
5.40
5.40
11.80
8.10
8.10
17.50
0.93
0.93
2.00
3.40
1.90
1.90
3.20
3.20
5.00
8.10
4.90
4.80
11.80
7.20
7.20
16.60
4.8:1
4.8:1
7.7:1
7.1:1
4.5:1
4.5:1
6.0:1
6.0:1
6.9:1
7.2:1
4.8:1
4.8:1
10.2:1
4.75:1
4.75:1
10.2:1
1.5:1
1.5:1
1.7:1
6.6:1
2.6:1
2.6:1
2.0:1
2.0:1
2.4:1
3.24:1
2.1:1
2.1:1
3.8:1
0.98:1
0.98:1
1.9:1
Hydril
Manual
Lock
Pipe
Current Revision:
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SECTION P – TABLES AND CHARTS
Model
or
Type
Nominal
Size
(Inches)
Working
Pressure
(Max PSI)
Hydraulic
Vertical Operating
Bore
Pressure
(Inches)
(psi)
Gallons Gallons
to
to
Close
Open
Close
Ratio
Open
Ratio
6.00
5.00
8.20
8.10
11.20
11.20
11.80
16.30
16.30
16.60
5.6:1
5.6:1
11.7:1
7.2:1
10.1:1
10.1:1
10.2:1
10.14:1
10.14:1
10.2:1
4.2:1
4.2:1
4.0:1
3.24:1
4.7:1
4.7:1
3.8:1
2.2:1
2.2:1
1.9:1
Hydril (continued)
Manual
Lock
Shear
11
11
11
11
13-5/8
13-5/8
13-5/8
20-3/4
21-1/4
21-1/4
3000
5000
10000
15000
3000
5000
10000
3000
2000
5000
11
11
11
11
13-5/8
13-5/8
13-5/8
20-3/4
21-1/4
21-1/4
3000 Max.
3000 Max.
3000 Max.
3000 Max.
3000 Max.
3000 Max.
3000 Max.
3000 Max.
3000 Max.
3000 Max.
MPL
Pipe
7-1/16
7-1/16
7-1/16
7-1/16
11
11
13-5/8
13-5/8
13-5/8
13-5/8
16-3/4
3000
5000
10000
15000
10000
15000
3000
5000
10000
15000
10000
18-3/4
7-1/16
7-1/16
7-1/16
7-1/16
11
11
13-5/8
13-5/8
13-5/8
13-5/8
16-3/4
10000
3000 Max.
1.20
3000 Max.
1.20
3000 Max.
2.00
3000 Max.
3.90
3000 Max.
5.70
3000 Max.
9.30
3000 Max.
5.90
3000 Max.
5.90
3000 Max.
12.90
3000 Max.
12.60
3000 Max.
15.60
18-3/4
3000 Max.
0.93
0.93
1.80
3.40
5.00
8.10
4.90
5.20
11.80
11.00
14.10
17.10
5.4:1
5.4:1
8.2:1
7.6:1
7.6:1
7.6:1
5.2:1
5.2:1
10.6:1
7.74:1
10.6:1
15.60
1.5:1
1.5:1
1.7:1
6.6:1
2.4:1
3.24:1
2.1:1
2.1:1
3.8:1
3.56:1
2.41:1
10.6:1
1.9:1
18-3/4
20-3/4
21-1/4
21-1/4
15000
3000
2000
5000
18-3/4
20-3/4
21-1/4
21-1/4
3000 Max.
3000 Max.
3000 Max.
3000 Max.
19.40
18.00
18.00
19.30
16.70
16.30
16.30
16.60
7.27:1
10.6:1
10.6:1
10.6:1
2.15:1
0.98:1
0.98:1
1.9:1
11
11
11
11
13-5/8
13-5/8
13-5/8
13-5/8
16-3/4
18-3/4
18-3/4
20-3/4
21-1/4
21-1/4
3000
5000
10000
15000
3000
5000
10000
15000
10000
10000
15000
3000
2000
5000
11
11
11
11
13-5/8
13-5/8
13-5/8
13-5/8
16-3/4
18-3/4
18-3/4
20-3/4
21-1/4
21-1/4
3000 Max.
3000 Max.
3000 Max.
3000 Max.
3000 Max.
3000 Max.
3000 Max.
3000 Max.
3000 Max.
3000 Max.
3000 Max.
3000 Max.
3000 Max.
3000 Max.
6.00
6.00
9.30
9.30
12.00
12.00
12.90
12.60
15.60
17.10
19.40
18.00
18.00
19.30
5.00
5.00
8.20
8.10
11.20
11.20
11.80
11.00
14.10
15.60
16.70
16.30
16.30
16.60
6.0:1
6.0:1
12.4:1
7.6:1
10.6:1
10.6:1
10.6:1
7.74:1
10.6:1
10.6:1
7.27:1
10.6:1
10.6:1
10.6:1
4.2:1
4.2:1
4.0:1
3.24:1
4.7:1
4.7:1
3.8:1
3.56:1
2.4:1
1.9:1
2.15:1
2.2:1
2.2:1
1.9:1
MPL
Shear
Current Revision:
Previous Revision:
October 2002
October 1998
P - 18
5.50
5.50
8.80
8.80
11.50
11.50
11.80
17.20
17.20
17.50
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
__
SECTION P – TABLES AND CHARTS
Model
or
Type
Nominal
Size
(Inches)
Working
Pressure
(Max PSI)
Hydraulic
Vertical Operating
Bore
Pressure
(Inches)
(psi)
Gallons Gallons
to
to
Close
Open
Close
Ratio
Open
Ratio
Bowen Tools, Inc.
51922
51923
51924
60701
50460
70051
51926
51927
51928
51929
61040
61044
61048
61050
47034
60467
70630
61053
66174
61055
61507
61060
51938
63642
70466
60615
70399
2-1/2 Sgl
2-1/2 Sgl
2-1/2 Twin
2-1/2 Twin
2-9/16 Sgl
2-9/16 Sgl
3 Sgl
3 Sgl
3 Twin
3 Twin
4 Sgl
4 Sgl
4 Twin
4 Twin
4-1/16 Sgl
4-1/16 Sgl
4-1/16 Twin
4 1/2 Sgl
4 1/2 Sgl
4 1/2 Sgl
4 1/2 Twin
4 1/2 Twin
5-1/2 Sgl
7-1/16 Sgl
7-1/16 Twin
7-5/8 Sgl
7-5/8 Twin
5000
10000
5000
10000
15000
20000
5000
10000
5000
10000
5000
10000
5000
10000
10000
15000
15000
3000
5000
10000
5000
10000
3000
10000
10000
5000
5000
2-1/2
2-1/2
2-1/2
2-1/2
2-9/16
2-9/16
3
3
3
3
4
4
4
4
4-1/16
4-1/16
4-1/16
4 1/2
4 1/2
4 1/2
4 1/2
4 1/2
5-1/2
7-1/16
7-1/16
6-1/2
6-1/2
1000
1600
900
1600
1200
800
600
1200
600
1200
500
1000
500
1000
1000
1250
1250
400
555
1000
500
1000
300
900
900
900
1800
0.17
0.26
0.35
0.52
0.30
0.87
0.27
0.27
0.53
0.53
0.93
0.93
1.86
1.86
0.43
0.69
1.38
0.90
1.83
0.90
1.79
1.79
1.23
1.02
2.04
1.75
3.50
0.14
0.18
0.27
0.36
0.30
0.93
0.22
0.22
0.43
0.43
0.78
0.78
1.55
1.55
0.34
0.74
1.48
0.81
1.64
0.81
1.61
1.61
1.05
1.10
2.20
1.74
3.48
7.9:1
7.9:1
7.9:1
7.9:1
8.18:1
23.8:1
13.2:1
13.2:1
13.2:1
13.2:1
15.3:1
15.3:1
15.3:1
15.3:1
13.6:1
16.2:1
16.2:1
15.3:1
15.3:1
15.3:1
15.3:1
15.3:1
20.8:1
16.2:1
16.2:1
10.9:1
10.9:1
7-1/16
7-1/16
7-1/16
7-1/16
7-1/16
11
11
11
11
11
11
13-5/8
13-5/8
13-5/8
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1.22
1.22
1.54
1.22
1.22
3.31
3.31
4.23
3.31
4.23
5.54
5.54
5.54
6.78
1.17
1.17
1.48
1.17
1.17
3.16
3.16
4.03
3.16
4.03
5.42
5.20
5.42
6.36
6.9:1
6.9:1
6.9:1
6.9:1
6.9:1
7.3:1
7.3:1
7.3:1
7.3:1
7.3:1
9.9:1
7.0:1
7.0:1
7.0:1
Cameron Iron Works, Inc.
U
U
U-Shear
U
U
U
U
U-Shear
U
U-Shear
U
U
U
U-Shear
6
6
6
7-1/16
7-1/16
10
10
10
11
11
11
12
13-5/8
13-5/8
Current Revision:
Previous Revision:
3000
5000
5000
10000
15000
3000
5000
5000
10000
10000
15000
3000
5000
5000
October 2002
October 1998
P - 19
2.3:1
2.3:1
2.3:1
2.3:1
2.3:1
2.5:1
2.5:1
2.5:1
2.5:1
2.5:1
2.2:1
2.3:1
2.3:1
2.3:1
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
__
SECTION P – TABLES AND CHARTS
Model
or
Type
Nominal
Size
(Inches)
Working
Pressure
(Max PSI)
Hydraulic
Vertical Operating
Bore
Pressure
(Inches)
(psi)
Gallons Gallons
to
to
Close
Open
Close
Ratio
Open
Ratio
7.0:1
7.0:1
6.6:1
6.8:1
6.8:1
6.8:1
7.4:1
7.0:1
7.0:1
7.0:1
7.0:1
5.5:1
6.5:1
7.2:1
7.2:1
7.0:1
7.0:1
14.0:1
14.0:1
9.0:1
9.0:1
14.0:1
14.0:1
6.7:1
9.3:1
7.75:1
7.75:1
9.05:1
9.05:1
9.05:1
9.05:1
8.64:1
8.64:1
8.64:1
8.64:1
3.8:1
3.8:1
3.9:1
3.9:1
3.9:1
3.9:1
3.7:1
3.7:1
2.3:1
2.2:1
8.9:1
2.3:1
2.3:1
1.9:1
3.7:1
1.3:1
1.2:1
1.3:1
1.2:1
3.0:1
2.3:1
4.1:1
3.1:1
1.0:1
1.0:1
2.3:1
2.3:1
1.4:1
1.4:1
1.2:1
1.2:1
2.5:1
3.5:1
1.5:1
1.5:1
1.83:1
1.83:1
1.21:1
1.21:1
1.07:1
.62:1
.62:1
.62:1
1.0:1
1.0:1
1.0:1
1.0:1
1.0:1
1.0:1
1.0:1
1.0:1
Cameron Iron Works (continued)
U
U-Shear
U
U
U
U-Shear
U
U
U-Shear
U
U-Shear
U
U-Shear
U
U-Shear
U
U
U-Blind
with
Shear
Booster
U II
U II
QRC
QRC
QRC
QRC
QRC
QRC
QRC
QRC
QRC
QRC
SS
SS
SS
SS
SS
SS
SS
SS
13-5/8
13-5/8
13-5/8
16-3/4
16-3/4
16-3/4
18-3/4
20
20
21-1/4
21-1/4
21-1/4
21-1/4
21-1/4
21-1/4
26
26
13-5/8
13-5/8
16-3/4
16-3/4
20
20
18-3/4
18-3/4
6
6
8
8
10
10
12
16
18
20
6
6
8
8
10
10
12
14
Current Revision:
Previous Revision:
10000
10000
15000
3000
5000
5000
10000
3000
3000
2000
2000
7500
7500
10000
10000
2000
3000
5000
10000
3000
5000
2000
3000
10000
15000
3000
5000
3000
5000
3000
5000
3000
2000
2000
2000
3000
5000
3000
5000
3000
5000
3000
5000
October 2002
October 1998
13-5/8
13-5/8
13-5/8
16-3/4
16-3/4
16-3/4
18-3/4
20-3/4
20-3/4
21-1/4
21-1/4
21-1/4
21-1/4
21-1/4
21-1/4
26-3/4
26-3/4
13-5/8
13-5/8
16-3/4
16-3/4
20-3/4
20-3/4
18-3/4
18-3/4
7-1/16
7-1/16
9
9
11
11
13-5/8
16-3/4
17-3/4
17-3/4
7-1/16
7-1/16
9
9
11
11
13-5/8
13-5/8
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/2500
1500/2500
1500/2500
1500/2500
1500/2500
1500/2500
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
P - 20
5.54
6.78
11.70
10.16
10.16
12.03
21.20
8.40
9.35
8.40
9.35
20.41
23.19
26.54
30.15
10.50
10.50
11.60
11.60
10.80
10.80
16.80
16.80
24.70
34.70
0.81
0.81
2.36
2.36
2.77
2.77
4.42
6.00
6.00
6.00
0.80
0.80
1.50
1.50
1.50
1.50
2.90
2.90
5.42
6.36
11.28
9.45
9.45
11.19
23.10
7.90
8.77
7.90
8.77
17.78
20.20
24.14
27.42
9.84
9.84
10.90
10.90
11.70
11.70
15.70
15.70
22.30
32.30
0.95
0.95
2.70
2.70
3.18
3.18
5.10
7.05
7.05
7.05
0.70
0.70
1.30
1.30
1.30
1.30
2.50
2.50
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
__
SECTION P – TABLES AND CHARTS
Model
or
Type
Nominal
Size
(Inches)
Working
Pressure
(Max PSI)
Hydraulic
Vertical Operating
Bore
Pressure
(Inches)
(psi)
Gallons Gallons
to
to
Close
Open
Close
Ratio
Open
Ratio
Cameron Iron Works (continued)
Type F
with
Type W2
Operator
6
6
7
7
8
8
10
10
11
12
14
16
16
20
20
3000
5000
10000
15000
3000
5000
3000
5000
10000
3000
5000
2000
3000
2000
3000
7-1/16
7-1/16
7-1/16
7-1/16
9
9
11
11
11
13-5/8
13-5/8
16-3/4
16-3/4
20-1/4
20-1/4
500/1500
500/1500
500/1500
500/1500
500/1500
500/1500
500/1500
500/1500
500/1500
500/1500
500/1500
500/1500
500/1500
500/1500
500/1500
1.50
1.50
1.50
1.50
2.80
2.80
2.80
2.80
2.80
4.10
4.10
5.00
5.00
5.00
5.00
2.30
2.30
2.30
2.30
3.70
3.70
3.70
3.70
3.70
5.30
5.30
6.00
6.00
6.00
6.00
4.5:1
4.5:1
4.5:1
4.5:1
2.5:1
2.5:1
2.5:1
2.5:1
2.5:1
2.0:1
2.0:1
2.0:1
2.0:1
2.0:1
2.0:1
Type F
with
Type W
Operator
6
6
7
7
8
8
10
10
11
12
14
16
16
20
20
3000
5000
10000
15000
3000
5000
3000
5000
10000
3000
5000
2000
3000
2000
3000
7-1/16
7-1/16
7-1/16
7-1/16
9
9
11
11
11
13-5/8
13-5/8
16-3/4
16-3/4
20-1/4
20-1/4
500/1500
500/1500
500/1500
500/1500
500/1500
500/1500
500/1500
500/1500
500/1500
500/1500
500/1500
500/1500
500/1500
500/1500
500/1500
2.30
2.30
2.30
2.30
3.70
3.70
3.70
3.70
3.70
6.80
6.80
7.60
7.60
7.60
7.60
3.05
3.50
3.50
3.50
4.60
4.60
4.60
4.60
4.60
8.10
8.10
9.10
9.10
9.10
9.10
4.5:1
4.5:1
4.5:1
4.5:1
2.5:1
2.5:1
2.5:1
2.5:1
2.5:1
2.0:1
2.0:1
2.0:1
2.0:1
2.0:1
2.0:1
Type F
with
Type L
Operator
6
6
7
7
8
8
10
10
11
12
14
16
16
20
20
3000
5000
10000
15000
3000
5000
3000
5000
10000
3000
5000
2000
3000
2000
3000
7-1/16
7-1/16
7-1/16
7-1/16
9
9
11
11
11
13-5/8
13-5/8
16-3/4
16-3/4
20-1/4
20-1/4
250/1500
250/1500
250/1500
250/1500
250/1500
250/1500
250/1500
250/1500
250/1500
250/1500
250/1500
250/1500
250/1500
250/1500
250/1500
3.97
3.97
3.97
3.97
6.85
6.85
6.85
6.85
6.85
10.30
10.30
11.71
11.71
11.71
11.71
3.46
3.46
3.46
3.46
6.19
6.19
6.19
6.19
6.19
9.38
9.38
10.66
10.66
10.66
10.66
4.9:1
4.9:1
4.9:1
4.9:1
3.44:1
3.44:1
3.44:1
3.44:1
3.44:1
2.3:1
2.3:1
2.3:1
2.3:1
2.3:1
2.3:1
Current Revision:
Previous Revision:
October 2002
October 1998
P - 21
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
__
SECTION P – TABLES AND CHARTS
Model
or
Type
Type F
with
Type H
Operator
Nominal
Size
(Inches)
6
6
7
7
8
8
10
10
11
12
14
16
16
20
20
Working
Pressure
(Max PSI)
3000
5000
10000
15000
3000
5000
3000
5000
10000
3000
5000
2000
3000
2000
3000
Hydraulic
Vertical Operating
Bore
Pressure
(Inches)
(psi)
7-1/16
7-1/16
7-1/16
7-1/16
9
9
11
11
11
13-5/8
13-5/8
16-3/4
16-3/4
20-1/4
20-1/4
1000/5000
1000/5000
1000/5000
1000/5000
1000/5000
1000/5000
1000/5000
1000/5000
1000/5000
1000/5000
1000/5000
1000/5000
1000/5000
1000/5000
1000/5000
Gallons Gallons
to
to
Close
Open
Close
Ratio
Open
Ratio
0.52
0.52
0.52
0.52
0.90
0.90
0.90
0.90
0.90
1.52
1.52
1.73
1.73
1.73
1.73
1.50
1.50
1.50
1.50
1.80
1.80
1.80
1.80
1.80
2.70
2.70
3.08
3.08
3.08
3.08
1.5:1
1.5:1
1.5:1
1.5:1
1.0:1
1.0:1
1.0:1
1.0:1
1.0:1
2.3:1
2.3:1
2.3:1
2.3:1
2.3:1
2.3:1
1.10
1.10
0.94
0.94
6.5:1
6.5:1
1.0:1
1.0:1
0.52
0.99
5.89
5.89
2.27
1.74
8.45:1
4.45:1
10.63:1
10.63:1
5.57:1
1.45
4.74:1
1.82:1
19.4:1
19.4:1
3.00:1
4.45:1
Guiberson Division of Dresser Industries
Hc
Hyd. Cyl.
6
8
3000
2000
7-3/8
9 -1/16
2000
2000
4-1/16
6
7-1/16
7-1/16
8
10000
5000
10000
15000
5000
10
4-1/16
6
7-1/16
7-1/16
8
3000
1500/3000
0.59
1500/3000
1.19
1500/3000
6.35
1500/3000
6.35
1500/3000
2.58
10
1500/3000
1.16:1
10
11
12
13-5/8
13-5/8
16-3/4
20
20
5000
10000
3000
5000
10000
5000
2000
3000
10
11
12
13-5/8
13-5/8
16-3/4
21-1/4
21-1/4
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
2.98
8.23
4.35
4.35
11.56
13.97
5.07
5.07
2.62
7.00
5.30
5.30
10.52
12.71
4.46
4.46
5.57:1
7.11:1
8.16:1
8.16:1
10.85:1
10.85:1
5.57:1
5.57:1
2.09:1
3.44:1
1.74:1
1.74:1
3.48:1
3.61:1
.78:1
.78:1
6
8
3000
3000
7-1/16
9
1500/3000
1500/3000
0.55
7.80
0.51
6.86
——
——
——
——
6
8
11
13-5/8
13-5/8
13-5/8
13-5/8
3000
3000
10000
5000
5000
10000
15000
7-1/16
9
11
13-5/8
13-5/8
13-5/8
13-5/8
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
0.55
0.77
8.23
4.35
11.56
10.58
11.56
0.51
0.68
7.00
5.30
10.52
10.52
10.52
4.0:1
4.0:1
7.11:1
8.16:1
10.85:1
7.11:1
7.11:1
2.50:1
1.81:1
3.44:1
1.74:1
3.48:1
3.48:1
2.14:1
Shaffer
LWS w/
Manual
Lock
LWP
Series
LWP
Type
SL and
LWS
Posilock
Current Revision:
Previous Revision:
October 2002
October 1998
P - 22
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
__
SECTION P – TABLES AND CHARTS
Model
or
Type
Nominal
Size
(Inches)
Working
Pressure
(Max PSI)
Hydraulic
Vertical Operating
Bore
Pressure
(Inches)
(psi)
Gallons Gallons
to
to
Close
Open
Close
Ratio
Open
Ratio
Shaffer (continued)
LWP
Type
SL and
LWS
Posilock
16-3/4
16-3/4
18 3/4
18-3/4
20
20
20
20
21-1/4
5000
10000
10000
15000
2000
2000
3000
3000
10000
16-3/4
16-3/4
18 3/4
18-3/4
21-1/4
21-1/4
21-1/4
21-1/4
21-1/4
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
13.97
14.47
15.30
14.62
7.80
16.88
7.80
16.88
16.05
12.60
12.50
13.21
13.33
6.86
15.35
6.86
15.35
13.86
11.85:1
7.11:1
7.11:1
2.45:1
2.06:1
1.83:1
8.16:1
10.85:1
8.16:1
10.85:1
7.11:1
1.15:1
2.52:1
1.15:1
2.52:1
1.63:1
Sentinel
6
3000
7-1/16
1500/3000
0.29
0.28
——
——
Type
B and E
6
6
8
8
10
10
12
14
16
3000
5000
3000
5000
3000
5000
3000
5000
2000
7-1/16
7-1/16
9
9
11
11
13-5/8
13-5/8
15-1/2
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
1500/3000
2.75
2.75
2.75
2.75
3.25
3.25
3.55
3.55
3.65
2.30
2.30
2.30
2.30
2.70
2.70
2.90
2.90
3.00
6.0:1
6.0:1
6.0:1
6.0:1
6.0:1
6.0:1
6.0:1
6.0:1
6.0:1
2.57:1
2.57:1
1.89:1
1.89:1
1.51:1
1.35:1
1.14:1
1.14:1
1.05:1
Current Revision:
Previous Revision:
October 2002
October 1998
P - 23
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
__
SECTION P – TABLES AND CHARTS
Annular Blowout Preventers
Model
or
Type
Nominal
Size
(Inches)
Working
Pressure
(Max PSI)
Hydraulic
Vertical Operating
Bore
Pressure
(Inches)
(psi)
Gallons
to
Close
Gallons
to
Open
Secondary
Volume
(Gallons)
Hydril Company
GK
GK
GK
GK
GK
GK
GK
GK
GK
GK
GK
GK
GK
GK
GK
GK
GK
GK
6
6
——
——
——
8
8
——
10
10
——
——
12
——
——
16
16
——
3000
5000
10000
15000
20000
3000
5000
10000
3000
5000
10000
10/15000
3000
5000
10000
2000
3000
5000
7-1/16
7-1/16
7-1/16
7-1/16
7-1/16
9
9
9
11
11
11
11
13-5/8
13-5/8
13-5/8
16-3/4
16-3/4
16-3/4
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
2.85
3.86
9.42
11.20
10.90
4.33
6.84
15.90
7.43
9.81
25.10
26.67
11.36
17.98
37.18
17.46
21.02
28.70
2.24
3.30
11.20
10.90
7.20
3.41
5.80
11.95
5.54
7.98
18.97
20.45
8.94
14.16
26.50
12.59
15.80
19.93
GL
GL
GL Dual
GL
GL Dual
GL
——
——
——
——
——
——
5000
5000
5000
5000
5000
5000
13-5/8
16-3/4
16-3/4
18 3/4
18 3/4
21-1/4
1500
1500
1500
1500
1500
1500
19.76
33.80
33.80
44.00
44.00
58.00
19.76
33.80
33.80
44.00
44.00
58.00
GX
GX
GX
GX
GX
11
11
13-5/8
13-5/8
18-3/4
10000
15000
10000
15000
10000
11
11
13-5/8
13-5/8
18-3/4
1500
1500
1500
1500
1500
17.88
24.14
24.14
34.00
58.00
17.88
24.14
24.14
34.00
58.00
MSP
MSP
MSP
MSP
MSP
MSP
MSP
MSP
6
8
10
20
20
20
29-1/2
30
2000
2000
2000
2000
2000
2000
500
1000
7-1/16
9
11
20-3/4
21-1/4
HL21-1/4
29-1/2
30
1500
1500
1500
1500
1500
1500
1500
1500
2.85
4.57
7.43
31.05
31.05
31.75
60.00
87.60
1.98
2.95
5.23
18.93
18.93
19.25
——
27.80
Current Revision:
Previous Revision:
October 2002
October 1998
P - 24
8.24
17.30
17.30
20.00
20.00
29.50
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
__
SECTION P – TABLES AND CHARTS
Model
or
Type
Nominal
Size
(Inches)
Working
Pressure
(Max PSI)
Hydraulic
Vertical Operating
Bore
Pressure
(Inches)
(psi)
Gallons
to
Close
Gallons
to
Open
Secondary
Volume
(Gallons)
Cameron Iron Works
A
A
A
A
A
A
A
A
A
6
6
6
11
11
11
13-5/8
13-5/8
16-3/4
5000
10000
15000
5000
10000
15000
5000
10000
5000
7-1/16
7-1/16
7-1/16
11
11
11
13-5/8
13-5/8
16-3/4
1500
1500
N.A.
1500
1500
N.A.
1500
1500
1500
2.20
4.00
N.A.
7.80
12.10
N.A.
15.50
21.50
33.00
1.90
3.10
N.A.
6.50
10.50
N.A.
