Well-Control-Manual

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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 ( H2S) 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 
WELL CONTROL MANUAL 
 
 Drilling & Workover October 2002 
 __ 
 
 
INTRODUCTION AND RESPONSIBILITIES 
 
 
 
 
 
 
Current Edition: October 2002 1 3rd Edition 
Previous Revision: October 1998 
 
 
 
Table of Contents 
 
 
Introduction.......................................................................................................... 2 
1.0 Responsibilities of Drilling Staff ........................................................ 3 
1.1 Well Planning................................................................................... 3 
1.2 Drilling Program............................................................................... 3 
1.3 Geological Information..................................................................... 3 
1.4 Area Drilling Experience .................................................................. 4 
1.5 Casing Design and Depths of Setting .............................................. 4 
1.6 Equipment Selection........................................................................ 4 
1.7 Hiring Contract Rigs. ........................................................................ 4 
1.8 Specification of Rig Equipment ....................................................... 4 
1.9 Contract Responsibilities................................................................. 4 
1.10 Training of Company and Contract Personnel ................................. 5 
1.11 BOP Equipment ............................................................................... 5 
1.12 BOP Testing ..................................................................................... 5 
1.13 Well Control ..................................................................................... 5 
1.14 Pre-recorded Data Sheet ................................................................. 5 
1.15 Slow Pump Rate Data....................................................................... 5 
1.16 Blowout Prevention Training ........................................................... 6 
1.17 Information to be Posted.................................................................. 6 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
WELL CONTROL MANUAL 
 
 Drilling & Workover October 2002 
 __ 
 
 
INTRODUCTION AND RESPONSIBILITIES 
 
 
 
 
 
 
Current Edition: October 2002 2 3rd Edition 
Previous Revision: October 1998 
 
 
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. 
 
Changes in this 3rd Edition of the Saudi Aramco Well Control Manual are indicated by a bold 
vertical line in the right margin, opposite the revision. 
WELL CONTROL MANUAL 
 
 Drilling & Workover October 2002 
 