13.90
18.70
29.00
D
D
D
D
D
D
6
7-1/16
10
11
13-5/8
13-5/8
5000
10000
5000
10000
5000
10000
7-1/16
7-1/16
11
11
13-5/8
13-5/8
3000
3000
3000
3000
3000
3000
1.69
2.94
5.65
10.15
12.12
18.10
1.39
2.55
4.69
9.06
10.34
16.15
3000
5000
10000
3000
5000
3000
5000
10000
3000
5000
10000
5000
5000
2000
5000
7-1/16
7-1/16
7-1/16
9
9
11
11
11
13-5/8
13-5/8
13-5/8
16-3/4
18 3/4
21-1/4
21-1/4
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
1500
4.57
4.57
17.11
7.23
11.05
11.00
18.67
30.58
23.50
23.58
40.16
33.26
48.16
32.59
61.37
3.21
3.21
13.95
5.03
8.72
6.78
14.59
24.67
14.67
17.41
32.64
25.61
37.61
16.92
47.76
3000
3000
3000
3000
3000
3000
3000
3000
3000
3000
3
4
6 1/4
7 7/8
8 7/8
10
10 7/8
11 1/8
12 3/8
13 3/4
3000
3000
3000
3000
3000
3000
3000
3000
3000
3000
0.50
0.80
1.60
4.10
5.70
7.60
11.10
10.30
15.30
19.90
Shaffer
Spherical
BOP
6
6
7-1/16
8
8
10
10
11
12
13-5/8
13-5/8
16-3/4
18 3/4
20
21-1/4
Regan
K
K
K
K
K
K
K
K
K
K
3
4
7
8 5/8
9 5/8
10 3/4
11 3/4 (old)
11 3/4 (new)
13 3/8
13 3/4
Current Revision:
Previous Revision:
October 2002
October 1998
P - 25
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
__
SECTION P – TABLES AND CHARTS
Model
or
Type
Nominal
Size
(Inches)
Working
Pressure
(Max PSI)
Hydraulic
Vertical Operating
Bore
Pressure
(Inches)
(psi)
Gallons
to
Close
Gallons
to
Open
Secondary
Volume
(Gallons)
Regan (continued)
K
K
KFD
KFD
KFD
KFD
KFD
KFDJ
16
18 5/8
16
18 3/4
20
22
24
27 1/2
3000
3000
500
500
500
500
500
2000
15 3/8
17 1/2
10
10
10
10
10
10
3000
3000
1000
1000
1000
1000
1000
2500
25.00
29.50
3.00
3.00
3.00
3.00
3.00
3.00
KFL
KFL
KFL
KFL
KFL
KFL
KFL
KFL
KFL
KFL
KFL
KFL
KFL
13-5/8
13-5/8
13-5/8
16-3/4
16-3/4
16-3/4
20
20
20
30
30
30
30
3000
5000
10000
3000
5000
10000
2000
3000
5000
1000
2000
1000
2000
13-5/8
13-5/8
13-5/8
16-3/4
16-3/4
16-3/4
20-3/4
20-3/4
20-3/4
28
28
26-1/2
26-1/2
Well + 500
Well + 500
Well + 500
Well + 500
Well + 500
Well + 500
Well + 500
Well + 500
Well + 500
Well + 500
Well + 500
Well + 500
Well + 500
19.50
22.00
24.50
25.75
29.00
31.50
28.50
32.00
35.00
47.50
52.00
51.50
56.00
6
6
8
8
3000
6000
3000
6000
7-1/16
7-1/16
9
9
3000
3000
3000
3000
4.50
4.50
8.25
8.25
Torus
Torus
Torus
Torus
Current Revision:
Previous Revision:
October 2002
October 1998
P - 26
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
__
SECTION P – TABLES AND CHARTS
Hydraulically Operated Valves
Model
or
Type
Line
Size
(Inches)
Working
Pressure
(Max PSI)
Bore
Size
(Inches)
Hydraulic
Operating
Pressure
(psi)
Gallons
to
Close
Gallons
to
Open
Cameron Iron Works
HCR
HCR
HCR
HCR
F
F
F
F
F
F
F
F
F
F
F
F
F
F
F
DV
DV
DV
DV
DV
DV
DV
4
4
6
6
3000
5000
3000
5000
4
4
7
7
1500
1500
1500
1500
0.52
0.52
1.95
1.95
0.61
0.61
2.25
2.25
2
2
2
2
2-1/2
2-1/2
2-1/2
2-1/2
3
3
3
3
4
4
6
960-3000
5000-15000
960-3000
5000-15000
960-3000
5000-15000
960-3000
15000
960-2000
3000-5000
10000
15000
2000-5000
10000
2000-5000
1 13/16
1 13/16
2-1/16
2-1/16
2-9/16
2-9/16
2-9/16
2-9/16
3-1/8
3-1/8
3-1/8
3-1/8
4-1/8
4-1/8
6-1/8
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
1500/5000
0.10
0.16
0.10
0.16
0.13
0.20
0.20
0.40
0.15
0.24
0.28
0.49
0.30
0.59
0.84
0.10
0.16
0.10
0.16
0.13
0.20
0.20
0.40
0.15
0.24
0.28
0.49
0.30
0.59
0.84
4
4
6
8
10
10
12
3000
5000
3000
3000
3000
5000
3000
4
4
7
9
11
11
13-5/8
1500
1500
1500
1500
1500
1500
1500
1.10
1.10
3.60
5.60
11.40
11.40
22.70
0.80
0.80
2.10
2.40
5.70
5.70
11.80
2500
2500
2500
2500
2500
2500
2500
2500
2500
2500
0.11
0.11
0.11
0.20
0.23
0.23
0.23
0.42
0.25
0.46
0.13
0.13
0.13
0.21
0.26
0.26
0.26
0.45
0.30
0.51
McEvoy Oilfield Equipment
AC Valve
w/ U-1
Hyd.
Oper.
2
2
2
2
2-1/2
2-1/2
2-1/2
2-1/2
3
3
Current Revision:
Previous Revision:
2000
3000
5000
10000
2000
3000
5000
10000
2000
3000
October 2002
October 1998
P - 27
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
__
SECTION P – TABLES AND CHARTS
Model
or
Type
Line
Size
(Inches)
Working
Pressure
(Max PSI)
Bore
Size
(Inches)
Hydraulic
Operating
Pressure
(psi)
Gallons
to
Close
Gallons
to
Open
McEvoy Oil Field Equipment (continued)
AC Valve
w/ U-1
Hyd.
Oper.
3
4
4
4
5000
2000
3000
5000
2500
2500
2500
2500
0.46
0.62
0.62
0.98
0.51
0.69
0.69
1.04
C Valve
with
RM-1
Actuator
2
2-1/2
3
4
5000
5000
5000
5000
2-1/16
2-9/16
3-1/8
4-1/8
1500
1500
1500
1500
0.10
0.12
0.23
0.44
0.11
0.13
0.25
0.50
E Valve
with
RM-1
Actuator
1-13/16
2-1/16
2-9/16
3-1/16
4-1/16
10000
10000
10000
10000
10000
1-13/16
2-1/16
2-9/16
3-1/16
4-1/16
1500
1500
1500
1500
1500
0.08
0.16
0.30
0.36
1.00
0.09
0.18
0.33
0.37
1.07
EDU and
EU Valve
with U-1
Actuator
3
3-1/16
5000
10000
3-1/16
3-1/16
2500
2500
0.47
0.47
0.52
0.52
2 Reg.
2
2 Reg.
2
2 Reg.
2
2-1/16
2-1/16
2-1/2
2-1/2
2-1/2
3
3
3
3-1/16
4
4
4-1/16
6
2000
2000
3000
3000
5000
5000
10000
15000
2000
3000
5000
2000
3000
5000
10000
3000
5000
10000
3000
1-11/16
2-1/16
1-11/16
2-1/16
1-11/16
2-1/16
2-1/16
2-1/16
2-9/16
2-9/16
2-9/16
3-1/8
3-1/8
3-1/8
3-1/16
4-1/16
4-1/16
4-1/16
7-1/16
3000
3000
3000
3000
3000
3000
3000
3000
3000
3000
3000
3000
3000
3000
3000
3000
3000
3000
3000
Shaffer
Flo-Seal
Current Revision:
Previous Revision:
October 2002
October 1998
P - 28
0.20
0.20
0.20
0.20
0.20
0.20
0.40
0.40
0.30
0.30
0.30
0.30
0.30
0.30
0.60
0.80
0.80
1.30
0.20
0.20
0.20
0.20
0.20
0.20
0.40
0.40
0.30
0.30
0.30
0.30
0.30
0.30
0.60
0.80
0.80
1.30
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
__
SECTION P – TABLES AND CHARTS
Model
or
Type
Line
Size
(Inches)
Working
Pressure
(Max PSI)
Bore
Size
(Inches)
Hydraulic
Operating
Pressure
(psi)
Gallons
to
Close
Gallons
to
Open
Shaffer (continued)
Flo-Seal
with
Ramlock
2 Reg.
2
2 Reg.
2
2 Reg.
2
2-1/16
2-1/16
2-1/2
2-1/2
2-1/2
3
3
3
3-1/16
4
4
4-1/16
6
2000
2000
3000
3000
5000
5000
10000
15000
2000
3000
5000
2000
3000
5000
10000
3000
5000
10000
3000
1-11/16
2-1/16
1-11/16
2-1/16
1-11/16
2-1/16
2-1/16
2-1/16
2-9/16
2-9/16
2-9/16
3-1/8
3-1/8
3-1/8
3-1/16
4-1/16
4-1/16
4-1/16
7-1/16
3000
3000
3000
3000
3000
3000
3000
3000
3000
3000
3000
3000
3000
3000
3000
3000
3000
3000
3000
0.30
0.30
0.30
0.30
0.30
0.30
0.40
0.40
0.30
0.30
0.30
0.40
0.40
0.40
0.60
0.80
0.80
0.80
0.30
0.30
0.30
0.30
0.30
0.30
0.40
0.40
0.30
0.30
0.30
0.40
0.40
0.40
0.60
0.80
0.80
0.80
CB
Subsea
Failsafe
Long
Sea
Chest
3
3-1/16
5000
10000
3-1/8
3-1/16
3000
3000
0.00
0.00
0.45
0.50
CB
Subsea
Failsafe
Short
Sea
Chest
3
3-1/16
5000
10000
3-1/8
3-1/16
3000
3000
0.43
0.45
0.45
0.50
Type DB
3
3
3-1/16
4
4
4-1/16
6
3000
5000
10000
3000
5000
10000
3000
3-1/8
3-1/8
3-1/16
4-1/16
4-1/16
4-1/16
7-1/16
3000
3000
3000
3000
3000
3000
3000
0.30
0.30
0.60
0.80
0.80
1.30
2.00
0.30
0.30
0.60
0.80
0.80
1.30
2.00
Current Revision:
Previous Revision:
October 2002
October 1998
P - 29
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
__
SECTION Q – WELL CONTROL EQUATIONS
WELL CONTROL
EQUATIONS
Current Revision:
Previous Revision:
October 2002
October 1998
Q-1
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
__
SECTION Q – WELL CONTROL EQUATIONS
1.
Pressure (psi)
Force (lb)
__________
= psi
Area (in2)
2.
Pressure Gradient (psi/ft)
0.007 x Mud Weight (pcf) = (psi/ft)
3.
Hydrostatic Pressure (psi)
a.
0.007 x Mud Weight (pcf) x True Vertical Depth, TVD (ft) = psi
Hydrostatic Pressure (psi)
b.
Mud Weight (pcf) =
______________________________________
0.007 x True Vertical Depth, TVD (ft)
Hydrostatic Pressure (psi)
c. True Vertical Depth, TVD (ft) =
_____________________________
0.007 x Mud Weight (pcf)
4.
Equivalent Density (pcf)
Pressure (psi)
_______________
= pcf
0.007 x TVD (ft)
5.
Formation Pressure (psi)
Hydrostatic Pressure in Drill Pipe (psi) + SIDPP (psi) = psi
6.
Density to Balance Formation (pcf)
Kill Mud Weight, KMW (pcf) =
SIDPP (psi)
________________
+ Original Mud Weight (pcf) = pcf
0.007 x TVD (ft)
Current Revision:
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SECTION Q – WELL CONTROL EQUATIONS
7.
Equivalent Mud Weight, EMW (pcf)
Leak-Off Pressure (psi)
_____________________________
+ Leak-Off Mud Wt (pcf) = pcf
0.007 x Casing Shoe TVD (ft)
8.
Maximum Allowable Surface Pressure, MASP (psi)
(based on casing burst)
Casing Internal Yield (psi) x .80 (safety factor) = psi
9.
Maximum Initial Shut-In Casing Pressure, MISICP (psi)
Upon initial closure only-based on formation breakdown @ shoe.
For IWCF, written as MAASP.
[ EMW (pcf) - Present Mud Wt (pcf) ] x 0.007 x Shoe TVD (ft) = psi
10.
Initial Circulating Pressure (psi)……… (ENGINEER’S & DRILLER’S METHODS)
SIDPP (psi) + Slow Pump Rate Pressure, SPRP (psi) = psi
11.
Final Circulating Pressure (psi)………. (ENGINEER’S METHOD)
Kill Mud Wt (pcf)
SPRP (psi) x
_________________________
= psi
Original Mud Wt (pcf)
12.
Equivalent Circulating Density, ECD (pcf)
Annular Pressure Loss (psi)
_____________________________
+ Mud Wt (pcf) = pcf
0.007 x TVD Bit (ft)
13.
Gas Pressure and Volume Relationship - Boyle’s Law
P1V1 = P2V2
The pressure (P1, psi) of a gas bubble times its volume (V1, bbl) in one
part of the hole equals its pressure (P2, psi) times its volume (V2, bbl) in another.
This disregards the effects of temperature (T) and gas compressibility (z).
Current Revision:
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SECTION Q – WELL CONTROL EQUATIONS
14.
Pump Output (bbl/min)
bbl
______
strokes
x
stroke
15.
bbl
________
=
min
min
100% Triplex Pump Capacity (bbl/stroke)
[ Liner ID (in) ]2
______________
Stroke Length (in)
x
_________________
1029
16.
______
bbl
x 3 =
12
_______
stroke
Surface To Bit Strokes (strokes)
Drill String Internal Volume(bbl) = strokes
bbl/stroke
17.
Circulating Time (min)
Volume (bbl)
Pump Output (bbl/min)
18.
=
Open Hole Capacity Factor (bbl/ft)
[ Open Hole Diameter (in) ]2
1029
19.
min
=
bbl
ft
=
bbl
ft
Pipe Capacity Factor (bbl/ft)
[ Pipe Inside Diameter (in) ]2
1029
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SECTION Q – WELL CONTROL EQUATIONS
20.
Annulus Capacity Factor, ACF (bbl/ft)
[ Open Hole Diameter (in) ]2 - [ Pipe Outside Diameter (in) ] 2
1029
=
bbl
ft
or
[ Casing Inside Diameter (in) ]2 - [ Pipe Outside Diameter (in) ] 2
1029
21.
Pipe Displacement (bbl/ft)
(disregarding tool joints)
[ Pipe Outside Diameter (in) ]2 - [ Pipe Outside Diameter (in) ] 2
1029
22.
bbl
ft
=
Total Pipe Displacement (bbl/ft)
=
bbl
ft
(disregarding tool joints)
[ Pipe Outside Diameter (in) ]2 = bbl
1029
ft
23.
Height of Influx (ft)
Pit Gain (bbl)
Annulus Capacity Factor (bbl/ft)
24.
Pressure Gradient of Influx (psi/ft)
ft
=
(bit on bottom)
 SICP (psi) − SIDPP (psi)  psi
 = ft
 Height of Influx (ft)

Pressure Gradient of Mud (psi/ft) - 
25.
Rate of Kick Rise (ft/hr)
(well shut-in)
Change in SICP (psi)
0.007 x Mud Wt (pcf) x Elapsed Time for Change in SICP (hr)
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= ft
hr
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SECTION Q – WELL CONTROL EQUATIONS
26.
Weight per Foot of Drill Collars (lb/ft)
lb
2.67 x  [OD (in)]2 - [ID (in)]2  =
 ft

27.
Force (lb)
Pressure (psi) x Area (in2) = lb
28.
Area (in2)
π x [ Diameter (in) ]2 = in2, where π = 3.142
4
29.
Degrees API (@ 600F)
O
30.
API =
141.5
- 131.5
Specific Gravity
Specific Gravity (@ 600F)
Specific Gravity =
31.
141.5___
[oAPI + 131.5]
Mud Weight from Specific Gravity (pcf)
Mud Weight = Specific Gravity x 62.4 pcf
32.
Hang-Off Weight (lb)
Weight of Block
+ Kelly Weight
+ Weight of Compensator
+ Air Weight of Drill Pipe (KB to Hang-Off Ram)
+ 10,000 lbs
_____________
= Weight on Indicator after Hang-Off (lb)
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SECTION Q – WELL CONTROL EQUATIONS
33.
Barite Requirement For Weight-up (100 lb sx)
 15 x Increase in MW 

262.0 - KWM

Barite (sxs) = Volume to Weight-Up (bbls) x 
34.
Cutting Back or Weighting Up One Fluid with Another to Obtain Desired Fluid
Density
Volume of Mixing Fluid to Add (bbls) =
 Starting Fluid Wt (pcf) - Desired Fluid Wt (pcf) 

 Desired Fluid Wt (pcf) - Mixing Fluid Wt (pcf) 
Vol. of Starting Fluid (bbls) x 
35.
Final Density of a Mixture of Fluid (pcf)
Final Fluid Wt (pcf) =
[ Fluid Wt 1 (pcf) x Volume Fluid 1 (cf) ] + [ Fluid Wt 2 (pcf) x Volume Fluid 2 (cf) ]
Volume fluid 1 (cf) + Volume Fluid 2 (cf)
(where cf = 5.62 x bbls)
36.
Final Density of a Mixture of Fluid and a Solid (pcf)
Final Fluid Density (pcf) =
[ Fluid Density (pcf) x Volume Fluid (cf) ] + Weight of Solid Added (lb)
 Weight of Solid Added (lb) 

 True Density of Solid (pcf) 
Volume Fluid (cf) + 
37.
Weight of Solid to Add to a Fluid to Obtain Desired Fluid Weight (lb)
Weight of Solid to Add (lb) =
Volume of Starting Fluid (cf) x True Density of Solid (pcf)
 Desired Fluid Wt (pcf) - Starting Fluid Wt (pcf) 
x 

 True Density of Solid (pcf) - Desired Fluid Wt (pcf) 
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SECTION Q – WELL CONTROL EQUATIONS
VOLUMETRIC CONTROL EQUATIONS
38.
Pressure Increment, PI (psi)
PI = Safety Factor (psi) = psi
3
39.
Fluid Increment, MI (bbl)
MI = PI (psi) x Annulus Capacity Factor (bbl/ft) = bbl
0.007 x Mud Wt (pcf)
40.
Rate of Bubble Rise, ROR (ft/hr)
ROR =
41.
(see Equation 25 above)
Change in Casing Pressure (psi)__________ = ft
0.007 x Mud Wt (pcf) x Elapsed Time for Change (hr)
hr
Time to Bubble Penetration, BPT (hr)
BPT = Depth of Bubble (ft) – Depth of Bit (ft) = hr
ROR (ft/hr) + Stripping Speed (ft/hr)
LUBRICANT AND BLEED EQUATION
42.
Pressure That Can be Bled Off after Lubricating in a Given Volume of Fluid (psi)
Volume Lubricated (bbl) x 0.007 x Fluid Wt (pcf)_ = psi
Capacity Factor (bbl/ft)
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SECTION Q – WELL CONTROL EQUATIONS
STRIPPING AND SNUBBING EQUATIONS
STRIPPING
2
Fp = π x [ OD (in) ] x Well Head Pressure (psi)
4
43.
Pressure Area Force, Fp (lb)
44.
Buoyed Weight of Tubulars, W (lb)
 489 - Mud Wt (pcf) 

489

W = W AIR (lb) x 
[ OD (in) ]2
45.
Barrels to Bleed per Stand (bbls/stand) Bbl/Stand =
___________
x Stand Length (ft)
1029
46.
Volumetric Control Considerations
Pressure Increment, PI (psi)
(see Equation 37 above)
Fluid Increment, MI (bbl)
(see Equation 38 above)
Surface Pressure Increase due to Penetration of the Bubble, SPINCR (psi)
(L
k(DPxOH)
)
- L k (OH) x (PG MUD - PGGAS ) = psi
Open Hole Kick Length, Lk (OH) (ft)
Kick Volume at Penetration (bbl)
LK(OH) =
________________________________
ACFOH (bbl/ft)
DP by Hole Kick Length, Lk (DPx OH) (ft)
Kick Volume at Penetration (bbl)
LK(DPxOH) =
________________________________
ACFDPXOH (bbl/ft)
Rate of Bubble Rise, ROR (ft/hr)
(see Equation 40 above)
Time of Bubble Penetration, BPT (hrs)
(see Equation 41 above)
Current Revision:
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SECTION Q – WELL CONTROL EQUATIONS
SNUBBING
47.
Snub Force, SF (lb)
SF = Fp + Friction Force – W
48.
Neutral Point
SF = 0; Fp = W
W (lb)
49.
Effective String Weight, WE (lb/ft)
WE (lb/ft) =
______
L (ft)
50.
Calculating Effective String Weight and Change in Effective String Weight
after Filling
a)
Effective String Weight no Fluid in the workstring:
W E (Effective String Wt, lb/ft) =
String Wt (lb/ft) – [ OD (in) ]2 x Fluid Wt WELL (pcf)
183.3
Note:
W E and String Wt both have units of lb/ft.
For example, the string weight of 2-7/8” tubing normally would be 6.5 lb/ft.
b)
Increase in the Effective String Weight after the pipe is filled with the same
Fluid Weight that is in the well:
∆ W E (lb/ft) = [ ID (in) ]2 x Fluid Wt WELL (pcf)
183.3
c)
Increase in the Effective String Weight after the pipe is filled with a different
Fluid Weight than the Fluid Weight that is in the well:
∆ W E (lb/ft) = [ ID (in) ]2 x Fluid Wt FILL (pcf)
183.3
d)
After filling the pipe, the Effective String Weight will be:
W E (AFTER FILLING) (lb/ft) = W E + ∆ W E
= String Wt (lb/ft) - [ OD (in) ]2 x Fluid Wt WELL (pcf) + [ ID (in) ]2 x Fluid Wt (pcf)
183.3
183.3
In this case, note that Fluid Wt in the last term above will be Fluid WtWell if
filled with the same fluid, or Fluid Wtfill if filled with a different fluid weight.
Current Revision:
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SECTION Q – WELL CONTROL EQUATIONS
51.
Predicting the Neutral Point
Combining Equations 47 and 48 above gives an equation for the length L (ft) or
pipe that must be run into the well to reach the Neutral Point:
W (lb)
Fp (lb) = W (lb)
and
W E (lb/ft) =
_______
L (ft)
Fp (lb)
L (ft)
=
__________
W
E
a)
(lb/ft)
The Neutral Point occurs in unfilled pipe when the length of pipe run into
the well is:
L (ft)
Fp (lb) ________________
=
2
String Wt (lb/ft) – [ OD (in) ] x Fluid WtWELL (pcf)
183.3
b)
The Neutral Point occurs in filled pipe when the length of pipe run into the
well is:
L (ft)
=
Fp (lb) _______________________________________
2
2
String Wt (lb/ft) – [ OD (in) ] x Fluid WtWELL (pcf) + [ ID (in) ] x Fluid Wt (pcf)
183.3
183.3
In this case, note that Fluid Wt in the final denominator term above will be
Fluid WtWELL if filled with the same fluid, or Fluid WtFILL if filled with a
different fluid weight.
Current Revision:
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SECTION Q – WELL CONTROL EQUATIONS
ACCUMULATOR SIZING
52.
Bottle Capacity Required (gals)
Bottle Vol. (gals) =
Volume Fluid Required (gals)_________________
Precharge Pressure
____________________________
-
Minimum Operating Pressure
53.
Precharge Pressure
____________________________
Maximum Operating Pressure
Volume Useable Fluid Available (gals)
Volume Useable Fluid (gals) =
Precharge Pressure
Bottle Volume x
____________________________
Minimum Operating Pressure
Current Revision:
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Q - 12
-
Precharge Pressure
_____________________________
Maximum Operating Pressure
rd
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SECTION R - WELL CONTROL POLICIES
Table of Contents
Well Control Certification
Certification Requirements.................................................................. R - 5
BOP Equipment Requirements
API Monogram .................................................................................... R - 5
OEM Certification ................................................................................ R - 5
Visual Inspection ................................................................................. R - 5
Elastomer Replacement...................................................................... R - 6
Maintenance Log................................................................................. R - 6
Elastomer Verification ......................................................................... R - 6
Spare Requirements on Rigsite .......................................................... R - 6
Connection Requirements................................................................... R - 7
Locking Devices for Rams .................................................................. R - 7
BOP Elastomer Ratings for H2S and Temperature
Annulars .............................................................................................. R - 7
Fixed Rams ......................................................................................... R - 7
Variable Bore Rams ............................................................................ R - 7
Shear Blind Rams ............................................................................... R - 8
Use of Diverters
Onshore Wells .................................................................................... R - 8
Offshore Wells .................................................................................... R - 8
Use of Shear Blind Rams
Applications Requiring SBR ................................................................ R - 8
Size of Emergency Kill Line................................................................. R - 8
Emergency Kill Line
Hook-Up (Onshore)............................................................................. R - 9
Hook-Up (Offshore)............................................................................. R - 9
Valves.................................................................................................. R - 9
Kill Line
Hook-Up .............................................................................................. R - 9
Valves.................................................................................................. R - 9
Pressure Rating .................................................................................. R - 9
Connections on Kill, Emergency Kill, and Choke Lines
Connection Requirements................................................................. R - 10
Use of Targeted Tees ....................................................................... R - 10
Use of Heavy Duty Elbows ................................................................ R - 10
Use of Chiksans ................................................................................ R - 10
Use of Weco Connections ................................................................ R - 10
Minimum Bore on Kill, Emergency Kill, and Choke Lines
Bore Requirements ........................................................................... R - 11
Current Revision:
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SECTION R - WELL CONTROL POLICIES
Utilizing Flexible Hose
For Choke Line, Kill Line, or Emergency Kill Line ............................ R - 11
Choke Manifolds
Specifications .................................................................................... R - 12
Workover Operations (3M)................................................................ R - 12
Flare Lines
Oil Wells (Onshore)........................................................................... R - 12
Gas Wells (Onshore) ........................................................................ R - 12
Accumulators
Manufacturer ..................................................................................... R - 13
Fluid Requirements ........................................................................... R - 13
Pre-Charge Requirements ................................................................ R - 13
Closing Requirements....................................................................... R - 13
Back-up Charging System ................................................................ R - 13
Location............................................................................................. R - 13
Pressure Testing BOP Equipment
Frequency of Pressure Test.............................................................. R - 14
Minimum Duration of Pressure Test ................................................. R - 14
Pressure Test Fluid ........................................................................... R - 14
Low Pressure Test ............................................................................ R - 14
High Pressure Test ........................................................................... R - 14
Pressure Test Requirements on Deep Gas Wells ............................ R - 14
Pressure Testing Annular.................................................................. R - 15
Use of Test Stump ............................................................................ R - 15
Pressure Testing Wellhead Valves ................................................... R - 15
Documenting Pressure Test Charts.................................................. R - 15
Pressure Testing Higher WP Equipment than Required .................. R - 15
Pressure Testing Accumulator Hydraulic Lines ................................ R - 15
Leak between BOP Stack and Casing Head .................................... R - 16
Drill Pipe Float
Running a Drill Pipe Float.................................................................. R - 16
Gas Busters
Minimum Size Requirements for Oil Rigs ......................................... R - 16
Minimum Size Requirements for Gas Rigs ....................................... R - 17
Encountering Loss Circulation
Loss of Returns in Hydrocarbon-Bearing Zone................................. R - 17
Maintaining Minimum Overbalance
General Requirements for Drilling and WO Applications .................. R - 17
Drilling the Arab-C Reservoir with Water .......................................... R - 18
Reducing Mud Weight to Free Differentially Stuck Pipe ................... R - 18
Isolating Khuff Reservoir
Setting Casing at Top of Khuff Formation......................................... R - 18
Tapered String
Working with a Tapered String.......................................................... R - 18
Current Revision:
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SECTION R - WELL CONTROL POLICIES
Space Out Data
Recording Space Out Data ............................................................... R - 18
Slow Pump Rate Data
Recording Slow Pump Rate Data ..................................................... R - 19
Tripping Pipe
Pulling Out of Hole ............................................................................ R - 19
Running In Hole................................................................................. R - 19
Performing Flow Checks
While Drilling ..................................................................................... R - 19
While Tripping ................................................................................... R - 20
Displacing to Brine on Horizontal Wells ............................................ R - 20
Shutting In Well
Shutting In Well without Flow Checking ............................................ R - 20
While Drilling ..................................................................................... R - 20
While Tripping ................................................................................... R - 21
With BHA across BOP Stack ............................................................ R - 21
Failure of Upper Pipe Rams During a Well Kill Operation
Recommended Action....................................................................... R - 21
BOP Configuration When Running Casing
Running Casing w/ Class ‘B’ 3M Stack ............................................. R - 21
Running Casing w/ Class ‘A’ 3M or 5M Stack................................... R - 22
Running Casing or 7” Liner w/ Class ‘A’ 10M Stack (w/o SBR) ........ R - 22
Running Casing w/ Class ‘A’ 10M Stack (w/ SBR)............................ R - 22
Running 7” Liner w/ Class ‘A’ 10M Stack (w/ SBR)........................... R - 22
Running 4-1/2” Liner w/ Class ‘A’ 10M Stack.................................... R - 22
Running 4-1/2” Pre-Perforated Liner w/ Class ‘A’ 10M Stack ........... R - 23
Shut-In on 4-1/2” Pre-Perforated Liner w/ Class ‘A’ 10M Stack ........ R - 23
Changing Rams or Installing Casing Rams
Isolation Policy .................................................................................. R - 23
Pressure Testing Casing Rams ........................................................ R - 24
Installing Casing Slips
With Multi-Stage Cementing ............................................................. R - 24
BOP Configuration when Running Production Tubing
Running 5-1/2” or 5-1/2”x 4-1/2” w/ Class ‘A’ 10M Stack .................. R - 24
Running Dual Strings Simultaneously w/ Class ‘A’ 5M Stack ........... R - 25
BOP Configuration when Running Production Tubing/Packer
Running Tubing/Packer Simultaneously w/ Class ‘A’ 3 or 5M Stack R - 25
Removing BOP Stack or Production Tree
Isolation Policy for Low GOR Oil Wells ............................................. R - 25
Isolation Policy for High GOR Oil Wells ............................................ R - 25
Isolation Policy for Gas Wells............................................................ R - 25
Isolation Policy for WIW Wells .......................................................... R - 26
Current Revision:
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R-3
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SECTION R - WELL CONTROL POLICIES
Rigging Down on High GOR Wells w/ SSSV
RD Procedure (w/ Little Clearance between Rig and Tree) .............. R - 26
Platform Well Security Prior to Workover Operations
Required Number of Mechanical Barriers of Isolation ...................... R - 26
Running or Pulling Tubing and ESP Cable w/ Workover Rig
BOP Configuration ............................................................................ R - 27
Pressure Testing Annulars................................................................ R - 27
Shut-In Procedure ............................................................................. R - 27
BOP Configuration When Running Test String
Running 3-1/2” Test String w/ Class ‘A’ 10M Stack (w/o SBR) ......... R - 27
Running 3-1/2” Test String w/ Class ‘A’ 10M Stack (w/ SBR) ........... R - 27
Running 3-1/2” Test String w/ Class ‘A’ 5M Stack ............................ R - 28
Rigging Up Surface Well Test Equipment
Installing Surface Lines Upstream of Test Manifold.......................... R - 28
Installing Surface Lines Downstream of Test Manifold ..................... R - 28
Pressure Testing with Nitrogen
Surface Well Test Equipment (Gas Wells) ....................................... R - 28
Lubricator (Gas Wells) ...................................................................... R - 28
Running Electric Line
Electric Line BOP Requirements for Open Hole ............................... R - 29
Electric Line BOP Requirements for Cased Hole ............................. R - 29
Shut-In on Drill Pipe while Logging with Side-Entry Sub ................... R - 29
Fishing Procedure for Stuck Logging Tool in Open Hole.................. R - 30
Running Coiled Tubing
CT BOP Requirements for Low Pressure Wells ............................... R - 30
CT BOP Requirements for High Pressure Wells .............................. R - 30
Current Revision:
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2001
R-4
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SECTION R - WELL CONTROL POLICIES
The well control policies described in this section represent operations and specifications that are
routinely referenced. These policies (as well as the equipment standards and procedures throughout
this Well Control Manual) are considered mandatory. Any deviation from these requirements must
be approved by the General Manager, Drilling and Workover. Compliance shall be the responsibility
of the Saudi Aramco Drilling Foreman (or Liaisonman) as directed by the Drilling Superintendent.
rd
Changes in this 3 Edition of the Saudi Aramco Well Control Manual are indicated by a bold vertical
line in the right margin, opposite the revision.
WELL CONTROL CERTIFICATION
CERTIFICATION REQUIREMENTS
POLICY
ALL SAUDI ARAMCO FOREMEN AND LIAISONMEN, CONTRACT
TOOLPUSHERS, DRILLERS, AND ASSISTANT DRILLERS SHALL HAVE
CURRENT WELL CONTROL CERTIFICATION (EITHER WELL CAP OR
IWCF ARE ACCEPTABLE).
BOP EQUIPMENT REQUIREMENTS
API MONOGRAM
POLICY
ALL NEWLY MANUFACTURED BOP EQUIPMENT SHALL BE API
MONOGRAMMED.
OEM CERTIFICATION
POLICY
A FULL OEM CERTIFICATION OF THE BOP, CHOKE MANIFOLD
(INCLUDING CHOKES) AND ALL RELATED EQUIPMENT (I.E. CLOSING
UNIT, KILL LINE VALVES, CHOKE LINE VALVES, COFLEX HOSE ETC.)
SHALL BE REQUIRED AT CONTRACT START-UP AND CONTRACT
RENEWAL WITH A MAXIMUM PERIOD OF 3 YEARS BETWEEN OEM
RECERTIFICATION.
VISUAL INSPECTION
POLICY
THE BOP SHALL BE OPENED, CLEANED AND VISUALLY INSPECTED
AFTER EVERY NIPPLE DOWN, INCLUDING SERVICING THE MANUAL
LOCK SCREWS.
ELASTOMER REPLACEMENT
POLICY
ELASTOMERS EXPOSED TO WELL FLUIDS SHALL BE REPLACED AT A
MAXIMUM OF EVERY 12 MONTHS, UNLESS VISUAL INSPECTIONS
INDICATE CHANGING EARLIER.
NOTE:
Current Revision:
Previous Revision:
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June
2001
SEAL ELEMENTS FOR 30” ANNULAR PREVENTERS MAY BE
USED UP TO 36 MONTHS (PROVIDED INSPECTIONS ARE
SATISFACTORY, PROPERLY DOCUMENTED, AND THE
EXPIRATION DATE OF THE ELASTOMER IS NOT EXCEEDED).
R-5
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SECTION R - WELL CONTROL POLICIES
MAINTENANCE LOG
POLICY
A MAINTENANCE LOG FOR EACH PIECE OF BOP EQUIPMENT SHALL
BE MAINTAINED.
THIS LOG SHALL INCLUDE (AT A MINIMUM) RECORDS OF ALL
SERVICE AND INSPECTIONS PERFORMED ON THE BOP.
THE LOG WILL TRAVEL WITH CONTRACTOR-OWNED EQUIPMENT
AND SHALL BE KEPT IN THE BOP SHOP FOR SAUDI ARAMCO-OWNED
EQUIPMENT.
ELASTOMER VERIFICATION
POLICY
ALL RIGS SHALL MAINTAIN A LOG BOOK OF BOP SCHEMATICS
DETAILING THE COMPONENTS INSTALLED IN EACH RAM CAVITY.
THE LOG BOOKS SHALL CONTAIN THE PART NUMBER, DESCRIPTION
AND INSTALLATION DATE OF RAM BLOCKS, TOP SEALS, RAM OR
ANNULAR PACKERS AND BONNET/DOOR SEALS.
TO BE WITNESSED AND CO-SIGNED BY THE TOOLPUSHER AND THE
SAUDI ARAMCO DRILLING FOREMAN/ LIAISONMAN.
SPARE REQUIREMENTS ON THE RIGSITE
POLICY
AT LEAST ONE SPARE SET OF RAM SEALS (TOP SEALS AND PACKER
RAMS) FOR ALL RAMS, INCLUDING PACKER RAMS FOR EACH SIZE
TUBING OR DRILLPIPE TO BE USED, BONNET OR DOOR SEALS,
CONNECTING ROD SEALS, PLASTIC PACKING FOR RAM SHAFT
SECONDARY SEALS, RING GASKETS TO FIT FLANGE CONNECTIONS,
AND A SPARE SEAL ELEMENT FOR THE ANNULAR PREVENTER MUST
ON THE RIGSITE.
RAM BLOCKS SHOULD NOT BE DRESSED UNTIL READY TO USE.
CONNECTION REQUIREMENTS
POLICY
ALL BOP EQUIPMENT WITH WORKING PRESSURE OF 3,000 PSI AND
ABOVE SHALL HAVE FLANGED, WELDED, INTEGRAL, OR HUBBED
CONNECTIONS ONLY.
A GRAYLOC CLAMP IS A HUBBED CONNECTION AND IS ACCEPTABLE
FOR ALL PRESSURE APPLICATIONS.
VIBRATOR HOSES ON RIG PUMPS SHALL HAVE MOLDED END
CONNECTIONS. THREADED OR SEAL WELDED CONNECTIONS ARE
NOT ACCEPTABLE.
Current Revision:
Previous Revision:
October 2002
June
2001
R-6
rd
3 Edition
WELL CON T ROL M AN U AL
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SECTION R - WELL CONTROL POLICIES
LOCKING DEVICES FOR RAMS
POLICY
ALL RAM PREVENTERS SHALL BE EQUIPPED WITH MANUAL OR
AUTOMATIC LOCKING DEVICES, WHICH MUST BE LOCKED WHENEVER
THE RAMS ARE CLOSED TO CONTROL THE WELL.
A HAND CRANK/WRENCH OR HAND WHEEL SYSTEM ARE ACCEPTABLE
MANUAL DEVICES. AUTOMATIC DEVICES (AS SHAFFER POSI-LOCKS)
ARE ALSO ACCEPTABLE.
BOP ELASTOMER RATINGS FOR H2S AND TEMPERATURE
ANNULAR UNITS
POLICY
MINIMUM ACCEPTABLE RATINGS
0
3,000 PSI STACK
2.5% H2S AND 180 F
0
5,000 PSI STACK
2.5% H2S AND 180 F
0
10,000 PSI STACK
2.5% H2S AND 180 F
CAMERON, SHAFFER, AND HYDRIL ARE ACCEPTABLE
MANUFACTURERS.
FIXED RAM PREVENTERS
POLICY
MINIMUM ACCEPTABLE RATINGS
0
3,000 PSI STACK
5.0% H2S AND 250 F
0
5,000 PSI STACK
10.0% H2S AND 250 F
0
10,000 PSI STACK
20.0% H2S AND 300 F
CAMERON, SHAFFER, AND HYDRIL ARE ACCEPTABLE
MANUFACTURERS.
VARIABLE BORE RAMS
POLICY
MINIMUM ACCEPTABLE RATINGS
0
3,000 PSI STACK
5.0% H2S AND 250 F
0
5,000 PSI STACK
10.0% H2S AND 250 F
0
10,000 PSI STACK
20.0% H2S AND 250 F
VARIABLE BORE RAMS (VBR) ARE OPTIONAL FOR TAPERED STRING
APPLICATIONS ON CLASS ‘A’ BOP STACKS. HOWEVER, THE VBR
MUST MEET THE MINIMUM SPECIFICATIONS.
ONLY FIXED RAMS SHALL BE USED IN THE MASTER PIPE RAM
POSITION.
CAMERON’S EXTENDED RANGE HIGH TEMPERATURE VBR-II PACKER
(3-1/2” TO 5-7/8” PIPE SIZES) FOR THE CAMERON 13-5/8” U TYPE
BLOWOUT PREVENTER IS ACCEPTABLE FOR 3M AND 5M
APPLICATIONS. THE VBR WAS SUCCESSFULLY TESTED TO 250
DEGREES F WITH A CAMLAST ELASTOMER RATED FOR 20% H2S.
Current Revision:
Previous Revision:
October 2002
June
2001
R-7
rd
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SECTION R - WELL CONTROL POLICIES
SHEAR BLIND RAMS
POLICY
MINIMUM ACCEPTABLE RATINGS
0
3,000 PSI STACK
5.0% H2S AND 250 F
0
5,000 PSI STACK
10.0% H2S AND 250 F
0
10,000 PSI STACK
20.0% H2S AND 300 F
BOTH CAMERON AND SHAFFER ARE ACCEPTABLE MANUFACTURERS.
USE OF DIVERTERS
NIPPLING UP DIVERTERS ONSHORE
POLICY
A CLASS ‘D’ DIVERTER STACK SHALL BE INSTALLED ON THE
CONDUCTOR AND/OR NEXT CASING STRING FOR ALL EXPLORATION
WELLS AND DEVELOPMENT WELLS IN THE SHALLOW GAS AREA OR
AREAS WHERE OFFSET DATA INDICATES SHALLOW GAS WELLS.
ALL OTHER ONSHORE AREAS DO NOT NEED A DIVERTER.
NIPPLING UP DIVERTERS OFFSHORE
POLICY
A CLASS ‘D’ DIVERTER STACK SHALL BE INSTALLED ON THE
CONDUCTOR OF ALL OFFSHORE EXPLORATION WELLS AND WELLS
WHERE OFFSET DATA INDICATES POSSIBLE SHALLOW GAS.
THE DIVERTER LINES MUST HAVE THE CAPABILITY OF DISCHARGING
BELOW THE BOTTOM OF THE HULL DUE TO H2S.
USE OF SHEAR BLIND RAMS
APPLICATIONS REQUIRING SHEAR BLIND RAMS
POLICY
SHEAR BLIND RAMS SHALL BE UTILIZED FOR THE FOLLOWING D&WO
APPLICATIONS
1)
CLASS ‘A’ 10M STACKS (ALL DEEP GAS WELLS)
2)
OFFSHORE CLASS ‘A’ 5M (ALL OFFSHORE WELLS)
3)
ONSHORE CLASS ‘A’ 5M (ALL WELLS WITH > 10% H2S)
4)
GAS CAP WELLS (EITHER 3M OR 5M CLASS ‘A’ STACKS)
5)
POPULATED AREAS
THE SHEAR BLIND RAMS SHALL BE INSTALLED IN THE RAM LOCATION
IMMEDIATELY ABOVE THE DRILLING CROSS.
SIZE OF EMERGENCY KILL LINE
POLICY
THE EMERGENCY KILL LINE SHALL BE 3” ON ALL RIGS WHICH ARE
UTILIZING SHEAR BLIND RAMS.
RIGS UTILIZING A 3M OR 5M CLASS ‘A’ BOP STACK WITH SHEAR BLIND
RAMS SHALL CHANGE FROM A 2” TO 3” EMERGENCY KILL LINE.
WHEN CONNECTING TO A 2” WELLHEAD OUTLET, THE LINE SHALL BE
3” AND MANUAL VALVE 2”.
Current Revision:
Previous Revision:
October 2002
June
2001
R-8
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
SECTION R - WELL CONTROL POLICIES
EMERGENCY KILL LINE
HOOK-UP (ONSHORE)
POLICY
THE EMERGENCY KILL LINE SHALL BE AN INDIVIDUAL LINE WITH
FLANGED STEEL PIPING (OF THE SAME RATED WORKING PRESSURE
AS THE BOP STACK) CONNECTED TO THE WELLHEAD AND EXTENDING
TO THE END OF THE CATWALK.
HOOK-UP (OFFSHORE)
POLICY
THE EMERGENCY KILL LINE SHALL BE AN INDIVIDUAL 5M LINE WITH
THE CAPABILITY OF BEING CONNECTED TO THE CEMENT MANIFOLD
THROUGH THE CHOKE MANIFOLD AS SHOWN IN SECTION J (FIGURE
18A) OR THROUGH A DEDICATED LINE FROM THE RIG FLOOR
CEMENT MANIFOLD. A 3” ID, 5M COFLEX (COFLON LINED) HOSE
SHALL BE RUN BETWEEN THE FIXED PIPING AND APPLICABLE
CASING SPOOL.
VALVES
POLICY
VALVE ARRANGEMENTS ARE DESCRIBED IN SECTION J. ALL VALVES
SHALL BE THE SAME RATED WORKING PRESSURE AS THE BOP
STACK.
A CHECK VALVE IS NOT REQUIRED IN THE EMERGENCY KILL LINE
(WHICH WILL ALLOW MONITORING ANNULUS PRESSURE BELOW THE
MASTER RAM).
KILL LINE
HOOK-UP
POLICY
THE PRIMARY KILL LINE SHALL BE CONNECTED TO EITHER THE STAND
PIPE OR DIRECTLY TO THE MUD PUMPS FOR ALL PRESSURE
APPLICATIONS.
FOR STAND PIPE CONNECTIONS ON 10M APPLICATIONS, AN
ISOLATION VALVE IS REQUIRED BETWEEN THE KILL LINE (10M) AND
THE STAND PIPE MANIFOLD (5M).
VALVES
POLICY
VALVE ARRANGEMENTS ARE DESCRIBED IN SECTION J. ALL VALVES
SHALL BE THE SAME RATED WORKING PRESSURE AS THE BOP
STACK.
PRESSURE RATING
POLICY
Current Revision:
Previous Revision:
THE KILL LINE SHALL HAVE THE SAME PRESSURE RATING AS THE BOP
STACK, INDEPENDENT OF WHETHER THE KILL LINE IS CONNECTED TO
THE STAND PIPE OR THE MUD PUMPS.
October 2002
June
2001
R-9
rd
3 Edition
WELL CON T ROL M AN U AL
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SECTION R - WELL CONTROL POLICIES
CONNECTIONS ON KILL, EMERGENCY KILL, AND CHOKE LINES
CONNECTION REQUIREMENTS
POLICY
ALL LINES SHALL CONSIST OF STEEL PIPING WITH FLANGED,
WELDED, INTEGRAL, OR HUBBED CONNECTIONS ONLY.
COFLEX HOSE (COFLON LINED) MAY BE USED IN LIEU OF OR
COMBINATION WITH STEEL LINE FOR KILL OR EMERGENCY KILL LINE
IN ALL PRESSURE APPLICATIONS (SEE ADDITIONAL DETAILS UNDER
FLEXIBLE HOSES BELOW).
USE OF TARGETED TEES
POLICY
ALL FABRICATED STEEL PIPING SHALL BE STRAIGHT, AS POSSIBLE,
WITH TARGETED TEES OR BLOCK-TEE ELBOWS AT THE TURNS. ALL
TEES MUST BE TARGETED WITH RENEWABLE BLIND FLANGES.
WELDED TEES ARE NOT ACCEPTABLE.
USE OF HEAVY DUTY ELBOWS
POLICY
ONLY TARGETED OR BLOCK-TEE ELBOWS WITH RENEWABLE BLIND
FLANGES ARE ACCEPTABLE.
USE OF CHIKSANS
POLICY
CHIKSANS ARE NOT ACCEPTABLE FOR KILL LINE, EMERGENCY KILL
LINE, OR CHOKE LINE (WASHOUTS IN THE PACKING ELEMENT OF
THE SWIVEL CAN DEVELOP DURING LONG TERM USE).
USE OF WECO CONNECTIONS
POLICY
WECO CONNECTIONS (OTHER THAN THE REMOTE CONNECTIONS AT
THE END OF THE CATWALK) ARE NOT ACCEPTABLE FOR KILL LINE,
EMERGENCY KILL LINE, OR CHOKE LINE (LEAKS IN THE LIP SEAL OF
THE WECO CONNECTION CAN OCCUR WITH GAS, CO2, AND HT/HP
SITUATIONS).
INTEGRAL OR WELDED WECO FIGURE 1502 CONNECTIONS ARE
ACCEPTABLE DOWNSTREAM OF THE BUFFER TANK FOR ALL LAND
APPLICATIONS, PROVIDED THEY ARE MONOGRAMMED TO API 6A.
WECO FIGURE 1502 CONNECTIONS ON THE WELL TEST LINE
(DOWNSTREAM OF THE CHOKE MANIFIOLD) ARE NOT ACCEPTABLE
FOR OFFSHORE OPERATIONS.
FIGURE 602 CONNECTIONS ARE NOT ALLOWED ON ANY DRILLING
OR WORKOVER OPERATION.
Current Revision:
Previous Revision:
October 2002
June
2001
R - 10
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
SECTION R - WELL CONTROL POLICIES
MINIMUM BORE ON KILL, EMERGENCY KILL, AND CHOKE LINES
BORE REQUIREMENTS
POLICY
THE MINIMUM BORE SIZE FOR KILL, EMERGENCY KILL, AND CHOKE
LINES SHALL BE THE SAME SIZE AS THE BORE OF THE WELD NECK
FLANGE USED IN THE PRESSURE APPLICATION, AS INDICATED BELOW.
KILL LINE:
NOMINAL SIZE
WORKING PRESSURE (PSI)
MINIMUM BORE
2-1/16"
2-1/16"
3M AND 5M
10M
1.72”
2.09”
NOMINAL SIZE
WORKING PRESSURE (PSI)
MINIMUM BORE
2-1/16"
3-1/8”
3-1/8”
3-1/16"
3M AND 5M
3M
5M
10M
1.72”
2.93”
2.65”
3.09”
NOMINAL SIZE
WORKING PRESSURE (PSI)
MINIMUM BORE
3-1/8”
3-1/8”
4-1/16"
3M
5M
10M
2.93”
2.65”
4.09”
EMERGENCY KILL LINE:
CHOKE LINE:
ALL LINES SHALL BE WELDED AND PRESSURE TESTED AS PER API
SPECIFICATION 6A.
UTILIZING FLEXIBLE HOSE
FOR KILL LINE, EMERGENCY KILL LINE, OR CHOKE LINE
POLICY
Current Revision:
Previous Revision:
COFLEX FLEXIBLE STEEL HOSE (OR A COMBINATION FLEXIBLE HOSE
AND HARD LINE) MAY BE USED FOR KILL LINE OR EMERGENCY KILL
LINE ON 3M, 5M, AND 10M PSI APPLICATIONS AND CHOKE LINE ON
3M AND 5M PSI APPLICATIONS, IF THE FOLLOWING REQUIREMENTS
ARE SATISFIED,
§
COFLON LINED AND MONOGRAMMED TO API SPECIFICATION
16C.
HOSES
CURRENTLY
IN
THE
FIELD,
NOT
MONOGRAMMED, MAY CONTINUE TO BE USED FOR THE
REMAINING SERVICE LIFE. HOWEVER AS HOSES ARE
REPLACED, THEY MUST BE MONOGRAMMED
§
ALL OTHER COMPONENTS OF THE HOSE AND END-FITTINGS
IN POSSIBLE CONTACT WITH WELLBORE FLUIDS MEET NACE
STANDARD MR-01-75 (LATEST REVISION)
§
ALL END-FITTINGS SHALL BE FLANGED, WELDED, INTEGRAL,
OR HUBBED CONNECTIONS (WHICH ARE MOLDED TO THE
HOSE AND MONOGRAMMED TO API SPECIFICATION 6A)
§
RE-CERTIFICATION BY OEM EVERY 3 YEARS
October 2002
June
2001
R - 11
rd
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WELL CON T ROL M AN U AL
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Oc t obe r 2 0 0 2
SECTION R - WELL CONTROL POLICIES
§
CERTIFIED FOR DRILLING SERVICE (NO WEEP HOLES)
§
PROPERLY SUPPORTED/ANCHORED, WHERE NECESSARY,
WHEN USED AS CHOKE LINE
NUMBER OF CONNECTIONS MINIMIZED WHEN FLEXIBLE
HOSE IS USED IN COMBINATION WITH HARD LINE
§
§
SAME WORKING PRESSURE (OR GREATER) AS BOP STACK
THE USE OF HARD LINE FOR CHOKE LINE IS REQUIRED ON HIGH
PRESSURE GAS WELLS (10M) AND OPTIONAL FOR OIL WELL
APPLICATIONS.
CHOKE MANIFOLDS
SPECIFICATIONS
POLICY
ALL CHOKE MANIFOLDS AND PIPING SHALL MEET SOUR SERVICE
NACE MR-01-75 (LATEST REVISION) AND API SPECIFICATION 6A. ALL
VALVES AND CHOKES SHALL BE MONOGRAMMED TO API 6A AND
MADE TO THE SPECIFIC REQUIREMENTS LISTED IN SECTION J, AS PER
PRESSURE APPLICATION.
NOTE:
IT IS ACCEPTABLE TO CONVERT API MONOGRAMMED ‘DD’
VALVES TO ‘EE’ UNDER API 6A, SECTION 11.
WORKOVER OPERATIONS (3M)
POLICY
ALL WORKOVER RIGS USING A 3,000 PSI CHOKE MANIFOLD SHALL
USE THE MANIFOLD CONFIGURATION DESCRIBED IN SECTION J 4.0.3.
THIS MANIFOLD INCLUDES ONE 3” MINIMUM CHOKE LINE, TWO 3”
MINIMUM FLARE LINES, A MANUAL ADJUSTABLE CHOKE AND A
REMOTE HYDRAULIC CONTROLLED ADJUSTABLE CHOKE.
FLARE LINES
OIL WELLS
POLICY
TWO (2) 3-1/2” EUE FLARE LINES, EACH APPROXIMATELY 400 FEET IN
LENGTH, ARE REQUIRED ON ONSHORE OIL WELLS.
GAS WELLS
POLICY
NOTE:
(ALL WELLS)
FOUR (4) 4-1/2” LTC GAS FLARE LINES AND ONE (1) 3-1/2” EUE LIQUID
FLARE LINE, EACH APPROXIMATELY 1000 FEET IN LENGTH, ARE
REQUIRED ON ONSHORE GAS WELLS.
ELBOWS AND CHIKSANS ON THE FLARE LINE ARE SUSCEPTIBLE TO EROSION
AND WASHOUTS AND ARE NOT ACCEPTABLE (BECAUSE OF THE POTENTIAL
FOR HIGH FLUID VELOCITIES). THE FLARE LINE, AS WITH THE CHOKE LINE,
SHALL BE AS STRAIGHT AS POSSIBLE, WITH TARGETED OR BLOCK-TEE
ELBOWS AT TURNS, AS REQUIRED.
USING DRILL PIPE FOR FLARE LINE IS NOT RECOMMENDED BECAUSE OF THE
DIFFICULTY OF PROPERLY MAKING UP THE CONNECTIONS ON THE GROUND.
Current Revision:
Previous Revision:
October 2002
June
2001
R - 12
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
SECTION R - WELL CONTROL POLICIES
ACCUMULATOR CLOSING UNITS
MANUFACTURER
POLICY
THE BRAND OF CLOSING UNIT USED BY THE DRILLING CONTRACTOR
IS NOT DICATED BY SAUDI ARAMCO; HOWEVER, THE CLOSING UNIT
MUST MEET THE FOLLOWING REQUIREMENTS.
FLUID REQUIREMENTS
POLICY
THE ACCUMULATOR SHALL STORE ENOUGH FLUID UNDER PRESSURE
TO CLOSE ALL PREVENTERS (AND HOLD CLOSED), OPEN THE HCR TO
CHOKE, AND RETAIN 50% OF THE CALCULATED CLOSING VOLUME
WITH A MINIMUM OF 200 PSI ABOVE PRE-CHARGE PRESSURE
WITHOUT ASISTANCE FROM THE CHARGING SYSTEM.
PRE-CHARGE REQUIREMENTS
POLICY
THE ACCUMULATOR SHALL BE PRE-CHARGED WITH NITROGEN AS
PER MANUFACTURER’S SPECIFICATIONS/RECOMMENDATIONS.
THE MINIMUM PRE-CHARGE PRESSURE FOR A 3,000 PSI WORKING
PRESSURE ACCUMULATOR UNIT IS 1,000 PSI.
PRECHARGE PRESSURE SHALL BE CHECKED PRIOR TO CONNECTING
THE CLOSING UNIT TO THE BOP STACK (OR ANY TIME THE
ACCUMULATOR MUST BE COMPLETELY DE-PRESSURIZED).
CLOSING REQUIREMENTS
POLICY
THE ACCUMULATOR SHALL BE CAPABLE OF CLOSING EACH RAM
WITHIN 30 SECONDS.
CLOSING TIME SHALL NOT EXCEED 30 SECONDS FOR ANNULARS
SMALLER THAN 18-3/4” AND 45 SECONDS FOR ANNULARS
PREVENTERS OF 18-3/4” OR LARGER.
BACK-UP CHARGING SYSTEM
POLICY
THE ACCUMULATOR BACK-UP CHARGING SYSTEM SHALL BE
AUTOMATIC, SUPPLIED BY A POWER SOURCE INDEPENDENT FROM
THE POWER SOURCE TO THE PRIMARY ACUMULATOR-CHARGING
SYSTEM, AND POSSESS SUFFICIENT CAPABILITY TO CLOSE ALL BOP
COMPONENTS AND HOLD THEM CLOSED.
LOCATION
POLICY
Current Revision:
Previous Revision:
THE ACCUMULATOR SHALL BE LOCATED AT A REMOTE LOCATION, AT
LEAST 60 FEET DISTANCE FROM THE WELLBORE AND 100 FEET FOR
GAS WELLS.
October 2002
June
2001
R - 13
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WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
SECTION R - WELL CONTROL POLICIES
PRESSURE TESTING BOP EQUIPMENT
FREQUENCY OF PRESSURE TEST
POLICY
BOP EQUIPMENT MUST BE PRESSURE TESTED AS FOLLLOWS
1)
WHEN INSTALLED
2)
BEFORE DRILLING OUT EACH CASING STRING
3)
FOLLOWING THE DISCONNECTION OR REPAIR OF ANY
WELLBORE PRESSURE SEAL IN THE WELLHEAD/BOP
STACK (LIMITED TO THE AFFECTED COMPONENTS
ONLY)
4)
ATLEAST ONCE EVERY TWO WEEKS (+ 2 DAYS)
MINIMUM DURATION OF PRESSURE TEST
POLICY
ALL PRESSURE TESTS SHALL BE HELD FOR A MINIMUM DURATION OF
10 MINUTES WITH NO OBSERVABLE PRESSURE DECLINE.
PRESSURE TEST FLUID
POLICY
ALL PRESSURE TESTS SHALL BE PERFORMED USING WATER.
LOW PRESSURE TEST
POLICY
A LOW PRESSURE TEST TO 300 PSI SHALL BE CONDUCTED ON EACH
PIECE OF BOP EQUIPMENT BEFORE THE HIGH PRESSURE TEST.
HIGH PRESSURE TEST
POLICY
THE HIGH PRESSURE TEST SHALL BE DETERMINED BY THE
FOLLOWING,
INITIAL PRESSURE TEST
1) FULL WORKING PRESSURE, IF TEST PLUG IS USED
2) 80% OF CASING BURST, IF CUP TESTER IS USED
SUBSEQUENT PRESSURE TEST(S)
1)
GREATER THAN MAXIMUM ANTICIPATED SURFACE
PRESSURE, IF A TEST PLUG IS USED
2)
80% OF CASING BURST, IF CUP TESTER IS USED
PRESSURE TEST REQUIREMENTS FOR CLASS ‘A’ 10,000 PSI BOP STACK ON DEEP GAS WELLS
POLICY
FOR KHUFF WELLS (JILH DOLOMITE CASING POINT)
1)
FULL WORKING PRESSURE (10,000 PSI) WHEN INSTALLED
2)
PRESSURE TEST TO 8,500 PSI THEREAFTER
FOR PRE-KHUFF WELLS (JILH DOLOMITE CASING POINT AND BELOW)
1)
FULL WORKING PRESSURE (10,000 PSI) WHEN INSTALLED
2)
PRESSURE TEST TO 10,000 PSI THEREAFTER
FOR K1/MK1 WELLS (WHERE NU OCCURS ABOVE JILH DOLOMITE CP)
1)
FULL WORKING PRESSURE (10,000 PSI) WHEN INSTALLED
2)
PRESSURE TEST TO MAXIMUM ANTICIPATED SURFACE
PRESSURE (5,000 PSI MINIMUM) THEREAFTER
Current Revision:
Previous Revision:
October 2002
June
2001
R - 14
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
SECTION R - WELL CONTROL POLICIES
PRESSURE TESTING ANNULAR PREVENTER
POLICY
ANNULAR PREVENTERS SHALL BE TESTED TO 70% OF THE RATED
WORKING PRESSURE UPON INSTALLATION AND ALL SUBSEQUENT
TESTS.
USE OF TEST STUMP
POLICY
TEST STUMPS ARE AN ACCEPTABLE METHOD OF PRESSURE TESTING
THE BOP STACK AT THE RIGSITE. THE BOTTOM CONNECTION (AND
ALL OTHER CONNECTIONS NOT TESTED) MUST BE TESTED WITH A
TEST PLUG UPON INSTALLATION OF THE BOP STACK.
PRESSURE TESTING WELLHEAD VALVES
POLICY
TEST ALL VALVES ON THE WELLHEAD INDIVIDUALLY TO THEIR
RATED WORKING PRESSURE ON INSTALLATION (USING A VR PLUG)
AND TO 80% OF CASING BURST ON SUBSEQUENT PRESSURE TESTS,
WITH A CUP TESTER LOCATED AT + 90’.
DOCUMENTING PRESSURE TEST CHARTS
POLICY
PRESSURE CHARTS SHOULD INCLUDE THE FOLLOWING,
1)
DATE OF TEST
2)
WELL NAME
3)
DRILLER
4)
TOOLPUSHER
5)
SAUDI ARAMCO REPRESENTATIVE
A STAMP OR LABEL ON THE CHART MAY BE USED TO PROVIDE THIS
INFORMATION.
PRESSURE TESTING HIGHER WORKING PRESSURE BOP EQUIPMENT THAN REQUIRED FOR THE
WELL BEING DRILLED (OIL WELLS ONLY)
POLICY
HIGHER WORKING PRESSURE EQUIPMENT USED ON A NON-GAS
WELL, REQUIRING A LOWER PRESSURE RATING, SHALL BE TESTED
TO THE LOWER PRESSURE REQUIREMENTS.
EXAMPLE:
IF A 5,000 PSI BOP STACK IS USED ON A CLASS ‘B’
3,000 PSI WELL APPLICATION, THEN PRESSURE
TESTS SHALL BE AS REQUIRED FOR A 3,000 PSI
STACK.
PRESSURE TESTING ACCUMULATOR HYDRAULIC LINES
POLICY
MANIFOLD AND BOP HYDRAULIC LINES SHALL BE PRESSURE TESTED
TO 3,000 PSI UPON INSTALLATION TO ENSURE PRESSURE INTEGRITY
AT HIGHER PRESSURES.
THIS PRESSURE TEST IS MANDATORY FOR ALL RIGS.
Current Revision:
Previous Revision:
October 2002
June
2001
R - 15
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
SECTION R - WELL CONTROL POLICIES
LEAK IN FLANGE OR RING GASKET BETWEEN BOP STACK AND CASING HEAD (WHILE TESTING
BOP STACK)
POLICY
FOR LEAK IN 9-5/8” CASING HEAD
1)
SET RBP 100’ ABOVE CASING SHOE (GAS WELLS ONLY)
2)
SET RTTS/STORM VALVE AT + 200’ (W/ + 3000’ OF KILL
STRING)
3)
REMOVE BOP STACK AND REPAIR LEAK
4)
RE-INSTALL BOP STACK AND PRESSURE TEST
5)
RETRIEVE RTTS/STORM VALVE
6)
RETRIEVE RBP (GAS WELLS ONLY)
FOR LEAK IN 13-3/8” CASING HEAD
1)
SET BP 100’ ABOVE CASING SHOE (GAS WELLS ONLY)
2)
SET RTTS/STORM VALVE AT + 200’ (W/ + 3000’ OF KILL
STRING)
3)
REMOVE BOP STACK AND REPAIR LEAK
4)
RE-INSTALL BOP STACK AND PRESSURE TEST
5)
RETRIEVE RTTS/STORM VALVE
6)
DRILL OUT BP (GAS WELLS ONLY)
FOR LEAK IN 18-5/8” CASING HEAD
1)
RIH AND SET CEMENT PLUG AT 500 – 200’. POH
2)
REMOVE BOP STACK AND REPAIR LEAK
3)
RE-INSTALL BOP STACK AND PRESSURE TEST
4)
DRILL OUT CEMENT PLUG
DRILL PIPE FLOAT
GENERAL REQUIREMENTS
POLICY
A DRILL PIPE FLOAT SHALL BE RUN AT ALL TIMES (EXCEPT WHEN
PLANNED OPERATIONS PRECLUDE RUNNING A FLOAT; AS TESTING,
TREATING, OR SQUEEZING).
A PORTED FLOAT IS NOT RECOMMENDED AS THESE PORTS CAN BE
EASILY PLUGGED AND SOMETIMES WASHOUT.
GAS BUSTERS
OIL RIGS
POLICY
MINIMUM SEPARATOR SIZE REQUIREMENTS FOR OIL RIGS
§
SEPARATOR DIAMETER OF 36”
§
SEPARATOR HEIGHT OF 15’
§
MUD LEG OF 7’
§
ONE 8” DIAMETER GAS VENT LINE
NOTE:
VENT LINE SHALL BE FLANGED OR CLAMPED STEEL LINE
ONLY, WITH A MINIMUM LENGTH OF 240’ FROM THE GAS
BUSTER (ONSHORE WELLS). THE FLARE PIT SHALL BE
POSITIONED AWAY FROM THE RESERVE/WASTE PITS TO
PREVENT IGNITION OF ANY WASTE HYDROCARBONS.
AN EXISTING GAS BUSTER (WITH DIFFERENT HEIGHT OR DIAMETER)
MAY COMPLY IF IT’S CAPACITY IS 17.5 BBLS OR GREATER.
Current Revision:
Previous Revision:
October 2002
June
2001
R - 16
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WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
SECTION R - WELL CONTROL POLICIES
GAS RIGS
POLICY
MINIMUM SEPARATOR SIZE REQUIREMENTS FOR GAS RIGS
§
SEPARATOR DIAMETER OF 36”
§
SEPARATOR HEIGHT OF 30’
§
MUD LEG OF 7’
§
TWO 8” DIAMETER GAS VENT LINES
NOTE: VENT LINES SHALL BE FLANGED OR CLAMPED STEEL LINE
ONLY, WITH A MINIMUM LENGTH OF 240’ FROM THE GAS
BUSTER (ONSHORE WELLS). THE FLARE PIT SHALL BE
POSITIONED AWAY FROM THE RESERVE/WASTE PITS TO
PREVENT IGNITION OF ANY WASTE HYDROCARBONS.
AN EXISTING GAS BUSTER (WITH DIFFERENT HEIGHT OR DIAMETER)
MAY COMPLY IF IT’S CAPACITY IS 35 BBLS OR GREATER.
ENCOUNTERING LOSS CIRCULATION
LOSS OF RETURNS IN A HYDROCARBON-BEARING ZONE
POLICY
IF LOSS CIRCULATION IS ANTICIPATED IN A POTENTIAL
HYDROCARBON-BEARING ZONE, RUN LARGE JET NOZZLES AND BHA
WITHOUT MUD MOTOR (IF POSSIBLE).
§
IF LOSS CIRCULATION IS ENCOUNTERED, ATTEMPT TO
REGAIN WITH (2) *LCM PILLS AND/OR CEMENT PLUGS
* FOR ARAB-D OPEN-HOLE PRODUCERS USE ACID SOLUBLE
LCM AND NO CEMENT PLUGS (UNLESS SPECIFICALLY
REQUIRED)
§
IF UNABLE TO REGAIN CIRCULATION, CONTINUE DRILLING
WITH MUD CAP TO NEXT CASING POINT
THE ONLY EXCEPTION TO THIS POLICY IS EXPERIENCING
COMPLETE LOSS CIRCULATION IN THE ARAB-D RSVR ON
A KHUFF/PRE-KHUFF [K2] WELL, WHERE CIRCULATION
MUST BE REGAINED BEFORE CONTINUING DRILLING TO
THE JILH DOLOMITE CASING POINT.
MAINTAINING MINIMUM OVERBALANCE
GENERAL REQUIREMENTS FOR OVERBALANCE FOR DRILLING & WORKOVER APPLICATIONS
POLICY
A MINIMUM OVERBALANCE SHALL BE MAINTAINED ON ALL WELLS AS
INDICATED BELOW,
§
§
§
100 PSI OVERBALANCE ON WATER RESERVOIRS
200 PSI OVERBALANCE ON OIL WELLS
300 PSI OVERBALANCE ON GAS WELLS
WATER FLOWS, AS ARAB-C, MAY BE DRILLED WITH FLOW IF
HYDROCARBONS, H2S, OR HIGH RATES ARE NOT ENCOUNTERED.
Current Revision:
Previous Revision:
October 2002
June
2001
R - 17
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
SECTION R - WELL CONTROL POLICIES
DRILLING THE ARAB-C RESERVOIR WITH WATER
POLICY
DRILL ARAB-C RESERVOIR WITH WATER……….IF WELL KICKS, SHUTIN AND CIRCULATE BOTTOMS-UP THROUGH CHOKE USING THE
‘DRILLER’S’ METHOD.
§
IF HYDROCARBON INFLUX, H2S, OR ‘HIGH RATE’
SALTWATER FLOW, KILL WELL AND CONTINUE DRILLING
WITH MUD
§
IF ‘LOW RATE’ SALTWATER FLOW, CONTINUE DRILLING
WITH THE WELL FLOWING TO CASING POINT AND MUD UP
PRIOR TO RUNNING CASING
REDUCING MUD WEIGHT LESS THAN PORE PRESSURE EQUIVALENT WHEN ATTEMPTING TO FREE
DIFFERENTIALLY STUCK PIPE
POLICY
NEVER REDUCE MUD WEIGHT LESS THAN PORE PRESSURE WHEN
ATTEMPTING TO FREE DIFFERENTIALLY STUCK PIPE.
AVOID PUMPING LARGE VOLUMES OF DIESEL TO FREE STUCK PIPE IN
A GAS ZONE.
GAS SOLUBILITY IN DIESEL CAN MASK A KICK INFLUX.
ISOLATING KHUFF RESERVOIR
SETTING CASING AT THE TOP OF THE KHUFF FORMATION
POLICY
SET CASING AT TOP OF KHUFF FORMATION ONLY ON CRITICAL
WELLS WITH,
§
§
§
§
ABNORMAL LOWER JILH PRESSURE
HIGH DIFFERENTIAL PRESSURE BETWEEN LOWER JILH
AND KHUFF RESERVOIRS
HIGHLY DEVIATED WELL PROFILE
PROXIMITY TO FACILITIES OR POPULATED AREAS
TAPERED STRING
WHEN WORKING WITH A TAPERED STRING
POLICY
ALWAYS BE IN A POSITION TO HAVE AT LEAST ONE STAND OF EITHER
SIZE PIPE AVAILABLE TO PICK UP.
SPACE OUT DATA
RECORDING SPACE OUT DATA
POLICY
Current Revision:
Previous Revision:
SPACE OUT DATA SHALL BE CLEARLY VISIBLE IN THE DOG HOUSE
AND RECORDED IN THE IADC TOUR BOOK EACH TIME THE RIG
PERFORMS A BOP DRILL.
October 2002
June
2001
R - 18
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WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
SECTION R - WELL CONTROL POLICIES
SLOW PUMP RATE DATA
RECORDING SLOW PUMP RATE DATA
POLICY
SLOW PUMP RATE SHALL BE RECORDED IN THE IADC TOUR BOOK
1)
TOURLY
2)
AFTER A MUD WEIGHT CHANGE
3)
AFTER A BIT NOZZLE OR BHA CHANGE
4)
AFTER EACH 500’ OF DEPTH
5)
AFTER A DRILLING OR COMPLETION FLUID TYPE CHANGE
6)
WHENEVER MUD PROPERTIES SIGNIFICATELY CHANGE
ALL FLOW CHECKS SHALL BE 15 MINUTES.
TRIPPING PIPE
PULLING OUT OF HOLE
POLICY
THE FOLLOWING PROCEDURE IS REQUIRED WHEN POH
1)
ENSURE A FULL OPENING SAFETY VALVE, INSIDE BOP,
CLOSING WRENCH, AND CROSSOVER SUBS ARE ON RIG
FLOOR
2)
RECORD DATA ON TRIP SHEET EVERY 5 STANDS FOR DP,
2 STANDS FOR HWDP, AND EVERY STAND FOR DC
3)
COMPARE DATA TO EXPECTED DISPLACEMENT VALUES
AVOID PULLING A WET STRING WHENEVER POSSIBLE.
RUNNING IN HOLE
POLICY
THE FOLLOWING PROCEDURE IS REQUIRED WHEN RIH
1)
ENSURE FULL OPENING SAFETY VALVE, INSIDE BOP,
CLOSING WRENCH, AND CROSSOVER SUBS ARE ON RIG
FLOOR
2)
RUN IN HOLE APPROXIMATELY ONE MINUTE PER STAND
3)
RECORD DATA ON TRIP SHEET EVERY 5 STANDS FOR DP,
2 STANDS FOR HWDP, AND EVERY STAND FOR DC
4)
COMPARE DATA TO EXPECTED DISPLACEMENT VALUES
5)
FILL DRILL PIPE EVERY 10 TO 20 STANDS
USE THE TRIP TANK WHEN RUNNING CASING.
PERFORMING FLOW CHECKS
PERFORMING FLOW CHECKS WHILE DRILLING
POLICY
A FLOW CHECK SHALL BE PERFORMED WHENEVER
1)
DECREASE IN PUMP PRESSURE
2)
INCREASE IN PUMP STROKES
3)
DECREASE IN MUD WEIGHT
4)
INCREASE IN CHLORIDES
5)
GRADUAL INCREASE IN DRILL RATE
6)
DRILLING BREAK
ALL FLOW CHECKS SHALL BE 15 MINUTES.
Current Revision:
Previous Revision:
October 2002
June
2001
R - 19
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
SECTION R - WELL CONTROL POLICIES
PERFORMING FLOW CHECKS WHILE TRIPPING
POLICY
A FLOW CHECK SHALL BE PERFORMED
1)
WHEN THE HOLE IS NOT TAKING THE CORRECT AMOUNT
OF FLUID
2)
BEFORE PUMPING A SLUG
3)
* BEFORE PULLING OUT OF THE HOLE
4)
* AFTER PULLING 5 TO 10 STANDS
5)
WHEN BIT ENTERS CASING SHOE
6)
* PRIOR TO PULLING LAST 5 STANDS
7)
PRIOR TO PULLING THE BHA
* INDICATES ADDITIONAL FLOW CHECKS REQUIRED WHEN A
HYDROCARBON ZONE IS OPEN.
ALL FLOW CHECKS SHALL BE 15 MINUTES.
DISPLACING TO BRINE ON HORIZONTAL WELLS
POLICY
THE FOLLOWING SHALL BE REQUIRED
1)
A BRINE DENSITY THAT WILL PROVIDE THE SAME
OVERBALNCE (AT BOTTOMHOLE TEMPERATURE) AS MUD
WEIGHT UTILIZED
2)
MEASUREMENT OF BRINE DENSITY IN/OUT TO VERIFY
THAT BOTH ARE THE SAME AT SAME TEMPERATURE
3)
A MINIMUM OF ONE HOUR TO WAIT/OBSERVE WELL
AFTER DISPLACING TO BRINE
4)
PUMPING OUT OF THE HOLE FOR MINIMIZED SWABBING,
CONTINUED FILL-UP, AND IMPROVED GAS DISPLACEMENT
IN THE HORIZONTAL OPEN HOLE
SHUTTING IN WELL
SHUTTING IN WELL WITHOUT A FLOW CHECK
POLICY
IMMEDIATE ACTION SHOULD BE TAKEN TO SHUT IN WELL WHENEVER
1)
INCREASE IN PIT GAIN
2)
INCREASE IN FLOW RATE
SHUTTING IN WELL WHILE DRILLING
POLICY
Current Revision:
Previous Revision:
SHUT-IN PROCEDURE (HARD SHUT–IN)
1)
SPACE OUT (SPOT TOOL JOINT)
2)
STOP MUD PUMPS
3)
CLOSE ANNULAR OR UPPER RAM PREVENTER
4)
CONFIRM WELL IS SHUT IN AND FLOW HAS STOPPED
5)
OPEN HCR
October 2002
June
2001
R - 20
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
SECTION R - WELL CONTROL POLICIES
SHUTTING IN WELL WHILE TRIPPING
POLICY
SHUT-IN PROCEDURE (HARD SHUT–IN)
1)
STAB FULL OPEN SAFETY VALVE
2)
CLOSE SAFETY VALVE
3)
SPACE OUT (SPOT TOOL JOINT)
4)
CLOSE ANNULAR OR UPPER RAM PREVENTER
5)
CONFIRM WELL IS SHUT IN AND FLOW HAS STOPPED
6)
OPEN HCR
DO NOT ATTEMPT TO RUN IN HOLE WITH THE WELL FLOWING.
SHUTTING IN WELL WITH BHA ACROSS BOP STACK
POLICY
SHUT-IN PROCEDURE (HARD SHUT–IN)
1)
SET SLIPS
2)
INSTALL CROSSOVER TO FULL OPEN SAEFTY VALVE
3)
STAB FULL OPEN SAFETY VALVE
4)
CLOSE SAFETY VALVE
5)
CLOSE ANNULAR
6)
CONFIRM WELL IS SHUT IN AND FLOW HAS STOPPED
7)
OPEN HCR
8)
INSTALL INSIDE BOP
9)
OPEN SAFETY VALVE
10)
REDUCE CLOSING PRESSURE ON ANNULAR AND STRIP-IN
A STAND OF DRILLPIPE
IN THE EVENT OF A FAILURE IN THE ANNULAR (WITH BHA ACROSS
BOP STACK) AND UNCONTROLLED FLOW, THE BHA SHOULD BE
DROPPED AND WELL SHUT IN WITH THE BLIND RAMS.
FAILURE OF UPPER PIPE RAMS DURING A WELL KILL OPERATION
RECOMMENDED ACTION
POLICY
RECOMMENDED ACTION TO INCLUDE
1)
CLOSE MASTER PIPE RAMS
2)
REPAIR UPPER PIPE RAMS
3)
CLOSE UPPER PIPE RAMS
4)
OPEN MASTER PIPE RAMS
5)
VERIFY UPPER PIPE RAMS ARE HOLDING
6)
CONTINUE WITH WELL KILL
BOP CONFIGURATION WHEN RUNNING CASING
RUNNING CASING OR LINER WITH CLASS ‘B’ 3000 PSI BOP STACK
POLICY
Current Revision:
Previous Revision:
BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING
ANNULAR
: USED AS CASING RAMS
TOP RAM
: BLIND RAMS
MASTER PIPE : DRILL PIPE RAMS
October 2002
June
2001
R - 21
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
SECTION R - WELL CONTROL POLICIES
RUNNING CASING WITH CLASS ‘A’ 3,000 OR 5,000 PSI BOP STACK (WITH OR WITHOUT SBR)
POLICY FOR:
SHORT LINERS (< 2000’)
BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING
ANNULAR
: USED AS CASING RAMS
TOP RAM
: PIPE RAMS
MIDDLE RAM
: BLIND RAMS (OR SHEAR BLIND RAMS)
MASTER PIPE : PIPE RAMS
POLICY FOR:
LONG LINERS (>2000’)
LONG STRINGS
BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING
ANNULAR
:
TOP RAM
: CHANGE PIPE RAMS TO CASING RAMS
MIDDLE RAM
: BLIND RAMS (OR SHEAR BLIND RAMS)
MASTER PIPE : PIPE RAMS
HAVE XO (CASING x DP) ON DRILL FLOOR.
RUNNING CASING OR 7” LINER WITH CLASS ‘A’ 10,000 PSI BOP STACK (WITHOUT SBR)
POLICY
BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING
ANNULAR
:
TOP RAM
: PIPE RAMS
MIDDLE RAM
: CHANGE BLIND RAMS TO CASING RAMS
TOP MASTER
: BLIND RAMS
BTM MASTER
: PIPE RAMS
HAVE XO (CASING x 5” DP) ON DRILL FLOOR.
RUNNING CASING WITH CLASS ‘A’ 10,000 PSI BOP STACK (WITH SBR)
POLICY
BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING
ANNULAR
:
TOP RAM
: CHANGE PIPE RAMS TO CASING RAMS
MIDDLE RAM
: SHEAR BLIND RAMS
TOP MASTER
: BLIND RAMS
BTM MASTER
: PIPE RAMS
HAVE XO (CASING x 5” DP) ON DRILL FLOOR.
RUNNING 7” LINER WITH CLASS ‘A’ 10,000 PSI BOP STACK (WITH SBR)
POLICY
BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING
ANNULAR
: USED AS CASING RAMS
TOP RAM
: PIPE RAMS
MIDDLE RAM
: SHEAR BLIND RAMS
TOP MASTER
: BLIND RAMS
BTM MASTER
: PIPE RAMS
HAVE XO (CASING x 5” DP) ON DRILL FLOOR.
RUNNING 4-1/2” LINER WITH 3-1/2” DP, 5” DP, AND 10,000 PSI CLASS ‘A’ STACK (W/ OR W/O SBR)
POLICY
Current Revision:
Previous Revision:
BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING
ANNULAR
: USED AS CASING RAMS
TOP RAM
: 5” PIPE RAMS
MIDDLE RAM
: BLIND RAMS (OR SHEAR BLIND RAMS)
October 2002
June
2001
R - 22
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
SECTION R - WELL CONTROL POLICIES
TOP MASTER
BTM MASTER
:
:
3-1/2” PIPE RAMS
5” PIPE RAMS
HAVE XO’S (4-1/2” LNR x 3-1/2” DP) AND (3-1/2” DP x 5” DP) ON DRILL
FLOOR.
RUNNING 4-1/2” PRE-PERFORATED LINER WITH 3-1/2” DP, 5” DP, AND 10,000 PSI CLASS ‘A’ BOP
STACK
POLICY
BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING
ANNULAR
:
TOP RAM
: 5” PIPE RAMS
MIDDLE RAM
: BLIND RAMS (OR SHEAR BLIND RAMS)
TOP MASTER
: 3-1/2” PIPE RAMS
BTM MASTER
: 5” PIPE RAMS
HAVE XO’S (4-1/2” LNR x 3-1/2” DP) (3-1/2” DP x 5” DP) ON DRILL FLOOR.
SHUTTING IN ON 4-1/2” PRE-PERFORATED LINER WITH 3-1/2” DP, 5” DP, AND 10,000 PSI CLASS ‘A’
BOP STACK
POLICY
SHUT-IN PROCEDURE:
1)
SET CASING SLIPS
2)
INSTALL XOs TO 5” DP
3)
MAKE UP A STAND OF DP AND RIH
4)
STAB FULL OPEN SAFETY VALVE AND CLOSE VALVE
5)
INSTALL INSIDE BOP AND OPEN SAFETY VALVE
6)
SHUT 5” PIPE RAMS
7)
OPEN HCR
IF THIS PROCEDURE CAN NOT BE ACCOMPLISHED DUE TO THE
AMOUNT OF FLOW (OR 2-3/8” INNER STRING), THE LINER SHALL BE
DROPPED (BY CLOSING PIPE RAMS, HANGING OFF, AND OPENING
PIPE RAM) AND SHUTTING THE BLIND RAMS.
CHANGING RAMS OR INSTALLING CASING RAMS
ISOLATION POLICY WHEN CHANGING RAMS OR INSTALLING CASING RAMS
POLICY
REQUIRES 2 BARRIERS FOR ISOLATION
1)
CLOSED PIPE OR BLIND RAM (MECHANICAL SHUT-OFF)
2)
KILL FLUID (NON-MECHANICAL SHUT-OFF)
MONITOR ANNULUS USING WELLHEAD VALVES.
IF THE BOTTOM MASTER RAM IS TO BE CHANGED, A PACKER AND
STORM VALVE WITH KILL STRING IS REQUIRED FOR A MECHANICAL
BARRIER.
A TEST PLUG OR TUBING HANGER/BPV SHOULD NOT BE USED AS A
MECHANICAL BARRIER IN THIS APPLICATION.
Current Revision:
Previous Revision:
October 2002
June
2001
R - 23
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
SECTION R - WELL CONTROL POLICIES
PRESSURE TESTING CASING RAMS
POLICY
CASING RAMS (AND ANNULAR PREVENTER) SHALL BE PRESSURE
TESTED WITH A TEST PLUG AND CASING JOINT TO THE FOLLOWING
PRESSURES PRIOR TO RUNNING CASING OR LINER,
CASING POINT
ARAB-D AND ABOVE
BASE JILH DOLOMITE
TOP OF KHUFF FM.
KHUFF-D ANHYDRITE
PRE-KHUFF TD
TEST PRESSURE
500 PSI
750 PSI
1500 PSI
1500 PSI
1500 PSI
INSTALLING CASING SLIPS
WITH MULTI-STAGE CEMENTING
POLICY
SET CASING SLIPS AS FOLLOWS
ST
ND
1)
DISPLACE 1 STAGE CEMENT W/ MUD ( 2 , IF 3 STAGE
JOB)
2)
OPEN UPPER MOST DV
3)
CIRCULATE HOLE CLEAN W/ MUD
4)
WOC 4 HRS WITH WELL STATIC (OBSERVING WELL FOR
FLOW)
5)
BREAK CIRCULATION EVERY HOUR TO PREVENT CEMENT
FROM SETTING UP ACROSS PORTS (IF PACKER FAILURE
AND EXPANSION)
6)
CIRCULATE BOTTOMS UP
7)
PICKUP BOP STACK (DO NOT DROP CASING SLIPS)
8)
SET CASING SLIPS PRIOR TO CEMENTING FINAL STAGE
NOTE:
CONSIDER PUMPING SECOND STAGE CEMENT BEFORE
SETTING SLIPS, IF THE PACKER FAILS AND LOSS
CIRCULATION IS EXPERIENCED (ESPECIALLY WITH A
HYDROCARBON OR H2S ZONE OPEN). THIS SITUATION
SHOULD BE REFERRED TO OPERATIONS MANAGEMENT
ON A CASE BY CASE BASIS.
BOP CONFIGURATION WHEN RUNNING PRODUCTION TUBING
RUNNING 5-1/2” PRODUCTION TUBING (OR 5-1/2” x 4-1/2” TUBING) AND CLASS ‘A’ 10,000 PSI BOP
STACK
POLICY
BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING:
ANNULAR
:
TOP RAM
: 5-1/2” PIPE RAMS
MIDDLE RAM
: BLIND RAMS (OR SHEAR BLIND RAMS)
TOP MASTER
: 5-1/2” PIPE RAMS
BTM MASTER
: 5” PIPE RAMS
HAVE XO (5-1/2” x 4-1/2” TBG) ON DRILL FLOOR.
Current Revision:
Previous Revision:
October 2002
June
2001
R - 24
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
SECTION R - WELL CONTROL POLICIES
RUNNING DUAL STRINGS SIMULTANEOUSLY WITH CLASS ‘A’ 5,000 PSI BOP STACK
POLICY
BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING:
ANNULAR
:
TOP RAM
: DUAL RAMS
MIDDLE RAM
: BLIND RAMS
MASTER PIPE : DUAL RAMS
BOP CONFIGURATION WHEN RUNNING PRODUCTION TUBING AND PACKER
RUNNING PRODUCTION TUBING AND PACKER SIMULTANEOUSLY WITH CLASS ‘A’ 3,000 OR 5,000
PSI BOP STACK
POLICY
BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING:
ANNULAR
:
TOP RAM
: **TUBING RAMS
MIDDLE RAM
: BLIND RAMS (OR SHEAR BLIND RAMS)
MASTER PIPE : *DRILL PIPE RAMS
*
DO NOT CHANGE THE MASTER PIPE RAMS TO TUBING RAMS
(THEY SHOULD REMAIN DRILL PIPE RAMS)
THIS WILL ELIMINATE THE NEED FOR RUNING A RBP AND/OR
RTTS AND STORM VALVE.
**
IF A TAPERED STRING IS TO BE RUN, THE UPPER PIPE RAMS
SHALL BE CHANGED TO THE SIZE OF THE MAJOR SECTION OF
TUBING IN THE STRING.
HAVE XO’S (TBG x DP) AND (LARGE TBG x SMALL TBG, FOR TAPERED
STRINGS) ON THE DRILL FLOOR.
IN CASE OF LOSS CIRCULATION, THE HOLE SHALL BE CONTINUOUSLY
FILLED (BOTH TUBING AND BACKSIDE) WHILE RUNNING THE
COMPLETION STRING.
REMOVING BOP STACK OR PRODUCTION TREE
ISOLATION POLICY FOR LOW GOR OIL WELLS
POLICY
REQUIRED BARRIERS FOR OIL WELLS (GOR < 850 SCF/BBL)
2 SHUT-OFFS (ONE MECHANICAL)
FOR DETAILS REFER TO G.I. 1853.001
ISOLATION POLICY FOR HIGH GOR OIL WELLS
POLICY
REQUIRED BARRIERS FOR OIL WELLS (GOR > 850 SCF/BBL)
3 SHUT-OFFS (TWO MECHANICAL)
FOR DETAILS REFER TO G.I. 1853.001
ISOLATION POLICY FOR GAS WELLS
POLICY
Current Revision:
Previous Revision:
REQUIRED BARRIERS FOR GAS WELLS
3 SHUT-OFFS (TWO MECHANICAL)
FOR DETAILS REFER TO G.I. 1853.001
October 2002
June
2001
R - 25
rd
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WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
SECTION R - WELL CONTROL POLICIES
ISOLATION POLICY FOR WATER INJECTION WELLS
POLICY
REQUIRED BARRIERS FOR WIW WELLS (IF POSITIVE WHP)
2 SHUT-OFFS (ONE MECHANICAL)
FOR DETAILS REFER TO G.I. 1853.001
REQUIRED BARRIERS FOR WIW WELLS (IF NO POSITIVE WHP)
1 SHUT-OFF
FOR DETAILS REFER TO G.I. 1853.001
RIGGING DOWN ON HIGH GOR WELLS WITH SSSV
RIG DOWN PROCEDURE (WITH LITTLE CLEARANCE BETWEEN RIG AND TREE)
POLICY
PROCEDURE
1) NU AND PT TREE
2) RETRIEVE WIRELINE PLUG FROM TAIL PIPE
3) CLOSE CROWN VALVE (DO NOT RD WIRELINE UNIT)
4) OPEN WELL FOR CLEAN-UP
5) CLOSE LOWER MASTER VALVE (OBSERVE NEGATIVE TEST)
6) RIH WITH WIRELINE AND SET PLUG
7) BLEED OFF PRESSURE (OBSERVE PLUG IS HOLDING - BARRIER 1)
8) CLOSE SSSV - BARRIER 2
9) SPLIT TREE ABOVE CLOSED LOWER MASTER VALVE- BARRIER 3
10) MOVE THE RIG OUT
11) RE-INSTALL TREE ABOVE THE LOWER MASTER VALVE
12) LATER, RU WIRELINE UNIT AND RETRIEVE THE PLUG
NOTE: A BPV COULD BE INSTALLED RATHER THAN SETTING A
WIRELINE PLUG.
PLATFORM WELL SECURITY REQUIREMENTS PRIOR TO WORKOVER OPERATIONS
REQUIRED NUMBER OF MECHANICAL BARRIERS OF ISOLATION
POLICY
ALL WELLS ON THE SAME PLATFORM SHALL BE SHUT-IN PRIOR TO
WORKOVER OPERATIONS USING TWO (2) MECHANICAL METHODS
OF ISOLATION,
*
Current Revision:
Previous Revision:
§
BELOW SURFACE
*CLOSED AND TESTED SURFACE CONTROLLED SUBSURFACE SAFETY VALVE
§
AT SURFACE
CLOSED MASTER VALVE
PRIOR TO MOVING IN A WORKOVER RIG, FIELD SERVICES WILL
CLOSE THE SUB-SURFACE SAFETY VALVES ON ALL WELLS AND
DE-PRESSURIZE THE PLATFORM. IF A SUB-SURFACE SAFETY
VALVE IS FOUND LEAKING, WELL SERVICES WILL REPLACE THE
VALVE.
October 2002
June
2001
R - 26
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
SECTION R - WELL CONTROL POLICIES
RUNNING OR PULLING TUBING AND ESP CABLE WITH WOROVER RIG
BOP CONFIGURATION WHEN RUNNING OR PULLING TUBING AND ESP CABLE
POLICY
BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING:
ANNULAR
:
ANNULAR
:
BOP STACK
: BASED ON BOP CLASS
PRESSURE TESTING ANNULARS
POLICY
PRESSURE TEST ANNULARS TO 1000 PSI (WITH ESP CABLE).
RECENT SHOP TESTING HAS SHOWN THAT AN ANNULAR CAN HOLD
1000 PSI WITH 3-1/2” TUBING AND 1” CABLE.
SHUT-IN PROCEDURE WHEN RUNNING OR PULLING TUBING AND ESP CABLE
POLICY
SHUT-IN PROCEDURE
1) SHUT-IN WELL WITH ANNULAR (UPPER) USING SAUDI ARAMCO
SHUT-IN PROCEDURE FOR TRIPPING.
2) CUT ESP CABLE WITH MECHANICAL CUTTER AT THE RIG FLOOR
(A WIRE LINE MECHANICAL CUTTER MUST BE ON THE FLOOR)
3) OPEN ANNULAR AND LOWER TUBING
4) CLOSE ANNULAR (UPPER) AROUND TUBING
BOP CONFIGURATION WHEN RUNNING TEST STRING
RUNNING 3-1/2” TEST STRING WITH TEST HEAD AND CLASS ‘A’ 10,000 PSI BOP STACK (W/O SBR)
POLICY
BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING:
ANNULAR
:
TOP RAM
: 5” PIPE RAMS (FOR STIFF JOINT)
MIDDLE RAM
: 3-1/2” PIPE RAMS
TOP MASTER
: BLIND RAMS
BTM MASTER
: 3-1/2” PIPE RAMS
HAVE XO (3-1/2” PH6 x 3-1/2” DP) ON DRILL FLOOR.
RUNNING 3-1/2” TEST STRING WITH TEST HEAD AND CLASS ‘A’ 10,000 PSI BOP STACK (WITH SBR)
POLICY
BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING:
ANNULAR
:
TOP RAM
: 5” PIPE RAMS (FOR STIFF JOINT)
MIDDLE RAM
: SHEAR BLIND RAMS
TOP MASTER
: 3-1/2” PIPE RAMS
BTM MASTER
: 5” PIPE RAMS
CHANGE TOP 5” PIPE RAM TO 3-1/2” PRIOR TO POH WITH TEST
STRING
HAVE XO (3-1/2” PH6 x 3-1/2” DP) ON DRILL FLOOR.
Current Revision:
Previous Revision:
October 2002
June
2001
R - 27
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
SECTION R - WELL CONTROL POLICIES
RUNNING 3-1/2” TEST STRING WITH TEST HEAD AND CLASS ‘A’ 5,000 PSI BOP STACK
POLICY
BOP CONFIGURATION SHALL CONSIST OF THE FOLLOWING:
ANNULAR
:
TOP RAM
: 5” PIPE RAMS (FOR STIFF JOINT)
MIDDLE RAM
: BLIND RAMS
MASTER RAM : 3-1/2” PIPE RAMS
HAVE XO (3-1/2” DP x 5” DP) ON DRILL FLOOR.
RIGGING UP SURFACE WELL TEST EQUIPMENT
INSTALLING SURFACE LINES UPSTREAM OF TEST MANIFOLD
POLICY
ONLY CONNECTIONS WITH METAL-TO-METAL SEALS ARE
ACCEPTABLE (API FLANGED, HUBBED, OR GRAYLOC).
WECO CONNECTIONS ARE NOT ALLOWED (LEAKS IN THE LIP SEAL
CAN OCCUR WITH GAS, CO2, AND HT/HP SITUATIONS).
INSTALLING SURFACE LINES DOWNSTREAM OF TEST MANIFOLD
POLICY
WECO FIGURE 1502 OR GRAYLOC CONNECTIONS ARE ACCEPTABLE
(FIGURE 602 HAMMER UNIONS ARE NOT ALLOWED ON ANY SAUDI
ARAMCO DRILLING AND WORKOVER OPERATIONS).
PRESSURE TESTING WITH NITROGEN
SURFACE WELLTEST EQUIPMENT - GAS WELLS
POLICY
TEST PROCEDURE ON GAS WELLS (W/ 10M WP SURFACE EQUIPMENT)
1)
PRESSURE TEST STRING TO 8,500 PSI
2)
NEGATIVE TEST SURFACE SAFETY VALVE (IF RUN) AND
LOWER MASTER VALVE
3)
PRESSURE TEST DOWNSTREAM OF CHOKE MANIFOLD TO
1,200 PSI WITH WATER
4)
PRESSURE TEST UPSTREAM OF CHOKE MANIFOLD TO
10,000 PSI WITH WATER
5)
PRESSURE TEST DOWNSTREAM OF CHOKE MANIFOLD TO
1,200 PSI WITH NITROGEN
6)
PRESSURE TEST UPSTREAM OF CHOKE MANIFOLD TO
8,000 PSI (80% OF WATER PRESSSURE TEST) WITH
NITROGEN
LUBRICATORS - GAS WELLS
POLICY
Current Revision:
Previous Revision:
IF A LUBRICATOR IS REQUIRED ON A GAS WELL (FOR WELL TESTING,
COMPLETION, OR WORKOVER OPERATIONS), THE LUBRICATOR SHALL
ALSO BE TESTED WITH NITROGEN TO 80% OF WATER PRESSSURE
TEST.
October 2002
June
2001
R - 28
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
SECTION R - WELL CONTROL POLICIES
RUNNING ELECTRIC LINE
ELECTRIC LINE BOP REQUIREMENTS FOR OPEN-HOLE LOGGING APPLICATIONS
POLICY
FOR OPEN-HOLE LOGGING
(OVER-BALANCED CONDITION)
OIL WELLS
WHEN OPEN-HOLE LOGGING, AN ELECTRIC LINE BOP IS NOT
REQUIRED, PROVIDED PRIMARY WELL CONTROL (HYDROSTATIC
PRESSURE > FORMATION PRESSURE) CAN BE MAINTAINED AND
CONFIRMED.
GAS WELLS
AN ELECTRIC LINE BOP AND LUBRICATOR IS RECOMMENDED ON ALL
GAS WELLS.
LUBRICATORS USED FOR OPEN-HOLE LOGGING WITH KILL MUD IN
THE HOLE REQUIRE HYDRO-TESTING ABOVE THE BLIND RAM WITH A
COLUMN OF WATER (AS A MINIMUM).
ELECTRIC LINE BOP REQUIREMENTS FOR CASED HOLE APPLICATIONS (LOGGING/PERFORATING)
POLICY
FOR CASED-HOLE
(UNDER-BALANCED CONDITION)
WELLS WITH MAXIMUM EXPECTED WHP < 5,000 PSI
1)
NIPPLE–UP 5,000 PSI WIRELINE BOP ON TESTHEAD OR
TREE
2)
MINIMUM NUMBER OF RAMS = 2
3)
HYDRAULIC BOP REQUIRED (MANUAL NOT ACCEPTABLE)
0
4)
MINIMUM TEMPERATURE RATING (ELASTOMER) = 250 F
5)
REMOTE GREASE INJECTION UNIT REQUIRED
6)
STUFFING BOX W/ HYDRAULIC OPERATED PACK-OFF
REQUIRED
7)
BALL CHECK VALVE REQUIRED
8)
TOOL CATCHER OPTIONAL
9)
TOOL TRAP REQUIRED
WELLS WITH MAXIMUM EXPECTED WHP = 5,000 – 10,000 PSI
1)
NU 10,000 PSI WIRELINE BOP ON TESTHEAD OR TREE
2)
MINIMUM NUMBER OF RAMS = 3
3)
HYDRAULIC BOP REQUIRED (MANUAL NOT ACCEPTABLE)
0
4)
MINIMUM TEMPERATURE RATING (ELASTOMER) = 300 F
5)
REMOTE GREASE INJECTION UNIT REQUIRED
6)
STUFFING BOX W/ HYDRAULIC OPERATED PACK-OFF
REQUIRED
7)
BALL CHECK VALVE REQUIRED
8)
TOOL CATCHER OPTIONAL
9)
TOOL TRAP REQUIRED
SHUTTING IN WHILE LOGGING WITH SIDE-ENTRY SUB (WIRELINE ACROSS BOP STACK)
POLICY
Current Revision:
Previous Revision:
SHUT-IN PROCEDURE
1)
CLOSE ANNULAR AROUND DRILL PIPE AND WIRELINE TO
RESTRICT FLOW
2)
INSTALL WIRELINE CLAMP TO DRILL PIPE
3)
CUT WIRELINE (ABOVE CLAMP) AT ROTARY TABLE WITH
MANUAL CUTTER
October 2002
June
2001
R - 29
rd
3 Edition
WELL CON T ROL M AN U AL
Drilling & Work ove r
Oc t obe r 2 0 0 2
SECTION R - WELL CONTROL POLICIES
4)
OPEN ANNULAR AND LOWER DP UNTIL WIRELINE IS
BELOW BOP STACK
CLOSE ANNULAR OR UPPERMOST RAM AS PER
APPROVED SHUT-IN PROCEDURE
5)
FISHING PROCEDURE FOR STUCK LOGGING TOOL IN OPEN HOLE
POLICY
STUCK NON-RADIOACTIVE TOOL
1)
PULL OFF ELECTRIC LINE AT ROPE SOCKET
2)
POH WITH ELECTRIC LINE
3)
RIH AND ENGAGE TOOL W/ OVERSHOT ON DRILL STRING
STUCK RADIOACTIVE TOOL
1)
CUT AND STRIP OVER ELECTRIC LINE W/ DRILL STRING
2)
ENGAGE TOOL WITH OVERSHOT
3)
PULL OFF ELECTRIC LINE AT ROPE SOCKET
4)
POH WITH ELECTRIC LINE
NOTE:
MAY CONSIDER STRIPPING OVER THE ELECTRIC LINE ON A
NON-RADIOACTIVE TOOL IF,
§
§
§
HOLE CONDITIONS ARE POOR
LARGE HOLE SIZE COMPARED TO TOOL OD
OPEN HOLE SECTION IS NOT KNOWN TO CONTAIN
HYDROCARBONS
LOGGING COMPANIES HAVE A ‘CIRCULATING SUB’ THAT CAN
BE MADE UP ON THE DRILL STRING (IN THE EVENT OF A
WELL CONTROL SITUATION) TO HANG OFF THE ELECTRIC
LINE AND ENABLE CIRCULATION; HOWEVER, THIS MAY BE
DIFFICULT TO INSTALL WITH A STRONG FLOW UP THE DRILL
PIPE.
RUNNING COILED TUBING
CT BOP REQUIREMENTS FOR LOW PRESSURE APPLICATIONS
POLICY
LOW PRESSURE BOP REQUIREMENTS (< 5,000 PSI)
1)
SIDE DOOR STRIPPER
2)
QUAD BOP
3)
FLOW TEE
TO BE USED WHEN LIFTING OR LIVENING A WELL.
CT BOP REQUIREMENTS FOR HIGH PRESSURE APPLICATIONS
POLICY
HIGH PRESSURE BOP REQUIREMENTS (> 5,000 PSI)
1)
SIDE DOOR STRIPPER
2)
SECOND SIDE DOOR OR RADIAL STRIPPER
3)
QUAD BOP
4)
FLOW TEE
5)
SHEAR/SEAL AND PIPE/SLIP COMPI
TO BE USED WHEN FLOWING THE WELL WITH COILED TUBING IN
THE HOLE.
Current Revision:
Previous Revision:
October 2002
June
2001
R - 30
rd
3 Edition
PRESSURE TESTING BLOWOUT PREVENTERS & RELATED EQUIPMENT
RIG:
PREVIOUS TEST:
WELL NUMBER:
WELL INFORMATION
BLOWOUT PREVENTERS
HOLE
LAST CASING STRING SET
BURST SHOE
SIZE DEPTH SIZE
WT GRADE RATING DEPTH
TESTER
DRILL PIPE DATA
CUP PLUG NONE SIZE
WT GRADE CONN
MUD WEIGHT:
THIS TEST:
UNIT
SIZE
PRESSURE RATING
TYPE
ANNULAR
PSI
PIPE RAMS
BLIND RAMS
PIPE RAMS
PIPE RAMS
PSI
PSI
PSI
PSI
PCF
ACCUMULATOR UNIT DATA
HYDRIL TO BE TESTED @ 70% RATED
WORKING PRESSURE WITH PIPE IN HOLE
NOTE:
SYSTEMS
CAPACITY
USEABLE
OPERATING
PRESSURE
VOLUME
GAL
PSI
GAL
PRECHARGE PRESSURE
DATE LAST CHECKED
PSI
MANIFOLD PRESSURE
ANNULAR
ACCUMULATOR
CUT-IN
PRESSURE
AIR PUMPS
ELECTRIC PUMPS
MANIFOLD
PSI
TEST DETAILS
CUT-OFF
PRESSURE
PSI
PSI
PSI
PSI
PSI
TEST OF AUXILIARY SYSTEMS AS PER SAUDI ARAMCO WELL CONTROL MANUAL
KILL LINE
PSI
CHOKE LINE
MANUAL
HCR
CHECK
KILL
MANUAL
HCR
CHOKE
VALVE
VALVE
VALVE
LINE
VALVE
VALVE
LINE
KELLY
SWACO
LEFT
RIGHT
EMERGENCY KILL LINE
UPPER
LOWER
MANUAL
HCR
KILL
COCK
COCK
VALVE
VALVE
LINE
LOW
HIGH
TIME
LOW
HIGH
REMARKS:
DRILLER SIGNATURE
Revision Date: 10/20/02
Form # 2.0
TOOLPUSHER SIGNATURE
COMPANY REPRESENTATIVE SIGNATURE
Page 1 of 2
PRESSURE TESTING BLOWOUT PREVENTERS & RELATED EQUIPMENT
RIG:
WELL NUMBER:
PREVIOUS TEST:
THIS TEST:
ALTERNATE BI-WEEKLY TESTS WITH
BOP TEST IN PSI AND TIME
CHARGING SYSTEM ISOLATED
TEST PRESSURE
LOW
HIGH
UNIT
ANNULAR
PIPE RAMS
BLIND RAMS
PIPE RAMS
PIPE RAMS
PSI
PSI
PSI
PSI
PSI
DURATION OF TEST
LOW
HIGH
PSI
PSI
PSI
PSI
PSI
CLOSE
MIN
MIN
MIN
MIN
MIN
MIN
MIN
MIN
MIN
MIN
OPEN
SEC
SEC
SEC
SEC
SEC
BOTTLE BANKS ISOLATED
CLOSE
SEC
SEC
SEC
SEC
SEC
SEC
SEC
SEC
SEC
SEC
OPEN
SEC
SEC
SEC
SEC
SEC
ARE THE BELOW ITEMS ON THE RIG AND IN GOOD WORKING ORDER:
YES
YES
NO
ROTATING HEAD AND STRIPPER (PACK-OFF)
ACCUMULATOR BOTTLE AND TEST GAUGE
STRIPPING VALVE (TIW)
FILL ADAPTER FOR NITROGEN BOTTLE
DRILL PIPE BACK PRESSURE VALVE (INSIDE BOP)
SPARE NITROGEN BOTTLES
X-OVER: DC x DP
DRILL PIPE PRESSURE GAUGE
KELLY COCK WRENCH (S)
ANNULAR PRESSURE GAUGE
ADJUSTABLE CHOKES STEM AND BONNETS
DRILL PIPE FLOAT VALVE
MUD GAS SEPARATOR
DE-GASSER
P.V.T. SET TO ALARM AT 10 BBLS
ALL BOLTS, STUDS & NUTS INSTALLED
AND TIGHTEN PROPERLY
CHOKE MANIFOLD LINED UP FOR A HARD SHUT-IN
ALL RING GASKETS ARE NEW
NO
REMARKS:
DRILLER SIGNATURE
Revision Date: 10/20/02
Form # 2.0
TOOLPUSHER SIGNATURE
COMPANY REPRESENTATIVE SIGNATURE
Page 2 of 2
DESCRIPTION OF BLOWOUT PREVENTERS AND INTERNAL COMPONENTS
RIG:
WELL NUMBER:
BLOWOUT PREVENTERS
ANNULAR PREVENTER
SIZE
WORKING PRESSURE
RAM PREVENTERS
SIZE
WORKING PRESSURE
MODEL
MAKE
SERIAL #
ELEMENT PART #
TYPE
PIPE
BLIND
PIPE
PIPE
MAKE
SERIAL #
SINGLE/DOUBLE
INTERNAL COMPONENTS
UNIT
RAM
SIZE
RAM
BLOCK #
RAM
PACKER #
TOP
SEAL #
BONNET/DOOR
SEAL #
CONN. ROD
SEAL #
DATE
INSTALLED
ANNULAR
PIPE RAMS
BLIND RAMS
PIPE RAMS
PIPE RAMS
REMARKS:
DRILLER SIGNATURE
Form # 1.0
TOOLPUSHER SIGNATURE
COMPANY REPRESENTATIVE SIGNATURE
Date: 10/20/02
CAMERON INFORMATION SHEET
01-001
SUBJECT: Cameron High Temperature Shearing Blind Ram (SBR)
Blade and Side Packers for 11” and 13-5/8” Cameron U Type Blowout
Preventers
PURPOSE: To provide information on qualification test results and new
part numbers assigned to qualified blade and side packers
Qualification Requirement: API 16A 2nd Edition, Appendix C plus
additional pressure hold time at elevated temperatures
Test Conditions:
BOP used – Cameron 13-5/8”-10,000 psi U mounted on a special test stump with internal
heating system
Test Fluid – Synthetic hydrocarbon motor oil (to simulate a mineral oil based drilling mud)
Test Temperatures - 250°F, 300°F, and 350°F
Test Pressure – 10,000 psi
Test Durations – API 16A 2nd Edition, Appendix C – One hour pressure hold all test temperatures
- Cameron Requirement – An additional 8 hour pressure hold - 250°F
- An additional 3 hour pressure hold - 300°F and 350°F
Results – Standard Cameron Blade and Side Packers qualify to API 16A, 2nd Edition,
Appendix C high temperature verification test requirements and successfully
complete Cameron required additional 8 hour pressure hold test at 250°F .
- High Temperature Cameron Blade and Side Packers qualify to API 16A,
2nd Edition, Appendix C high temperature verification test requirements and
successfully completed Cameron required additional 3 hour pressure hold test at
300°F and 350°F .
U BOP Shearing Blind Ram
CIS 01-001 / 5-24-01 REV / HT SBRs 11 & 13
U BOP H2S Shearing Blind Ram
1
CAMERON INFORMATION SHEET
01-001
SUBJECT: Cameron High Temperature Shearing Blind Ram (SBR)
Blade and Side Packers for 11” and 13-5/8” Cameron U Type Blowout
Preventers
Applicable Part Numbers
BOP Size - Pressure Rating
Up to 250°F & 5% H2S
Description
Up to 350°F & 35% H2S
11’-10,000 psi
Blade Packer
Side Packer
Side Packer
Top Seal
046910-04-00-01
046751-04-00-01
046752-04-00-01
644217-01-00-01
644834-04-00-01
2164284-04
2164285-04
644703-01-00-01
13-5/8”-10,000 psi
Blade Packer
Side Packer
Side Packer
Top Seal
644435-01-00-01
046751-01-00-02
046752-01-00-02
644223-01-00-01
644834-01-00-01
645427-01
645428-01
644707-01-00-01
For additional information contact Cameron Elastomer Technology (CET), Katy Texas
or your local Cameron representative.
29501 Katy Freeway, Katy, Texas 77494
CIS 01-001 / 5-24-01 REV / HT SBRs 11 & 13
Tel: 281-391-4615 Fax: 281-391-4640
2
Spare Parts List for 13-5/8” 10M
Type “U” Large Bore Shear Bonnet and Shear Rams
High Temperature and H2S Service
Item
Part Number
Description
BONNET ASSEMBLY: LARGE BORE SHEAR, RIGHT HAND, for
13-5/8" 10M WP TYPE 'U' BOP WITH TANDEM BOOSTER,
MANUAL LOCKING SCREW AND BONNET BOLTS, PER API 16A,
T-20, OPERATION TEMP RATING 'BF' (0-350 DEG SERVICE),
NACE, EST. NET WT. = 3,850 LBS.
BONNET ASSEMBLY: LARGE BORE SHEAR, LEFT HAND, for 135/8" 10M WP TYPE 'U' BOP WITH TANDEM BOOSTER, MANUAL
LOCKING SCREW AND BONNET BOLTS, PER API 16A, T-20,
OPERATION TEMP RATING 'BF' (0-350 DEG SERVICE), NACE,
EST. NET WT. = 3,850 LBS.
BONNET BOLT: for LARGE BORE SHEAR Bonnets, 13-5/8"
10M WP TYPE 'U' BOP, MODEL II
BONNET REBUILD KIT: for LARGE BORE SHEAR RAM,
13-5/8" 3M/5M/10M WP TYPE 'U' BOP (parts for ONE
BONNET), 350 DEG SERVICE
Qty
1 EA
1.
2011803-01
2.
2011803-02
3.
041366-12
4.
2164210-09
5.
644573-03-00-01
BONNET SEAL: for 13-5/8" 3M/5M/10M 'U' BOP, PER API
16A, TEMP CLASS "BF" (0-350 DEG SERVICE)
2 EA
6.
645077-36-00-01
SEAL, LIP: CONNECTING ROD; for 13-5/8" 3M-15M,
20-3/4" 3M, 21-1/4" 2M and 26-3/4 3M TYPE 'U' BOP,
5.505" OD X 4.008" ID X 0.938" LG, PER API 16A, TEMP
CLASS "BF" (0-350 DEG SERVICE)
2 EA
7.
644781-03
RAM ASSEMBLY: H2S SHEARING BLIND; UPPER, for 13-5/8"
3M/5M/10M WP TYPE 'U' BOP, CAMRAM 350 (TM)
1 EA
8.
644781-04
RAM ASSEMBLY: H2S SHEARING BLIND; LOWER, for 13-5/8"
3M/5M/10M WP TYPE 'U' BOP, CAMRAM 350 (TM)
1 EA
9.
644581-01-00-01
INSERT BLADE: UPPER, H2S SBR, for 13-5/8" 10M WP TYPE
'U' AND 'T' BOP, PER QP-10005-01
1 EA
10.
644581-02-00-01
INSERT BLADE: LOWER, H2S SBR, for 13-5/8" 10M WP TYPE
'U' AND 'T' BOP, PER QP-10005-01
1 EA
11.
644834-01-00-01
BLADE PACKER: SBR, for 13-5/8" 3M-15M WP TYPE 'U'
BOP, PER API 16A, TEMP CLASS "BF" (0-350 DEG SERVICE)
1 EA
12.
645427-01
SIDE PACKER: SBR, for 13-5/8" 3M-10M WP TYPE 'U' BOP,
CAMRAM 350 (TM)
2 EA
13.
645428-01
SIDE PACKER: SBR, for 13-5/8" 3M-10M WP TYPE 'U' BOP,
CAMRAM 350 (TM)
2 EA
14.
644707-01-00-01
TOP SEAL: for 13-5/8" SBR, 3M/5M/10M WP TYPE 'U' BOP,
CAMRAM 350 (TM) HIGH TEMP, API 16A, TEMP CLASS "BF"
2 EA
15.
644582-01
MODIFIED SET SCREW: for 13-5/8" 10M TYPE ‘U’ UPPER
SHEARING BLIND RAM, .750-10 UN-2
2 EA
16.
200231
PIN: SPIROL - .250 X 1.000 SST 18-8
2 EA
17.
2164148-02
REPAIR KIT: TANDEM SHEAR BOOSTER, COMPOSITE STYLE OR
ORIGINAL STYLE, 11" 15M AND 13-5/8" 3M-10M TYPE 'U'
BOP (QUANITY for 1 UNIT)
1 EA
1 EA
8 EA
2 EA
09/15/02
Spare Parts List for 11” 10M
Type “U” Large Bore Shear Bonnet and Shear Rams
High Temperature and H2S Service
Item
Part Number
Description
Qty
2164067-02
BONNET ASSEMBLY: LARGE BORE SHEAR, RIGHT HAND, for
11" 10M WP TYPE 'U' BOP WITH TANDEM BOOSTER, MANUAL
LOCKING SCREW AND BONNET BOLTS, API 16A, T-20,
OPERATION TEMP RATING 'BF' (0-350 DEGREE SERVICE),
NACE, EST. NET WT. 2,620 LBS.
1 EA
2.
2164067-01
BONNET ASSEMBLY: LARGE BORE SHEAR, LEFT HAND, for
11" 10M WP TYPE 'U' BOP, WITH TANDEM BOOSTER, MANUAL
LOCKING SCREW AND BONNET BOLTS, API 16A, T-20,
OPERATION TEMP RATING 'BF' (0-350 DEGREE SERVICE),
NACE, EST. NET WT. 2,620 LBS.
1 EA
3.
041366-05
BONNET BOLT: for LARGE BORE SHEAR RAM, 11" 10M WP
TYPE 'U' BOP, MODEL II
8 EA
4.
2164210-12
BONNET REBUILD KIT: for LARGE BORE SHEAR RAM, 11"
3M/5M/10M WP TYPE 'U' BOP (PARTS for ONE BONNET),
350 DEGREE SERVICE
2 EA
5.
644573-02-00-01
BONNET SEAL: 11" 3M/5M/10M WP TYPE 'U' BOP, API 16A,
TEMP CLASS "BF" (0-350 DEGREE SERVICE)
2 EA
6.
645077-38-00-01
SEAL, LIP: CONNECTING ROD; fOR 11" 5M/10M WP TYPE
'U' BOP, - 4.867" OD x 3.383" ID x 0.688" LG, API
16A, TEMP CLASS "BF" (0-350 DEGREE SERVICE)
2 EA
7.
645011-01-00-01
RAM ASSEMBLY: H2S SHEARING BLIND; UPPER, for 11"
5M/10M WP, TYPE 'U' BOP, API 16A, TEMP CLASS 'BF'
(0-350 DEGREE SERVICE)
1 EA
8.
645011-02-00-01
RAM ASSEMBLY: H2S SHEARING BLIND; LOWER, for 11"
5M/10M WP, TYPE 'U' BOP, API 16A, TEMP CLASS 'BF'
(0-350 DEGREE SERVICE)
1 EA
9.
645010-01-00-01
INSERT BLADE: UPPER, H2S SBR, for 11" 5M/10M WP
TYPE 'U' BOP, API 16A
1 EA
10.
645010-02-00-01
INSERT BLADE: LOWER, H2S SBR, for 11" 5M/10M WP
TYPE 'U' BOP, API 16A
1 EA
11.
644834-04-00-01
BLADE PACKER: SBR, for 11" 3M-15M WP TYPE 'U' BOP,
API 16A, TEMP CLASS "BF" (0-350 DEGREE SERVICE)
1 EA
12.
2164284-04
SIDE PACKER: FOLDOVER SHEAR RAM, for 11" 3M-10M WP
TYPE 'U' BOP, API 16A, TEMP CLASS "BF" (0-350 DEGREE
SERVICE)
2 EA
13.
2164285-04
SIDE PACKER: FOLDOVER SHEAR RAM, for 11" 3M-10M WP
TYPE 'U' BOP, API 16A, TEMP CLASS "BF" (0-350 DEGREE
SERVICE)
2 EA
14.
644703-01-00-01
TOP SEAL: for 11" SBR, 3M/5M/10M WP TYPE 'U' BOP,
CAMRAM 350 (TM) HIGH TEMP, API 16A, TEMP CLASS "BF"
2 EA
15.
644582-01
MODIFIED SET SCREW: for 11" 10M TYPE ‘U’ UPPER
SHEARING BLIND RAM, .750-10 UN-2
2 EA
16.
200231
PIN: SPIROL - .250 X 1.000 SST 18-8
2 EA
17.
2164148-03
REPAIR KIT: TANDEM SHEAR BOOSTER, COMPOSITE STYLE OR
ORIGINAL STYLE WITH ST/STL END CAP, for 11" 3/5/10M
TYPE 'U' BOP (QUANTITY FOR ONE UNIT)
1 EA
1.
09/15/02
Shaffer
A Varco Company
Spare Parts List for 13-5/8” 10M
Model ‘SL’ Large Bore ‘V’ Shear Rams
High Temperature and H2S Service
Item
Part Number
Description
Qty
1.
124992
BOOSTER KIT: 10” BOOSTER ASSEMBLY CONVERSION KIT FOR
13-5/8” 10M WP TYPE ‘SL’ RAM BOP, NACE (COMPLETE WITH
22 COMPONENTS).
2 EA
2.
114651
RAM SHAFT: POSLOCK FOR 13-5/8" 10M WP TYPE 'SL' BOP,
NACE.
2 EA
3.
132492
RAM SHAFT SUB-ASSEMBLY (RSSA): FOR 13-5/8" 10M WP
TYPE 'SL' BOP, NACE.
2 EA
4.
030102
CYLINDER O-RING:
2 EA
5.
030791
CYLINDER O-RING:
2 EA
6.
030105
CYLINDER BACK-UP RING:
2 EA
7.
030061
MANIFOLD O-RING:
8 EA
8.
030065
HINGE BRACKET O-RING:
4 EA
9.
134481
POSLOCK PISTON ASSEMBLY: FOR 13-5/8" 10M WP TYPE 'SL'
BOP, NACE.
2 EA
10.
RAM V-SHEAR: COMPLETE WITH 13-5/8” 10M WP ULTRATEMP ™
ELASTOMERS (350 DEGREES F AND 20% H2S)
1 EA
11.
RAM RUBBER ASSEMBLY: UPPER, V-SHEAR, ULTRATEMP ™
(350 DEGREES F AND 20% H2S)
1 EA
12.
RAM RUBBER ASSEMBLY: LOWER, V-SHEAR, ULTRATEMP ™
(350 DEGREES F AND 20% H2S)
1EA
10/01/02
CAMERON INFORMATION SHEET
02-001
SUBJECT: Cameron Extended Range High Temperature VBR-II Packers
for Cameron 13-5/8” U Type Blowout Preventers
PURPOSE: To provide information on qualification test results and new
part numbers assigned to 250°F - 5000 psi Extended Range HT VBR-II
packers for the 13-5/8" Cameron U BOP.
Qualification Requirement: API 16A 2nd Edition, Appendix C plus
additional pressure hold time at elevated temperature.
Test Conditions:
BOP used – Cameron 13-5/8”-10,000 psi U BOP mounted on a special test stump with internal
heating system.
Test Fluid – Synthetic hydrocarbon oil (to simulate a mineral oil based drilling mud).
Test Temperatures - 250°F
Test Pressure – 5,000 psi
Test Durations – API 16A 2nd Edition, Appendix C – One hour pressure hold at 250°F
- Cameron-Saudi Aramco Requirement – An additional 7-hour pressure hold at 250°F
Results – Extended Range HT VBR-II Packers P/N 2164765-01 successfully completed:
1-API 16A, 2nd Edition, Appendix C high temperature verification test requirements
for one hour on both 5-7/8" and 3-1/2" pipe mandrels at 250°F and 5000 psi.
2-Cameron-Saudi Aramco requirement - an additional 7 hour pressure hold test on
both 5-7/8" and 3-1/2" pipe mandrels at 250°F and 5000 psi.
Total time at 250°F and 5000 psi, 16 hours.
3-API 16A fatigue test (546 closures and 78 pressure tests) at ambient temperature.
Ram Subassembly P/N 2164806-01
Top Seal P/N 2164807-01
Ram P/N 2164404-01
Extended Range HT VBR-II Packer P/N 2164765-01
250°F - 5000 psi Extended Range HT VBR-II Packer & Top Seal
CIS 02-001 / 6-11-02 / Ext Range HT VBR-II
1
CAMERON INFORMATION SHEET
02-001
SUBJECT: Cameron Extended Range High Temperature VBR-II Packers
for Cameron 13-5/8” U Type Blowout Preventers
Applicable Part Numbers
BOP Size Pressure Rating
13-5/8”
5,000 psi
Description
Part Number
Ram subassembly
Ram
Ext. Range HT VBR-II Packer
HT/SS VBR Top Seal
2164806-01
2164404-01
2164765-01
2164807-01
Note: The Extended Range HT VBR-II packers and HT/SS top seals are molded using CAMLAST(tm)
elastomer, which provides H2S resistance up to 35%.
For additional information contact Cameron Elastomer Technology (CET), Katy Texas
or your local Cameron representative.
29501 Katy Freeway, Katy, Texas 77494
CIS 02-001 / 6-11-02 / Ext Range HT VBR-II
Tel: 281-391-4615 Fax: 281-391-4640
2
Engineering Standard
SAES-B-062
Onshore Wellsite Safety
30 September, 2001
Loss Prevention Standards Committee Members
Abdullah A. Al-Ghamdi, Chief Fire Prevention Engr., Chairman
Al-Sayed, S. M., FPE, Jeddah Area
Al-Sultan, S. A., LFPE, Dhahran Area
Bard T. E., LFPE, Riyadh Area
E.A. Ashoor, LFPE, RT Area
Fadley, G. L., Editor
Nolan, D. P., LFPE, Abqaiq Area
Saudi Aramco DeskTop Standards
Table of Contents
1
2
3
4
5
Scope............................................................. 2
Conflicts and Deviations................................ 2
References..................................................... 2
Definitions...................................................... 3
Determination of Rupture
Exposure Radius (REF)......................... 7
6 Wellsite Location............................................ 8
7 Population Analysis Procedure.................... 11
8 Well Safety Valves and Wellsite Hardware.. 12
9 Abandoned Wells......................................... 15
10 Drilling Rig Access Routes........................... 15
Appendix 1 – Procedure for Determining
Previous Issue: 30 May, 2001 Next Planned Update: 1 June, 2006
Revised paragraphs are indicated in the right margin
Primary contact: Abdullah A. Al-Ghamdi on phone 875-2724
Page 1 of 32
Document Responsibility: Loss Prevention
Issue Date: 30 September, 2001
Next Planned Update: 1 June, 2006
SAES-B-062
Onshore Wellsite Safety
RER of Oil and Gas Wells............ 16
1
2
3
Scope
1.1
This Standard covers the minimum mandatory requirements for site layout,
wellhead protection, access, and flow isolation for all wells including oil and gas
production wells, hydrocarbon injection wells, observation wells, abandoned
wells, suspended wells, and wellsite facilities located onshore. Water injection,
disposal, and supply wells, which are open to or pass through a geological zone
and could produce hydrocarbons, are also covered by this Standard.
1.2
This standard shall apply in the following circumstances:
1.2.1
All new wellsites.
1.2.2
All new wells drilled at existing wellsites.
1.2.3
Existing wells located in areas that have become populated per this
Standard shall be upgraded only when a workover is required for other
remedial work.
Conflicts and Deviations
2.1
Any conflicts between this Standard and other applicable Saudi Aramco
Engineering Standards (SAESs), Saudi Aramco Materials System Specifications
(SAMSSs), Saudi Aramco Standard Drawings (SASDs), or industry standards,
codes, and forms shall be resolved in writing by the Company or Buyer
Representative through the Manager, Loss Prevention Department of Saudi
Aramco, Dhahran.
2.2
Direct all requests to deviate from the Standard in writing to the Company or
Buyer Representative, who shall follow internal company procedure SAEP-302
and forward such requests to the Manager, Loss Prevention Department of Saudi
Aramco, Dhahran.
References
All referenced specifications, standards, codes, forms, drawings, and similar material
shall be of the latest issue (including all revisions, addenda, and supplements) unless
stated otherwise.
3.1
Saudi Aramco References
Page 2 of 32
Document Responsibility: Loss Prevention
Issue Date: 30 September, 2001
Next Planned Update: 1 June, 2006
SAES-B-062
Onshore Wellsite Safety
Saudi Aramco Engineering Procedure
SAEP-302
Instructions for Obtaining a Waiver of a
Mandatory Saudi Aramco Engineering
Requirement
Saudi Aramco Engineering Standards
SAES-B-064
Onshore and Nearshore Pipeline Safety
SAES-J-505
Combustible Gas and Hydrogen Sulfide in Air
Detection Systems
SAES-L-022
Design of Wellhead Piping, Flowlines, Trunklines
and Testlines
SAES-M-006
Fencing
Saudi Aramco Materials System Specification
45-SAMSS-005
Wellhead Equipment
Saudi Aramco Standard Drawings
3.2
AA-036247
Windsock Pole
AA-036454
Remote Controls for Onshore Wells
AB-036685
Wellhead Guard Barrier
Industry Codes and Standards
American Petroleum Institute
API RP 14B
4
Design, Installation, Repair and Operation of
Subsurface Safety Valve Systems
Definitions
Absolute Open Flow (AOF): In general terms, the rate of flow that would be produced
by a well if the only back-pressure at the surface is atmospheric pressure.
Choke: An adjustable pressure control valve that is used to control backpressure on the
well. Controlling the backpressure adjusts the production rate of the well.
Drilling Island: A well site for drilling one or more wells, normally used in populated
areas to minimize land usage. A drilling island is an exclusive land use area.
Drilling Pad: A compacted area of marl located at the well site. The drilling pad is
required to be level for use by drilling and workover rigs.
Page 3 of 32
Document Responsibility: Loss Prevention
Issue Date: 30 September, 2001
Next Planned Update: 1 June, 2006
SAES-B-062
Onshore Wellsite Safety
Gas-Oil Ratio (GOR): The ratio of volume of gas produced from a well in a barrel of
crude oil at standard conditions (14.7 psia, 15°C).
High Pressure Well: Wells where the shut-in wellhead pressure is expected to exceed
20,700 kPa (3000 psig).
Low Pressure Well: Wells where the shut-in wellhead pressure is not expected to
exceed 20,700 kPa (3000 psig).
LFL: Lower flammable limit of a fuel vapor in air mixture. If a vapor/air mixture is
above the LFL, a fire is likely in the presence of an ignition source.
Major Facility: The outer-most security fence, property line, or other demarcation of
land-use claim of refineries, large gas treatment, NGL plants, larger oil processing
facilities, and the property line of any third party manufacturing facilities (Refer to
Table 1 below for examples).
Table 1 - Examples of Major Facilities
Refineries
Gas Treating
NGL
Oil Process
Jeddah
Berri
Juaymah
Abqaiq Plants
Complex
Juaymah
Rabigh
Uthmaniyah
Yanbu
Jeddah
Ras Tanura
Shedgum
Safaniya
Onshore
GOSP
Complex
Tanajib Plants
Complex
Riyadh
Hawiyah
Shaybah
Central
Process
Facilities
Terminals
Ras Tanura
(North &
South)
Yanbu
Non-Aramco
SCEC Power
Generation
(formerly
SCECO)
SWCC
Treatment
Commercial
International
Airports
Jubail or Yanbu
Industrial
Complexes
Haradh
Non-Associated Gas Fields: Areas that are developed for the primary purpose of
producing natural gas. The produced gas is not a by-product of crude oil production.
Population: A grouping of people normally indicated by the existence of buildings.
Separation spacing from a well shall be measured from the nearest fence or other land
mark. For industrial, military, and other larger non-residential land claims, determine
the spacing based on the nearest anticipated development within the confines of the
fence during the anticipated period of drilling.
Page 4 of 32
Document Responsibility: Loss Prevention
Issue Date: 30 September, 2001
Next Planned Update: 1 June, 2006
SAES-B-062
Onshore Wellsite Safety
Populated Area: A well is in a populated area if the population density based on
counting occupied buildings exceeds 20 occupied buildings inside the 30 ppm rupture
exposure radius (RER). In addition, for the purposes of this Standard, a well is in a
populated area if a school, hospital, hotel, penal institution, or retail complex, whether
existing or planned, is inside the 30 ppm RER of that well.
Rupture Exposure Radius (RER):
1)
For toxic effects, the rupture exposure radius refers to the horizontal distance from
a leak source to a specified level of hydrogen sulfide (H2S) concentration in parts
per million (ppm).
2)
For a flammable gas hazard, the rupture exposure radius refers to the horizontal
distance from a leak source to the ½ Lower Flammable Limit (LFL).
Surface Safety Valve (SSV): An automated spring-assisted fail-safe valve installed on
a wellhead to automatically shut in flow during an abnormal condition such as high or
low pressure of the flowline. This can be the upper master valve, a wing valve
(upstream of choke), or a production valve (downstream of the choke).
Suspension Procedure: Wireline or workover rig procedures for securing a standing
well from production on a long-term basis.
Subsurface Safety Valve (SSSV): An automated valve installed below ground level in
the tubing string of an oil or gas well. The SSSV is used to shut in flow during an
abnormal condition. SSSVs, when required, shall be installed 60 m or more below
ground level per API RP 14B.
Wellhead: The valve manifold directly at the top of the well bore. The wellhead
consists of several specialized valves including the following:
a)
Crown Valve: Topmost valve of the wellhead. This valve is used for wireline
and coil tubing access to the well.
b)
Lower Master Valve: The first valve on a wellhead. This is not a surface safety
valve (SSV).
c)
Upper Master Valve: A second isolation gate valve just above the Lower Master
Valve on a wellhead. If this is automated, it is considered a surface safety valve
(SSV).
d)
Wing Valve: The valve on the side branch of the wellhead, normally located
immediately upstream of the choke.
Page 5 of 32
Document Responsibility: Loss Prevention
Issue Date: 30 September, 2001
Next Planned Update: 1 June, 2006
SAES-B-062
Onshore Wellsite Safety
7-1/16" 3M PSI Onshore Production Tree
SAUDI ARAMCO
3M PSI WP WOG
6M PSI TP
Figure 1 - Example of Wellhead (from 45-SAMSS-005, Figure 6)
Page 6 of 32
Document Responsibility: Loss Prevention
Issue Date: 30 September, 2001
Next Planned Update: 1 June, 2006
SAES-B-062
Onshore Wellsite Safety
Wellsite: A wellsite consists of wellhead(s), associated drilling pad, a well flare/burn
pit area or areas, and flare/burn pit buffer zone(s). The entire wellsite constitutes an
exclusive land use area. No other uses are permitted in this area, except as allowed by
this Standard. Size of the wellsite and distances between wellheads shall be specified
by Drilling and Workover Engineering, Drilling Operations, E&P Facilities &
Technology, and the Proponent Operating Department, on a case-by-case basis.
Well Status: Wells that are not flowing oil or gas may be described by the following
terms:
5
a)
Abandoned Well: A well that is permanently plugged with cement. This well
cannot be produced again.
b)
Observation Well: A well drilled to monitor reservoir conditions such as bottomhole pressure in the reservoir.
c)
Suspended Well: A well that has been shut-in on a long term basis with all
productive zones isolated and production shut-off on a long-term basis.
d)
Standing Well: A well that is shut-in awaiting action, such as flowline tie-in or
well perforation, before it can be returned to production.
Determination of Rupture Exposure Radius (RER)
5.1
Three concentric circles representing the three rupture exposure radii - 30 ppm,
100 ppm hydrogen sulfide (H2S) and ½ lower flammable limit (LFL) shall be
plotted from the well's proposed surface location as shown in Figure 2 below.
Refer to Appendix 1 for procedures to determine the RERs.
5.2
For fields, reservoirs, or service not listed in Appendix 1, the rupture exposure
radius shall be obtained from the Saudi Aramco Loss Prevention Department's
Technical Services Unit. In order to calculate the RER, the following
information should be provided with the request: Well composition of produced
fluid (mole %), temperature (Flowing Wellhead Temperature, FWHT), and AOF
for gas wells or maximum flow rate and GOR for oil wells.
Page 7 of 32
Document Responsibility: Loss Prevention
Issue Date: 30 September, 2001
Next Planned Update: 1 June, 2006
SAES-B-062
Onshore Wellsite Safety
Figure 2 – RERs
A well with population inside the 30 ppm H2S RER as shown above is considered to be in
a populated area if the population index is above 20 or if a school, hospital, major facility,
etc, are inside the RER (see 6.3).
6
Wellsite Location
6.1
Wells that are drilled through a hydrocarbon bearing formation shall be located
so that no occupied building or major facility is within the well's 100 ppm H2S
or ½ LFL RER. Minimum spacing shall not be less than that stated in Table 2.
Exceptions:
Farms and other developments used primarily for agriculture.
GOSPs, manifolds, pipelines, Khuff and Jouf gas distribution
facilities, and their associated utilities are allowed to be within the
100 ppm H2S circle but not within the ½ LFL RER nor closer than
the minimum spacing stated in Table 2.
Page 8 of 32
Document Responsibility: Loss Prevention
Issue Date: 30 September, 2001
Next Planned Update: 1 June, 2006
SAES-B-062
Onshore Wellsite Safety
Table 2 - Spacing from Oil and Gas Wells (4)
Facility
Pipelines (1, 2)
Overhead powerlines for site-related CP, etc.
(<69 kV); site related rectifiers
Main overhead powerlines
Saudi Aramco or Government roadways
Divided Limited-Access Expressways
(2)
(2)
Minimum Spacing
from the Wellhead
60 m
100 m
200 m
100 m
150 m
Railroads (3)
150 m
Major electrical distribution centers
450 m
Occupied buildings, major facilities
450 m
Non-well related flares and flare burn pits
450 m
Hospitals and schools
1000 m
1)
The existing elevated marl pad around wellhead(s) on a wellsite shall not be
crossed by a pipeline. Rig access shall not be obstructed by installation of a
pipeline. In addition, the minimum spacing does not apply to flowlines that are
associated with a multi-well wellsite.
2)
New wells may require additional spacing from existing flowlines for wellsite
construction and drilling operations. Spacing shall be increased as needed at
the request of the Drilling Services or Drilling Operations Departments.
3)
Spacing from the well to the closest edge of right-of-way, such as a fence.
4)
Minimum spacing applies to wells drilled after March 30, 2001.
6.2
Water gravity injector, power injector and supply wells that penetrate
hydrocarbon formations shall be spaced the same as hydrocarbon producing
wells. Injector and supply wells that do not penetrate hydrocarbon bearing
formations shall have a basic 60 m minimum spacing requirement from plant
equipment, buildings, etc. Gas injection wells shall use the same location
criteria as producing gas wells.
6.3
A well is in a populated area if the population density index within the 30 ppm
H2S rupture exposure radius exceeds 20, or if a school, hospital, hotel, penal
institution, retail shopping mall, or major facility, existing or planned, is
included within the 30 ppm H2S rupture exposure radius of that well (see Figure
2).
Commentary Notes:
For purposes of this Standard, roads are not deemed to generate
populated areas.
Where wells are located near areas of potential concern, such as
roads, parking areas, or camp sites, the Proponent
Page 9 of 32
Document Responsibility: Loss Prevention
Issue Date: 30 September, 2001
Next Planned Update: 1 June, 2006
SAES-B-062
Onshore Wellsite Safety
Operating/Engineering Department shall determine whether
additional precautionary measures, such as subsurface safety
valves, fencing, etc., are required.
6.4
Wells to be drilled or wells subject to workover in a populated area shall
implement the following additional precautionary measures in addition to the
normal drilling safety program during drilling of hydrocarbon zones. Other
drilling precautionary measures may be added at the request of the Manager,
Loss Prevention or the General Manager of Drilling and Workover.
Precautionary measures during drilling in a populated area:
1.
Rig-site H2S monitoring systems with 24-hour safety man coverage.
2.
Placement of remote H2S monitors in the vicinity of populations and
nearby facilities to monitor H2S levels at those locations in an emergency.
3.
An additional one-hole volume of kill-weight mud available at the drillsite
for immediate use.
4.
Capability of cutting the drill pipe with shear rams.
5.
On-site coverage 24 hours a day by on-site foremen (minimum 2-man
coverage on 12-hour shifts) with authority for immediate ignition of the
well without prior approval in the event of loss of well control.
6.
Capability of burning gas in a controlled release using parallel production
separators and an elevated flare with continuous flare pilot (Only for wells
to protect population within the 30 ppm H2S RER; the use of this
equipment is not required for drilling near GOSPs, process plants or major
facilities).
7.
An enhanced rig-site emergency contingency action plan.
8.
Other applicable safeguards as needed.
Commentary Note:
The requirements of 6.4 are not intended for non-rig flaring.
6.5
Under no circumstances shall population be exposed to over 30 ppm H2S gas
concentration for more than 1 hour.
6.6
Well flare burn pits shall be subject to the same spacing from population and
major facilities as well spacing. The exceptions to 6.1 shall also apply to flare
burn pits. Minimum spacing shall meet Table 3.
Page 10 of 32
Document Responsibility: Loss Prevention
Issue Date: 30 September, 2001
Next Planned Update: 1 June, 2006
SAES-B-062
Onshore Wellsite Safety
6.6.1
Oil wells and low-pressure gas wells shall have at least one flare while
being drilled.
6.6.2
High-pressure gas well shall have two flares while being drilled.
6.6.3
Flare burn pits shall be at predominantly downwind and crosswind
locations, at least 60 meters from the well (300 m for high-pressure gas
wells) ranging from 60 to 270 arc degrees from true North. Flare burn
pits shall be placed to point away from populations and facilities as much
as possible.
6.6.4
If there are two flares, they should be a minimum of 90 degrees and a
maximum of 180 degrees from each other and pointing away from
populations and facilities as much as possible.
Table 3 - Spacing from Well Flare Burn Pits (3)
Facility
Well (1)
Existing Wellheads
Pipelines (Above Ground)
Pipelines (Buried) (2)
Main Overhead Powerlines
Overhead Powerlines for Site-Related CP, etc.,
(<69 kV); Site Related Rectifiers
Powerlines (Buried) (2)
Minimum Spacing
from Oil & Gas Flare Burn Pits
60 m (Oil & LP Gas)
300 m (HP Gas Well)
60 m (Oil & LP Gas)
150 m (HP Gas Well)
60 m
15 m
200 m
100 m
Divided Limited-Access Expressways (3)
15 m
100 m (Oil Wells and LP Gas)
200 m (HP Gas Wells)
450 m (Oil and Gas Wells)
Railroads (3)
200 m
Population
450 m
Non-well Related Flares and Flare Burn Pits
450 m
Saudi Aramco or Government Roadways (3)
Hospitals and Schools
1000 m
1)
Spacing of the flare burn pit from the well being drilled shall be a minimum distance of 60 m
from the well for an oil well and 300 m minimum for a high-pressure gas well. Wells are to
be spaced a minimum of 60 m from the closest edge of a flare burn pit for an oil well or LP
gas well and 150 m from a flare for a HP gas well. A minimum of 60 m buffer zone shall be
maintained around the outside of each burn pit (not on the wellsite side). The edges of the
burn pits shall have a 2 m high berm (minimum elevation above flare outlet center).
2)
Buried CP powerlines, flowlines, and trunklines related to a wellsite shall have no other
spacing restrictions provided the powerlines do not interfere with rig access or future
production flare operations.
3)
Spacing from the closest edge of the flare burn pit to the edge of the right-of-way.
Page 11 of 32
Document Responsibility: Loss Prevention
Issue Date: 30 September, 2001
Next Planned Update: 1 June, 2006
6.7
7
Onshore Wellsite Safety
For existing wells in populated areas, the special precautions in 6.4 shall be used
for workovers. Precautions appropriate for stimulation and wireline work on
existing wells shall be as requested by the Proponent Operating Department,
Drilling and Workover Services, and Loss Prevention as needed.
Population Analysis Procedure
7.1
The boundaries of Saudi Aramco and non-Saudi Aramco development areas,
present and planned, within the rupture exposure radius of a well location shall
be obtained from the Land and Lease Division of Government Affairs Services
Department.
7.2
The population density index at a well location is defined as the sum of the
existing density index and the virtual density index values for the site.
7.3
Buildings having more than 4 stories shall be included in the population density
index as a number of equivalent buildings. The number of equivalent buildings
shall be calculated by dividing the number of stories in the building by 3 and
rounding up to a whole number.
7.4
To determine the existing density index for a well location, count the number of
buildings lying within the rupture exposure radius of the well. The resulting
whole number is the existing density index value.
7.5
For areas within the rupture exposure radius of a well which are planned for
development, the virtual density index shall be calculated as follows:
7.6
8
SAES-B-062
7.5.1
Calculate the land area in square meters (m²) of each development which
is included within the rupture exposure radius of the well.
7.5.2
Multiply the included area by 0.00075 and round up. The resulting
whole number is the virtual density index for this well location.
Not to be included in these calculations are temporary buildings that will be in
place for less than 6 consecutive months or that will be gone by the time the well
is spudded.
Well Safety Valves and Wellsite Hardware
8.1
Hydrocarbon Producing and/or Hydrocarbon Injection Wells - General
Requirements
8.1.1
All well installations shall be in accordance with the specifications
prepared by Saudi Aramco Drilling and Workover Engineering. Refer to
Page 12 of 32
Document Responsibility: Loss Prevention
Issue Date: 30 September, 2001
Next Planned Update: 1 June, 2006
SAES-B-062
Onshore Wellsite Safety
45-SAMSS-005 for the minimum requirements for Saudi Aramco oil and
gas production trees, wellheads, valves and miscellaneous equipment
relating to the wellhead. Naturally flowing hydrocarbon wells shall be
completed in a manner that permits flow only through a tubing string
equipped with a downhole packer or polished bore receptacle.
8.2
8.3
8.1.2
Requirements for wellhead piping, flowlines, trunklines, and testlines are
covered in SAES-L-022.
8.1.3
All wells shall have a manual lower master valve.
8.1.4
At the discretion of the Proponent Operating Department, oil wells may
be equipped with manual remote operators attached to the master valve
and/or wing valve. If manual remote operators are installed on oil wells,
they shall be in accordance with Standard Drawing AA-036454.
8.1.5
Any lockout device used to temporarily hold a surface safety valve
(SSV) in the open position by restricting movement of the valve stem
shall be constructed of fusible materials with a melting point 30°C above
the higher of the flowing wellhead or maximum design ambient
temperature.
Safety Valves for HP Gas Producing Wells
8.2.1
All high-pressure gas production wells shall have at least two springassisted failsafe surface safety valves (SSVs).
8.2.2
The two SSVs shall be triggered when an abnormally high or low
pressure is sensed in the piping to the well. Fusible devices, with a set
point 30°C above the higher of the flowing wellhead or maximum design
ambient temperature, shall be installed on the wellhead to close the
safety valves.
8.2.3
At the discretion of the Proponent Operating Department, addition of
other automated valves, such as subsurface safety valves, shall be
installed as requested.
Safety Valves on Oil Wells and Low Pressure Gas Wells
8.3.1
Where an oil well or low pressure gas well is in a populated area or
where the associated flowline has Location Class 3 or 4 populations (as
specified in Tables 1 and 2 of SAES-B-064), the wellhead shall be
provided with an SSV and SSSV.
Page 13 of 32
Document Responsibility: Loss Prevention
Issue Date: 30 September, 2001
Next Planned Update: 1 June, 2006
SAES-B-062
Onshore Wellsite Safety
8.3.2
For all existing oil wells and low pressure gas wells in populated areas or
where areas become populated due to growth of communities, those
wells shall remain active, but shall require installation of a SSV and
SSSV. The upgrade shall be done only when other needs justify the use
of a rig on the well.
8.3.3
The upper wellhead master valve shall be a spring-assisted fail-safe
surface safety valve (SSV), triggered when an abnormally high or low
pressure is sensed.
8.3.4
A subsurface safety valve (SSSV), per API RP 14B specification, shall
be installed more than 60 m below ground level in oil wells. The SSSV
shall be triggered when an abnormally high or low pressure is sensed.
8.3.5
A fusible device with a melting point 30°C above the higher of the
flowing wellhead temperature or maximum design ambient temperature,
shall be installed on the wellhead to trigger the SSV and SSSV systems.
Commentary Note:
Values for pipeline associated RERs are found in SAES-B064, Tables 1 and 2. Location Class 3 is where the
pipeline RER includes areas with a population index
greater than 30. Location Class 4 is where the pipeline
RER includes 4-story or greater buildings, schools,
hospitals, hotels, prisons, shopping malls or similar retail
complexes.
Table 4 – Well Safety Valves
Additional Drilling
Precautions
Oil/LP Gas Well –
Unpopulated Area (a)
Oil/LP Gas Well –
Populated Area
HP Gas Well
PWI Well –
Unpopulated Area
PWI Well –
Populated Area
No
Automated SSV
No
(a)
Automated SSSV
No
(a)
Yes
Yes
Yes
No
Yes, 2 SSVs
(b)
No
No
No
Yes
No
No
Note a
Even if the well is in an unpopulated area, if the flowline passes through a populated
area per 8.3, an SSV and SSSV shall be required.
Note b
HP gas production wells shall have at least two spring-assisted failsafe SSVs.
Addition of other automated valves, such as subsurface safety valves, shall be
installed where required by the Proponent Operating Department per Section 8.2.
Page 14 of 32
Document Responsibility: Loss Prevention
Issue Date: 30 September, 2001
Next Planned Update: 1 June, 2006
8.4
SAES-B-062
Onshore Wellsite Safety
Hydrocarbon Injection Wells
Hydrocarbon injection well flowlines shall each be provided with a check valve
in the wellhead piping.
8.5
Observation Wells
Wells shall be equipped with the relevant safety devices equivalent in function
to those that would be required for a producing well unless suspended with a
subsurface plug or other acceptable method.
8.6
Suspended Wells
Wells shall be suspended in accordance with Producing Engineering
requirements. Suspension procedures for wells shall be documented by
Producing Operations and shall be available for review.
8.7
8.8
9
Vehicular Crash Protection and Fencing
8.7.1
All wellheads shall be protected with a guard barrier per Saudi Aramco
Standard Drawing AB-036685.
8.7.2
Wellsites in populated areas shall be enclosed by a fence meeting the
specifications of SAES-M-006 (Type III). The fence shall have four
lockable vehicle gates, one in each quadrant locked at all times. Keys
shall be kept with the Proponent Operating Department. Two gates shall
be a minimum of 18 m wide rig-access gates. The locations of these rigaccess gates shall permit access to all wells on the wellsite from either
gate.
A wind sock pole per Saudi Aramco Standard Drawing AA-036247 and a wind
sock per SAMS Catalog Number 21-590-600 are to be permanently installed at
each hydrocarbon production or injection wellsite in populated areas.
Abandoned Wells
The following requirements apply to a wellsite only if all its wells have been
permanently plugged and if it is located in a populated area:
9.1
The perimeter of the drilling pad shall be provided with a fence (SAES-M-006,
Type III) if there is no fence at the perimeter of the buffer zone.
9.2
The fence shall have one lockable vehicle gate 10 m wide.
9.3
One access route 10 m wide shall be maintained to the wellsite gate.
Page 15 of 32
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10
SAES-B-062
Onshore Wellsite Safety
Drilling Rig Access Routes
Two access routes shall be available to each wellsite. These shall meet the following
requirements:
10.1
Each access route shall be 18 m wide, terminating at a rig access gate.
10.2
Vertical clearance over the access routes shall be 14 m minimum.
10.3
An access route shall not include grades or transverse slopes of more than 5%.
10.4
No obstruction is allowed on an access route.
10.5
The minimum radius of curvature of access routes shall be 70 m. The center
point of all access route curves shall be outside the wellsite served.
10.6
One of the access routes required by paragraph 10.1 above shall have within it a
prepared roadway consisting of a compacted marl running surface 0.3 m thick
and 9.0 m wide with 2.5 m wide shoulders, giving a total clear road width of 14
m.
30 May, 2001
30 September, 2001
Revision Summary
Major revision.
Editorial revision to delete "Populated Area" from the heading of Section 6.
Page 16 of 32
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SAES-B-062
Onshore Wellsite Safety
APPENDIX 1 – Procedure for Determining RER of Oil and Gas Wells
Introduction
To allow for more cost-effective well spacing, while at the same time maintaining a safe
distance between wells and exposed populations, SAES-B-062 provides variable
rupture exposure radii (RER) that are based on field and well conditions (i.e., the well
fluid composition and maximum potential release rate).
This appendix is based on a comprehensive analysis of RERs for Saudi Aramco oil and
gas wells. Exploration and Producing Facilities and Technology Department (E&P
FTD) (PRED/1-099-99) provided the data used for the RER calculations. Tables A7
and A8, at the end of this Appendix, summarize the data provide by E&P FTD. The
RER calculations were made in accordance with LPD Guidelines for Determining the
Consequences of Well Blowouts. Note that the information in Tables A7 and A8 are
based on the latest LPD gas dispersion model PHAST (Version 6.0). The RERs may
change in future updates of SAES-B-062 as a result of changes in well data or
refinements in the models. If the information for the well or production zone needed is
not in Appendix 1, contact the Supervisor, Technical Services Unit, Loss Prevention
Department.
The following sections illustrate the use of the correlations for predicting RERs for oil
and gas wells. The correlations are of the form RER = aQb, where a and b are fieldspecific constants and Q is based on the release rate of gas from the well. Correlations
are provided for the following oil and gas fields:
Non-Associated Gas Fields
North Ghawar Areas-Ain Dar and Shedgum
South Ghawar Area-Haradh
Central Ghawar Areas-Uthmaniyah
Qatif
South Ghawar Area-Hawiyah
Berri
Oil Fields
Abqaiq (Abqaiq Cap Gas)
Haradh
Abu Hadriyah
Harmaliyah
Abu Jiffan
Hawiyah
Ain Dar
Khurais
Berri Onshore
Khursaniyah
Dammam
Mazalij
Fadhili
Qatif
Fazran
Shedgum
Page 17 of 32
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SAES-B-062
Onshore Wellsite Safety
Uthmaniyah
The following sections explain and demonstrate the process of RER calculations.
Worksheets for calculating RERs are provided at the end of this Appendix.
Procedure for Determining RER of Gas Wells
Sour gas wells are considered in this Standard to have three Rupture Exposure Radii
(RER): a 100 ppm H2S RER (RER100 ppm), a 30 ppm H2S RER (RER30 ppm) and a ½ LFL
RER (RER½ LFL). Sweet gas wells would only have a RER½ LFL. These radii are used in
SAES-B-062 to determine spacing requirements. Follow these steps when determining
the RER for a gas well.
1.
Identify the gas field and reservoir for the well of interest (Contact Gen Supv'r.,
Oil or Gas Facilities & Projects Division, E&P FTD) and obtain the Absolute
Open Flow (AOF) and mole fraction of hydrogen sulfide (H2S) in the gas stream.
Note that the correlations included in this appendix are based upon the expected
upper and lower range of AOFs and H2S content in the gas stream.
2.
Determine release rate of H2S (QH2S) from the following:
QH2S = (QAOF)(xH2S)
Where xH2S = mole fraction of H2S in gas stream
QAOF = Absolute Open Flowrate of gas from the well, MMscfd
QH2S = maximum release rate of H2S, MMscfd
3.
Use the constants in Table A6 to calculate RER100 ppm, RER30 ppm and RER½ LFL
from the following
RER100 ppm = e(QH2Sf);
RER30ppm = g(QH2Sh);
RER½ LFL = l(QAOF)m
The AOF or H2S concentration of a gas mixture must fall within the limits presented in
Table A6. If an AOF or the H2S concentration is outside the limits, then LPD/TSU will
calculate RER values specifically for the well of interest (users need to supply
LPD/TSU with well name, AOF, gas composition (mole%), and flowing wellhead
temperature).
Example of RER for Gas Well
Page 18 of 32
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SAES-B-062
Onshore Wellsite Safety
As an example, consider a high-pressure gas well in the South Ghawar Area, Hawiyah.
Information available indicates that the anticipated Absolute Open Flow of the well is
100 MMscfd and the H2S concentration is expected to be 3 mole%.
The following steps are necessary to determine the RER:
1.
Data Requirements
The AOF and the H2S concentration are within the ranges specified in Table A6.
Table A6 indicates that the appropriate constants for this field are as follows:
Table A1 - RER Constants for South Ghawar Area,
Hawiyah Field (from Table A6)
RER100 ppm
2.
RER30 ppm
RER½ LFL
e
f
g
h
l
m
245
0.79
700
0.77
11.7
0.54
Calculate maximum H2S release rate
The maximum H2S release rate is given by the following:
QH2S = (QAOF)(xH2S)
= (100 MMscfd)( 3 / 100 )
=3 MMscfd of H2S
3.
Calculate RERs
RER100 ppm = 245[(3).79] = 583 m
RER30 ppm = 700[(3).77] = 1,631 m
RER½LFL = 11.7[(100).54] = 141 m
The RER for this example well are in Table A2.
Table A2 - RER for Example Well
Rupture Exposure Radii
Distance, m
RER100 ppm
583
RER30 ppm
1,631
RER½LFL
141
Page 19 of 32
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SAES-B-062
Onshore Wellsite Safety
Procedure for Determining RER of Oil Wells
Gas is flashed during a large release of crude and is then dispersed downwind. As with
gas wells, oil wells have three Rupture Exposure Radii (RER): a 100 ppm H2S RER
(RER100 ppm), a 30 ppm H2S RER (RER30 ppm) and a ½ LFL RER (RER½LFL). Sweet oil
wells only have a RER½ LFL. These radii are used in SAES-B-062 to determine spacing
requirements and to assist in determining emergency response planning and
notification. Follow these steps when determining the RER for an oil well:
1.
Identify the oil field and reservoir for the well of interest (Contact Gen Supv'r., Oil
or Gas Facilities & Projects Division, E&P FTD) and obtain the maximum oil
flow rate, Gas-Oil Ratio (GOR) and mole fraction of hydrogen sulfide (H2S) in the
oil. The correlations included in this appendix are based upon the expected upper
and lower range of maximum flow rates, gas-oil ratios, and H2S content in the oil.
2.
Use the following equation to calculate the rate of gas flashed from the crude
released at the maximum flow rate:
Qgas = (Qoil)(GOR) /1,000
Where:
Qgas = Release rate of flashed gas, MMscfd
Qoil = Maximum oil release rate, Mbpd
GOR = Gas-Oil Ratio, scf/stb
3.
Calculate the concentration of H2S in the flashed gas from the following
equations:
[xH2S]gas = φ[xH2S]oil
where:
φ = a(GOR)b (Note: a, b are obtained from Table A7)
Determine release rate of H2S (QH2S)
QH2S = (Qgas) ([xH2S]gas) [MMscfd of H2S]
4.
Calculate RER100 ppm
RER100 ppm = e(QH2S)f (Note: e, f are obtained from Table A7)
5.
Calculate RER30 ppm
RER30 ppm = g(QH2S)h (Note: g, h obtained from Table A7).
6.
Calculate RER½ LFL
Page 20 of 32
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SAES-B-062
Onshore Wellsite Safety
RER½ LFL = l(Qgas)m (Note: l, m obtained from Table A7)
If the AOF or H2S concentration do not fall within limits of Table A7, then LPD/TSU
will calculate RER values specifically for the well of interest (users need to supply
LPD/TSU with well name, maximum oil flow rate, oil composition (mole%), gas-oil
ratio, and flowing wellhead temperature).
Example of Oil Well RER Determination
As an example, consider an oil well that is producing Arab-D in the Khurais field.
Available information indicates the well will have a maximum flow rate of 30,000 bpd,
the oil will have an H2S concentration of 2.9 mole %, and the GOR is 277. What are
the RER values for this well?
1.
Available information
The available information is summarized below. The maximum flow rate and the
H2S concentration are within the limits specified in Table A7.
Maximum Flow Rate, Mbpd
30
GOR, scf/stb
277
Mole percent of H2S in Oil
2.9%
Constants for evaluating this well are summarized in Table A3.
Table A3 - RER Constants for Khurais Field (From Table A7)
H2S in Flashed Gas
2.
RER100 ppm
RER30 ppm
½ LFL
a
b
e
f
g
h
l
m
2.2
0
1,285
0.69
2,656
0.64
47.3
0.63
Calculate flashed gas release rate
The flow rate of released gas may be estimated by the following:
Qgas = (30 Mbpd) x (277 scf/stb) = 8.31 MMscfd
3.
Calculate the H2S concentration in flashed gas
φ = a(GOR)b = (2.2) x (277)0 = 2.2
[xH2S]gas = φ[xH2S]oil = (2.2) x (2.9 %) = 6.4%
4.
Calculate H2S release rate
QH2S = (8.31 MMscfd) x (.064) = 0.53 MMscfd H2S
Page 21 of 32
Document Responsibility: Loss Prevention
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5.
SAES-B-062
Onshore Wellsite Safety
Calculate RERs
RER100 ppm = e(QH2S)f
RER100 ppm = (1285)(0.53)0.69 = 829 m
RER30 ppm = g(QH2S)h
RER30 ppm = (2656)(0.53)0.64 = 1,769 m
RER½LFL = l(Qgas)m
RER½LFL = (47.3)(8.3)0.63 = 180 m
Table A4 - RER for Example Oil Well
Rupture Exposure Radii
Distance, m
RER100 ppm
829
RER30 ppm
1,769
RER½LFL
180
Method of Using RER Results
Saudi Aramco uses the maximum of the 30 ppm RER (100 ppm RER with additional
drilling precautions) or the ½ LFL RER to establish the minimum distance between
wells and population or major facilities (note that spacing can never be less than the
minimums stated in Table 2 of the Standard – see Section 5 for more details). The
purpose for this RER method of spacing is to minimize the possibility of exposing
people to either potentially lethal or flammable vapor clouds. Table A5 summarizes the
effects of hydrogen sulfide exposure to people.
Once the RER100 ppm, RER30 ppm, and RER½LFL are known, draw the RERs as circles with
the well at the center (see Figure A1). For sour gas wells, the ½ LFL RER will not
dominate, but it should still be drawn on the map showing RERs.
Page 22 of 32
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SAES-B-062
Onshore Wellsite Safety
Figure A1 - RER Circles Superimposed Over Well Site Map
Page 23 of 32
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SAES-B-062
Onshore Wellsite Safety
Table A5 - Effects of Hydrogen Sulfide on People
H2S
Concentration
(ppm)
0.10
Effect on People
ERPG-1*: The maximum airborne concentration below which it is believed that
nearly all adult males could be exposed for up to 1 hour without experiencing
other than mild transient adverse health effects or perceiving a clearly defined
objectionable odor.
4
Moderate odor, easily detected.
10
Time Weighted Average (TWA) exposure limitation, beginning of eye irritation.
Setting for Warning low level H2S alarm for control rooms and other indoor
areas protected by air intake sensors. Saudi Aramco work permit procedures
require use of SCBA for work in areas with 10 ppm or greater H2S.
15
Short Term Exposure Limit (STEL) for 15 minutes.
20
Warning High H2S Level alarm setting at Saudi Aramco plants per SAES-J-505.
30
ERPG-2*: The maximum airborne concentration below which it is believed that
nearly all adult males could be exposed for up to 1 hour without experiencing or
developing irreversible or other serious health effects or symptoms that could
impair their abilities to take protective action.
Inhalation limit for 60 minutes, threshold limit of possible eye injury.
Setting for Warning High-high Level H2S alarm at Saudi Aramco plants per
SAES-J-505.
50
70 – 150
Headaches, dizziness, sore throat and increasing stress.
100
ERPG-3*: The maximum airborne concentration below which it is believed that
nearly all adult males could be exposed for up to 1 hour without experiencing or
developing life-threatening health effects.
150
Loss of sense of smell.
150 – 300
300
500
1,000
Severe irritation of eyes and lungs.
Immediately Dangerous to Life and Health Concentration: The maximum
airborne concentration to which a healthy male worker can be exposed for as
long as 30 min and still be able to escape without loss of life or irreversible
organ system damage.
Loss of sense of reasoning and balance, loss of consciousness and possible
death in 30 – 60 minutes.
Immediate loss of consciousness and death within a few minutes.
* Emergency Response Planning Guideline (ERPG), American Industrial Hygiene Association.
Page 24 of 32
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SAES-B-062
Onshore Wellsite Safety
Table A6 – Gas Field Constants for RER Calculations
Properties
Field
H2S
(mole%)
min max
Constants
AOF or Qgas
(MMSCFD)
min max
100 ppm
30 ppm
½ LFL
e
f
g
h
l
m
Abqaiq Cap Gas
1.0
5.0
50
150
268
0.73
729
0.73
14.8
0.49
Berri
20
20
50
120
789
0.63
1894
0.64
11.7
0.49
North Ghawar
(Ain Dar and Shedgum)
0.72
6.0
50
150
273
0.75
689
0.81
14.0
0.48
South Ghawar (Haradh)
0.50
2.0
50
125
242
0.71
654
0.67
14.6
0.49
South Ghawar (Hawiyah)
0.5
4.5
50
150
245
0.79
700
0.77
11.7
0.54
Qatif
7.23
11.2
50
120
376
0.74
1032
0.72
11.1
0.50
Uthmaniyah
2.28
9.27
50
175
295
0.80
855
0.76
16.1
0.46
Equations for Oil and Gas Wells:
RER100 ppm = e(QH2S)f
RER30 ppm = g(QH2S)h
RER½LFL = l(QAOF)m
Equations for Oil Wells Only:
[xH2S]gas = φ[xH2S]oil
where φ = a(GOR)b
Note: All RER distances are in meters. QH2S = release rate of H2S, MMSCFD. Qgas = release rate
of gas, MMSCFD
Page 25 of 32
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SAES-B-062
Onshore Wellsite Safety
Table A7 – Oil Fields Constants for RER Calculations
Properties
Constants
H2S (mole%)
in Oil
Qoil (MBD)
min
max
min
max
a
b
e
f
g
h
l
m
Abqaiq
0.93
3.19
2.9
85
11.7
-0.29
815
0.58
1,895
0.58
49.4
0.59
Abu Hadriyah
0.21
2.23
1.9
88
2.2
0
1,024
0.57
2,249
0.55
63.8
0.57
Abu Jiffan
2.58
3.61
10
50
2.5
0
1,182
0.56
2,470
0.55
51.2
0.58
Ain Dar
0.25
2.7
6.9
37
1.7
0
897
0.76
2,251
0.84
45.5
0.42
Berri
1.06
8.92
15
143
33.5
-0.48
1,152
0.53
2,474
0.52
59.1
0.59
Dammam
1.04
2.18
8
52
2.8
0
432
0.48
725
0.49
24.1
0.47
Fadhili
4.13
11.1
5
31
1.5
0
878
0.77
1,949
0.71
51.7
0.54
Fazran
0.66
2.15
4.5
27
1.8
0
273
0.25
911
0.37
38.4
0.29
Haradh
0.02
0.79
5
32
2
0
2,741
0.77
3,825
0.37
50.4
0.52
Harmaliyah
1.69
5.3
6
32
1.6
0
856
0.61
1,980
0.59
45.3
0.44
Hawiyah
0.21
1.05
5
30
2
0
1,173
0.73
2,617
0.71
48.8
0.56
Khurais
0.58
2.94
9
36
2.2
0
1,285
0.69
2,656
0.64
47.3
0.63
Khursaniyah
1.96
4.77
7
43
2
0
1,079
0.59
2,346
0.58
47.9
0.53
Mazalij
1.9
5.47
6.3
37.8
2.2
0
1,232
0.71
2,565
0.67
50.6
0.65
Qatif
3.72
11.95
4
90
1.9
0
1,708
0.34
3,488
0.32
64.6
0.55
Shedgum
0.75
1.57
9
46
1.8
0
630
0.51
1,511
0.49
50.0
0.38
Uthmaniyah
0.23
1.55
9
29
1.8
0
1,438
0.83
3,279
0.83
36.5
0.70
Field
Flash
100 ppm
30 ppm
½ LFL
Page 26 of 32
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SAES-B-062
Onshore Wellsite Safety
Table A8 – Oil Field Data from Exploration and Producing
Components (mole %)
Well Name
Abqaiq
Abqaiq
Abqaiq
Abu Hadriyah
Abu Hadriyah
Abu Hadriyah
Abu Jiffan
Abu Jiffan
Abu Jiffan
Ain Dar
Ain Dar
Ain Dar
Berri
Berri
Berri
Dammam
Dammam
Dammam
Fadhili
Fadhili
Fadhili
Fazran
Fazran
Fazran
Haradh
Haradh
Haradh
Harmaliyah
Harmaliyah
Harmaliyah
Hawiyah
Hawiyah
Hawiyah
Khurais
Khurais
Khurais
Reservoir Range
Arab-D
Min.
Arab-D Wt. Avg.
Arab-C
Max.
Arab-A&B
Min.
Wt. Avg.
Arab-C
Max.
Arab-D
Min.
Arab-D Wt. Avg.
Arab-D
Max.
L. Fadhili
Min.
Arab-D Wt. Avg.
Arab-D
Max.
Arab-B
Min.
Wt. Avg.
Hanifa
Max.
Arab-D
Min.
Wt. Avg.
Arab-D
Max.
Arab-D
Min.
Wt. Avg.
Arab-D
Max.
L. Fadhili
Min.
Wt. Avg.
L. Fadhili
Max.
Arab-D
Min.
Arab-D Wt. Avg.
Arab-D
Max.
Arab-D
Min.
Arab-D Wt. Avg.
Arab-D
Max.
Arab-D
Min.
Arab-D Wt. Avg.
Arab-D
Max.
Arab-D
Min.
Arab-D Wt. Avg.
Arab-D
Max.
N2
0.3
0.1
0.6
0.2
0.4
0.3
0.2
0.2
0.3
0.1
0.1
0.2
0.1
0.1
0.1
0.2
1.4
1.5
0.0
0.1
0.1
0.3
0.2
0.1
0.3
0.2
0.2
0.1
0.1
0.1
2.1
1.0
0.4
0.3
0.5
0.8
CO2
4.9
4.6
5.1
1.0
1.2
1.3
1.7
1.9
2.1
3.9
5.9
6.3
1.2
1.5
6.6
2.8
4.8
5.5
2.9
2.3
9.8
3.8
4.5
2.1
1.4
3.8
4.8
4.8
5.1
5.3
4.8
4.8
4.1
1.4
1.9
4.5
H2S
0.9
1.8
3.2
0.2
1.4
2.2
2.6
3.1
3.6
0.3
1.7
2.7
1.1
2.1
8.9
1.0
1.7
2.2
4.1
5.5
11.1
0.6
1.5
2.2
0.0
0.4
0.8
1.7
4.1
5.3
0.2
0.8
1.1
0.0
0.6
2.9
C1
27.4
29.6
6.1
3.5
14.5
17.2
9.6
9.2
8.9
34.3
25.1
24.0
4.3
4.6
24.9
21.9
22.6
22.4
33.4
31.8
25.8
21.0
21.5
34.0
19.5
22.2
27.4
25.5
27.7
24.9
29.4
22.8
15.9
13.8
13.7
12.8
C2
C3
10.7 4.4
10.3 6.6
4.7
7.4
2.9
6.7
8.1
8.1
8.4
7.8
9.6
9.3
8.9
8.8
8.3
8.3
13.8 8.5
10.4 7.7
10.2 7.0
6.7
9.7
6.4
9.2
10.2 7.2
2.0
1.5
2.1
1.6
1.6
1.1
11.1 6.8
12.8 8.3
9.3
7.1
11.3 9.3
11.3 8.5
11.7 6.8
10.5 10.0
9.5
8.5
10.7 8.2
11.8 8.3
11.4 7.8
10.6 7.6
6.9
5.8
9.1
7.9
8.3
7.6
9.2
8.9
9.3
9.2
6.1
8.9
i-C4
1.6
0.6
1.2
1.4
1.1
1.1
1.2
1.2
1.2
1.0
1.0
0.9
1.7
1.5
0.9
0.3
0.4
0.2
0.5
0.9
0.9
1.2
1.0
0.8
1.2
1.1
1.0
0.9
0.9
0.9
0.8
1.0
1.0
1.3
1.2
1.4
n-C4
3.7
4.3
5.1
5.4
4.9
4.6
4.9
4.7
4.6
4.0
3.8
3.5
6.1
5.7
3.5
1.3
1.4
0.8
3.9
3.8
3.5
5.2
4.1
3.7
5.1
4.5
3.9
3.8
3.7
3.8
3.5
4.1
4.3
4.8
4.9
4.9
i-C5
2.6
1.0
2.1
2.2
1.8
1.6
1.7
1.7
1.8
1.1
1.2
1.2
2.3
2.2
1.2
0.4
0.8
0.4
0.8
1.0
1.2
1.8
1.3
1.3
1.6
1.6
1.3
1.2
1.3
1.2
1.2
1.4
1.7
1.7
1.7
1.9
n-C5
1.8
3.0
3.5
3.9
3.2
3.1
3.0
3.1
3.1
2.1
2.2
2.1
3.6
3.6
2.1
0.9
1.3
0.9
2.5
2.0
2.0
3.4
2.5
2.2
2.8
2.8
2.3
2.3
2.4
2.3
2.2
2.6
3.4
3.1
3.0
3.0
C6
4.2
3.1
4.6
4.3
3.4
2.8
3.9
4.4
5.0
1.6
3.0
3.2
3.5
3.7
2.8
4.7
3.6
3.4
3.2
1.4
1.8
3.7
4.0
2.1
2.8
3.9
2.0
3.1
3.0
3.2
3.0
3.5
6.0
4.0
3.8
3.9
C7+ GOR
37.4 860
35.1 860
56.6 135
68.3
57
52.0 260
49.6
57
52.4 253
52.7 253
53.0 253
29.3 730
37.8 550
38.7 550
59.8 139
59.3 145
31.6 659
63.1 353
58.4 360
60.0 353
30.7 955
30.3 962
27.4 955
38.5 1100
39.5 565
33.0 1100
44.7 470
41.4 470
37.6 470
36.6 772
32.7 772
34.8 772
40.2 485
40.9 485
46.1 485
51.4 277
50.1 277
48.7 277
Page 27 of 32
Document Responsibility: Loss Prevention
Issue Date: 30 September, 2001
Next Planned Update: 1 June, 2006
SAES-B-062
Onshore Wellsite Safety
Table A8 – Oil Field Data from Exploration and Producing (Cont'd)
Components (mole %)
Well Name Reservoir Range
Khursaniyah
Arab-D
Min.
Khursaniyah
Wt. Avg.
Khursaniyah
Arab-B
Max.
Mazalij
Arab-D
Min.
Mazalij
Arab-D Wt. Avg.
Mazalij
Arab-D
Max.
Qatif
Fadhili
Min.
Qatif
Wt. Avg.
Qatif
Arab-D
Max.
Shedgum
Arab-D
Min.
Shedgum
Wt. Avg.
Shedgum
Arab-D
Max.
Uthmaniyah
Arab-D
Min.
Uthmaniyah
Arab-D Wt. Avg.
Uthmaniyah
Arab-D
Max.
N2
0.1
0.2
0.1
0.1
0.3
0.3
0.2
0.9
0.3
0.3
0.2
0.2
0.1
0.2
0.1
CO2
2.5
3.1
4.7
3.4
2.6
1.6
3.5
6.6
6.7
5.4
5.3
5.4
3.8
4.5
5.2
H2S
2.0
2.4
4.8
1.9
3.2
5.5
3.7
7.9
11.9
0.8
1.1
1.6
0.2
0.8
1.6
C1
C2
19.4 9.8
21.5 9.8
15.8 7.2
28.7 5.8
19.2 8.0
5.3
8.7
38.2 12.3
14.4 7.0
20.8 9.0
25.0 10.0
24.4 9.9
24.3 9.8
26.1 9.7
24.6 10.0
23.9 9.2
C3
8.6
8.5
6.9
6.4
7.5
8.3
7.4
7.2
7.1
7.7
7.8
7.6
7.7
8.1
7.7
i-C4
1.1
1.1
1.0
1.0
1.1
1.2
0.9
1.0
1.0
1.0
1.0
1.0
0.9
1.0
1.1
n-C4
4.5
4.2
3.8
3.7
4.3
5.0
3.6
4.1
3.6
3.9
4.0
3.9
4.2
4.1
4.4
i-C5
1.7
1.5
1.5
1.4
1.7
2.1
1.2
1.6
1.4
1.3
1.4
1.3
1.6
1.4
1.5
n-C5
3.1
2.6
2.7
2.2
2.7
3.4
2.2
2.7
2.2
2.4
2.4
2.4
3.0
2.5
2.7
C6
3.2
2.8
2.9
3.2
4.0
5.6
3.0
3.8
3.6
3.3
3.2
3.3
3.4
3.3
4.1
C7+ GOR
44.0 350
42.3 380
48.7 350
42.1 398
45.4 398
53.0 398
23.8 1266
43.0 330
32.5 870
38.9 540
36.2 540
39.3 540
39.4 515
39.3 515
38.7 515
Page 28 of 32
Document Responsibility: Loss Prevention
Issue Date: 30 September, 2001
Next Planned Update: 1 June, 2006
SAES-B-062
Onshore Wellsite Safety
Table A9 – Gas Field Data from Exploration and Producing
Well Name Reservoir
Mol Wt.
Range
Component (mole %)
N2
CO2
H2S
C1
C2
C3
i-C4
nC4
iC5
nC5
C6
C7
C8
C9
C10+
North Ghawar (Ain Dar and Shedgum)
ANDR-277
Khuff-B
23.1
Min.
14.7
3.8
0.7
70.4
4.9
1.8
0.4
0.6
0.2
0.2
0.2
0.3
0.4
0.3
1.1
SDGM-226
Khuff-C
23.7
Med. 11.8
3.7
3.6
69.4
5.1
2.0
0.5
0.8
0.3
0.3
0.4
0.4
0.4
0.3
1.1
SDGM-212
Khuff-C
24.6
Max.
11.5
3.9
6.0
66.6
5.0
2.1
0.5
0.8
0.4
0.3
0.5
0.6
0.6
0.4
1.0
Central Ghawar Area (Uthmaniyah)
UTMN-622
Khuff-B
25.5
Min.
10.5
1.7
2.3
68.4
6.7
3.0
0.6
1.2
0.5
0.5
0.7
0.8
0.8
0.6
1.8
UTMN-616
Khuff-C
24.9
Med. 11.5
3.3
5.2
66.0
5.8
2.5
0.5
1.0
0.4
0.4
0.6
0.6
0.6
0.5
1.3
UTMN-2000 Khuff-C
26.4
Max.
10.2
3.1
9.3
62.0
6.2
2.7
0.5
1.0
0.3
0.3
0.6
0.9
0.8
0.6
1.5
Avg.
9.6
2.2
2.5
68
6.7
2.9
0.5
1.1
0.4
0.4
0.7
1.0
1.0
0.7
2.2
South Ghawar Area (Hawiyah)
Khuff-C
27
Khuff-C
26.6
Min.
9.8
2.3
0.5
69.4
6.8
3.0
0.5
1.1
0.4
0.4
0.7
1.0
1.0
0.7
2.2
Khuff-C
27.1
Med.
9.6
2.2
3.0
67.7
6.6
2.9
0.5
1.0
0.4
0.4
0.7
1.0
1.0
0.7
2.2
Khuff-C
27.2
Max.
9.4
2.2
4.5
66.6
6.5
2.8
0.5
1.1
0.4
0.4
0.7
1.0
1.0
0.7
2.1
Avg.
9.0
1.5
0.6
71.1
7.4
3.3
0.6
1.4
0.5
0.5
0.6
0.8
0.8
0.6
1.2
South Ghawar Area (Haradh)
Khuff-C
25
Khuff-C
25
Min.
9.0
1.5
0.5
71.2
7.4
3.3
0.6
1.4
0.5
0.5
0.6
0.8
0.8
0.6
1.2
Khuff-C
25
Med.
9
1.5
1.0
70.9
7.4
3.3
0.6
1.4
0.5
0.5
0.6
0.8
0.8
0.6
1.2
Khuff-C
25
Max.
9
1.5
2.0
70.1
7.3
3.3
0.6
1.4
0.5
0.5
0.6
0.8
0.8
0.6
1.2
Qatif
QTIF-51
Khuff-A
20.9
Min.
6.5
9.1
7.2
75.8
1.2
0.2
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
QTIF-152
Khuff-B
24.7
Max.
42.2
2.0
11.2
42.2
0.9
0.2
0.0
0.2
0.0
0.0
0.1
0.8
0.0
0.0
0.0
Abqaiq
Abq Cap
Gas
Berri
Abqaiq
0.7
8.6
2.3
64.5 14.1
6.1
2.2
0.9
0.3
0.1
0.1
0.1
0.0
0.0
0.0
Berri Khuff
Berri
10.0
8.2
19.8
61.4
0.2
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
23.2
0.3
Page 29 of 32
Document Responsibility: Loss Prevention
Issue Date: 30 September, 2001
Next Planned Update: 1 June, 2006
SAES-B-062
Onshore Wellsite Safety
The table below shows examples of the maximum RERs for some fields. The RER values
shown are based on the calculation information above and the maximum open flow and highest
sour gas concentration typically expected the fields listed. The values below are for example
only.
RER100ppm
(meters)
RER30ppm
(meters)
RER½LFL
(meters)
Abqaiq Gas Cap
1170
3170
170
North Ghawar (Ain Dar and Shedgum)
1420
4090
160
South Ghawar (Haradh)
460
1210
160
South Ghawar (Hawiyah)
1110
3050
180
Uthmaniyah
2740
7110
170
RER100ppm
(meters)
RER30ppm
(meters)
RER½LFL
(meters)
Abqaiq
1780
4140
620
Abu Jiffan
1270
2660
220
Ain Dar
850
2130
160
Dammam
460
770
100
Fazran
280
960
100
Haradh
910
2250
210
Harmaliyah
1340
3060
190
Hawiyah
490
1130
220
Khurais
950
2010
200
Khursaniyah
1340
2890
200
Mazalij
1880
3820
300
Shedgum
530
1270
170
Uthmaniyah
700
1590
240
Gas Fields
Oil Fields
Page 30 of 32
Document Responsibility: Loss Prevention
Issue Date: 30 September, 2001
Next Planned Update: 1 June, 2006
SAES-B-062
Onshore Wellsite Safety
Gas Field RER Work Sheet
Value
Information
Well Name
Field
Absolute Open Flow, Qgas MMSCFD
Mole % of H2S in Gas, [xH2S]gas
DATA from Table A6
Minimum AOF, MMSCFD, per Table A6
Maximum AOF, MMSCFD, per Table A6
Is AOF for well greater than minimum
and less than maximum AOF for field?
Minimum mole percent (%) of H2S per Table A6
Maximum mole percent (%) of H2S per Table A6
Is H2S mole % for well greater than minimum
and less than maximum flow rate for field?
( ) Yes (continue)
( ) No (stop: Contact LPD/TSU)
( ) Yes (continue)
( ) No (stop: Contact LPD/TSU)
Constants from Table A6
e
f
g
h
l
m
Calculate H2S Release Rate
QH2S = (QAOF)(xH2S) [MMscfd of H2S]
Calculate RERs
RER100 ppm = e(QH2S)f :
RER30 ppm = g(QH2S)h
RER½ LFL = l(QAOF)m
Results
RER100 ppm
RER30 ppm
RER½ LFL
Page 31 of 32
Document Responsibility: Loss Prevention
Issue Date: 30 September, 2001
Next Planned Update: 1 June, 2006
SAES-B-062
Onshore Wellsite Safety
Oil Field RER Work Sheet
Value
Information
Well Name
Field
Maximum Flow Rate, Qoil Mbpd
GOR, scf/stb
Mole % of H2S in Oil, [xH2S]oil
DATA from Table A7
Minimum Flow Rate, Mbpd, per Table A7 or Qoil
Maximum Flow Rate, Mbpd, per Table A7 or Qoil
Is flow rate for well greater than minimum
and less than maximum flow rate for field?
Minimum mole percent (%) of H2S per Table A7
( ) Yes (continue)
( ) No (stop: Contact LPD/TSU)
Maximum mole percent (%) of H2S per Table A7
Is H2S mole % for well greater than minimum
and less than maximum flow rate for field?
( ) Yes (continue)
( ) No (stop: Contact LPD/TSU)
Constants from Table A7
a
e
g
l
Calculate flashed gas release rate
b
f
h
m
Qgas = (Qoil)(GOR)/1,000 [MMscfd]
Calculate the H2S concentration in flashed gas
φ = a(GOR)b
[xH2S]gas = φ [xH2S]oil
QH2S = (([xH2S]gas)/100)Qgas [MMscfd of H2S]
Calculate RERs
RER100 ppm = e(QH2S)f
RER30 ppm = g(QH2S)h
RER½ LFL = l(Qgas)m
Results
RER100 ppm
RER30 ppm
RER½ LFL
Page 32 of 32
Saudi Aramco 7180 (5/89)
G.I. NUMBER
1852.001
SAUDI ARABIAN OIL COMPANY (Saudi Aramco)
GENERAL INSTRUCTION MANUAL
ISSUE DATE
ISSUING ORG.
DRILLING & WORKOVER
SUBJECT:
RIG SITE FLARE GUN AND COMMUNICATION EQUIPMENT
REPLACES
03/10/1999
APPROVAL
FAM
Approved
NEW
PAGE NUMBER
1
OF
2
CONTENT:
This General Instruction contains policy for equipping a rig with a Flare Gun and standard Communication
Equipment.
1. OBJECTIVE
2. BACKGROUND
3. FLARE GUN
4. COMMUNICATION EQUIPMENT
1.0
OBJECTIVE
The purpose of this policy is to ensure that every rig is fully equipped with a Flare Gun and
Communication Equipment in case of an uncontrolled surface well flow (blowout) or other
emergency.
2.0
3.0
BACKGROUND
2.1
During Drilling and Workover operations, with a rig on the well, an uncontrolled surface flow
(blowout) may occur, requiring immediate ignition of the well effluent to protect human life and
company assets. In such a case, a Flare Gun is fired to ignite the effluent before spreading.
2.2
During the blowout emergency, it becomes imperative to have reliable means of communication
at the rig site and with headquarters, especially when all power is turned off at the well site to
avoid uncontrolled ignition. The use of mobile car radios and portable communication devices
(such as Walkie-Talkies) become essential in effective transmittal of instructions and expedient
control of the well.
FLARE GUN
Drilling & Workover will have a Flare Gun on each rig site, as well as a box of at least 24 cartridges
with long shelf life. The Flare Gun and cartridges will be locked up in a clearly marked wooden box in
the Foreman's office, and the location of the key will be known only to the Foreman and the rig
Contract Supervisor. The Foreman and Contract Supervisor should be proficient in operation of the
Flare Gun.
* CHANGE
** ADDITION
NEW INSTRUCTION X
COMPLETE REVISION
2
Saudi Aramco 7180 (5/89)
G.I. NUMBER
1852.001
SAUDI ARABIAN OIL COMPANY (Saudi Aramco)
GENERAL INSTRUCTION MANUAL
ISSUE DATE
ISSUING ORG.
DRILLING & WORKOVER
SUBJECT:
RIG SITE FLARE GUN AND COMMUNICATION EQUIPMENT
FAM
4.0
REPLACES
03/10/1999
APPROVAL
Approved
NEW
PAGE NUMBER
2
OF
2
COMMUNICATION EQUIPMENT
4.1
Mobile Radio
Drilling & Workover and Computer & Communications Services Department will work
together to forecast, acquire and install a single side-band mobile radio in every rig Foreman's
vehicle to provide the capability to communicate with the Superintendent in case of an
emergency. The radio will only be used when at a safe distance from the well site in case of
unignited hydrocarbon accumulation since the vehicle and radio are both sources of ignition.
4.2
Walkie-Talkie
Drilling & Workover and Computer & Communications Services Department will work
together to forecast and acquire at least two portable communication devices, such as WalkieTalkies. The devices are needed on every rig site during an emergency or critical operation. The
portable communication devices will be locked up in a clearly marked wooden box in the
Foreman’s office, and the location of the key will be known only to the Foreman and the Rig
Contract Supervisor. The Foreman is responsible for the proper operation and charging of the
devices. The Walkie-Talkies must be rated for use in Class I, Div. I electrically classified areas
(i.e. explosion proof).
Approved by:
F. A. Al-Moosa
General Manager, Drilling and Workover.
N. H. Al-Rabeh
Manager, Computer and Communications Services Department.
* CHANGE
** ADDITION
NEW INSTRUCTION X
COMPLETE REVISION
2
Saudi Aramco 7180 (5/89)
G.I. NUMBER
1853.001
SAUDI ARABIAN OIL COMPANY (Saudi Aramco)
GENERAL INSTRUCTION MANUAL
ISSUE DATE
ISSUING ORG.
DRILLING & WORKOVER
SUBJECT:
ISOLATION BARRIERS FOR WELLS DURING DRILLING
& WORKOVER OPERATIONS (WITH AND WITHOUT RIG)
REPLACES
02/14/1999
APPROVAL
MYR
Approved
NEW
PAGE NUMBER
1
OF
5
CONTENT:
This document contains instructions for providing adequate isolation barriers (or shut-offs) when removing
surface control equipment while drilling or working over wells. These instructions are also applicable for well
repair work, performed by the Drilling & Workover organization without a rig on location.
1. OBJECTIVE
2. BACKGROUND
3. MINIMUM REQUIREMENT
4. TYPES OF ISOLATION BARRIERS
5. RELIABILITY OF ISOLATION BARRIER
6. WAIVER
1.0
OBJECTIVE:
The purpose of this GI is to ensure safe operations during drilling and well repair work by strict
compliance to the guidelines. Short cuts to compromise these guidelines will not be permitted unless a
waiver is obtained from the Vice President of Petroleum Engineering & Development or designated
representatives.
2.0
BACKGROUND:
When drilling or working over wells, with or without a rig, situations arise where surface equipment
such as Blow Out Preventers (BOPs), wellheads, master valves and trees have to be removed for
various reasons. In these situations, surface well control is temporarily removed and is substituted
with downhole isolation barriers so that the reservoir pressure is isolated and work can continue
around the wellhead safely. More than one isolation barrier or shut-off is normally required in certain
wells in case of unexpected failure of the primary barrier. Adequate back-up barriers reduce the
chances of uncontrolled surface flow (blowout) and costly repair work.
3.0
MINIMUM REQUIREMENT:
The following guidelines will apply at all times unless a waiver has been obtained from Management
(as described in paragraph 6.2). The mandatory number of barriers or shut-offs in each case is the
minimum; any additional barriers are optional, dictated by the well condition and downhole
completion equipment.
3.1
Oil Wells (GOR less than 850 scf/bbl)
2 shut-offs, one of which is mechanical.
* CHANGE
** ADDITION
NEW INSTRUCTION X
COMPLETE REVISION
5
Saudi Aramco 7180 (5/89)
G.I. NUMBER
1853.001
SAUDI ARABIAN OIL COMPANY (Saudi Aramco)
GENERAL INSTRUCTION MANUAL
ISSUE DATE
ISSUING ORG.
DRILLING & WORKOVER
SUBJECT:
ISOLATION BARRIERS FOR WELLS DURING DRILLING
& WORKOVER OPERATIONS (WITH AND WITHOUT RIG)
3.2
REPLACES
02/14/1999
APPROVAL
MYR
Approved
NEW
PAGE NUMBER
2
OF
5
Oil Wells (GOR more than 850 scf/bbl)
3 shut-offs, two of which are mechanical.
Note:
3.3
For tubing and packer completed wells, the 3 shut-off guideline is applicable to the
tubing only. A minimum of 2 shut-offs is required for the tubing-casing annulus
(tubing hanger and packer seals). If one of the two shut-offs is deemed to be
ineffective or questionable, then the annulus will have to be filled with overbalanced
kill fluid to act as a reliable shut-off.
Water Injection Wells
- If positive WH pressure, 2 shut-offs are required, one of which is mechanical.
- If no WH pressure, 1 shut-off is required.
Note:
3.4
It is acceptable to nipple up or nipple down the BOPs on top of the injection tree by
only closing the 10" ball valve. No additional shut-offs are required as long as the tree
was never removed or the tree has been pressure tested after nippling up.
Gas Wells
3 shut-offs, two of which are mechanical.
Note:
3.5
For tubing and packer completed wells, the 3 shut-off guideline is applicable to the
tubing only. A minimum of 2 shut-offs is required for the tubing-casing annulus
(tubing hanger and packer seals). If one of the two shut-offs is deemed to be
ineffective or questionable, then the annulus will have to be filled with overbalanced
kill fluid to act as a reliable shut-off.
Water Supply Wells (with or without submersible pump)
- If well flows to surface, 1 shut-off is required.
- If well does not flow to surface, no shut-off is required.
4.0
TYPES OF ISOLATION BARRIERS:
4.1
* CHANGE
A number of acceptable isolation barriers or shut-off alternatives are available and can be used
under different operating conditions. These barriers can be separated into two main groups:
Mechanical and Non-Mechanical.
** ADDITION
NEW INSTRUCTION X
COMPLETE REVISION
5
Saudi Aramco 7180 (5/89)
G.I. NUMBER
1853.001
SAUDI ARABIAN OIL COMPANY (Saudi Aramco)
GENERAL INSTRUCTION MANUAL
ISSUE DATE
ISSUING ORG.
DRILLING & WORKOVER
SUBJECT:
ISOLATION BARRIERS FOR WELLS DURING DRILLING
& WORKOVER OPERATIONS (WITH AND WITHOUT RIG)
4.2
REPLACES
02/14/1999
APPROVAL
MYR
Approved
NEW
PAGE NUMBER
3
OF
5
The following are examples of Mechanical and Non-Mechanical isolation barriers. The type of
barrier to utilize will depend on the well condition and downhole completion equipment. These
barriers include, but are not limited to:
Mechanical:
- Drillable or Retrievable Bridge Plug
- Retrievable Tubing Plug
- Back Pressure Valve
- Valve Back-Seat
- Surface Valve
- Subsurface Safety Valve (SSSV)
- Unperforated Casing
Non-Mechanical:
- Kill Fluid
- Cement
5.0
RELIABILITY OF ISOLATION BARRIERS:
5.1
5.2
Equipment Testing
5.1.1
Vendor Testing: Prior to delivery of a new mechanical pressure isolation device, the
vendor must conduct the required and appropriate hydrostatic pressure tests per Saudi
Aramco Materials System Specification (SAMSS) to insure that the device meets design
specifications.
5.1.2
Field-Testing: Whenever a mechanical isolation barrier is installed in a well, every effort
should be made to field test and insure the barrier is holding. Since plugs are designed
to hold pressure from above, below or from both directions, the field test should be
designed according to the plug functionality.
Kill Fluid
5.2.1
* CHANGE
A kill fluid can be used as one of the isolation barriers as mentioned in section 4.2 above.
In order for the kill fluid to be effective as an isolation barrier, two conditions must be
met:
a)
The hydrostatic pressure of the kill fluid column must exceed the reservoir
pressure.
b)
The wellbore kill fluid must remain static at surface for a period of time ( as per
item 5.2.2 below) to insure the presence of a competent barrier.
** ADDITION
NEW INSTRUCTION X
COMPLETE REVISION
5
Saudi Aramco 7180 (5/89)
G.I. NUMBER
1853.001
SAUDI ARABIAN OIL COMPANY (Saudi Aramco)
GENERAL INSTRUCTION MANUAL
ISSUE DATE
ISSUING ORG.
DRILLING & WORKOVER
SUBJECT:
ISOLATION BARRIERS FOR WELLS DURING DRILLING
& WORKOVER OPERATIONS (WITH AND WITHOUT RIG)
5.2.2
MYR
NEW
PAGE NUMBER
4
OF
1 hour
2 hour
3 hours
1 hour
30 minutes
WAIVER:
6.1
The above instructions will be mandatory when drilling or working over a well (with or without
a rig) by the Drilling & Workover organizations, unless prior management approval has been
secured. A written waiver to divert from the established guidelines must be obtained when an
unusual well situation dictates the need for fewer barriers than stipulated. Obtaining a waiver to
reduce the number of isolation barriers or shut-offs is highly discouraged and should only be
considered when there are no other alternatives.
6.2
The waiver will be requested by submitting Waiver Request Form Waiver - 01 (see Appendix I)
documenting the well situation, explaining why a waiver is necessary and explaining the impact
of the waiver. Waiver signature approval level will be Vice President of Petroleum Engineering
& Development or designated representaive.
Recommende by:
F. A. Al-Moosa
General Manager, Drilling and Workover
Approved by:
M. Y. Rafie
Vice President, Petroleum Engineering & Development
* CHANGE
5
The following are the minimum mandatory observation times for a kill fluid to be
declared static:
Oil Well (GOR less than 850 scf/bbl):
Oil Well (GOR more than 850 scf/bbl):
Gas Well
Water Injector
Water Supply Well
6.0
REPLACES
02/14/1999
APPROVAL
Approved
** ADDITION
NEW INSTRUCTION X
COMPLETE REVISION
5
Appendix I
GI 1853.001
Page 5 of 5
WAIVER REQUEST FOR ISOLATION BARRIER
Date Requested
Waiver Request #
Saudi Aramco Form: Waiver 01(10/98)
Well Name & Number
Plant #
Facility Connected to
Include number, paragraph, and issue date of this affected GI
Waiver requested
Y
N
After-the-Fact
Justification (Include discussion of impact assessment)
Impact Assessment
W A I V E R
O R G I N A T O R
Y
N
Financial Impact
Safety Impact
Discuss under Justification
Alternatives to waiving requirements
Originating Organization
(Originator's Name)
(Signature)
Date
Phone:
Originator's Supervisor
(Signature)
Date
Phone
A P P R O V A L
REMARKS
Vice President or Designated Representative
Name
Signature
Date
SAUDI ARAMCO
DRILLING & WORKOVER
ROOM 221A, BLDG 3193
DHAHRAN 31311, SAUDI ARABIA
TEL. 862-8000, FAX. 862-8011
October 18, 1999
D&WO/GM-160
Clarification of GI 1853.001
Managers
Drilling & Workover
The new GI 1853.001 entitled “Isolation Barriers for Wells during Drilling & Workover
Operations (with and without Rig)” was approved in November 1998 and distributed for
implementation. The interpretation of the GI with respect to changing rams or installing casing
rams has been questioned. The following clarifies the shut-off requirements for these
operations as per the subject GI.
Section 3.0,
Paragraphs 3.2 (Oil Wells with GOR more than 850 scf/bbl) and 3.4 (Gas Wells)
Three mandatory shut-offs are required; two of which should be mechanical.
Clarification:
i)
For BOP stack removal or tree removal, the mandatory shut-off requirements are
applicable.
ii)
For changing rams or installing casing rams, the mandatory shut-offs do not apply.
Two barriers are adequate; one of which should be mechanical. Shutting the blind
rams with kill fluid in the hole will provide proper isolation since the 1) BOP
preventers below the open ram cavity are effective and reliable (recently pressure
tested), 2) time involved in changing rams is much less than removing the entire
BOP stack or tree. When changing the lowermost set of rams, a down-hole
mechanical shut-off (either cased hole or packer) with kill fluid is required.
Signed 10/18/99
__________________________________
F. A. Al-Moosa, General Manager
Drilling & Workover
dgn/
cc: Drilling Superintendents, Deep Drilling and Onshore Workover Dept.
Drilling Superintendents, Dev. Drilling and Offshore Workover Dept.
General Supervisors, Drilling and W/O Engrg. Dept.
Originator
Letterbook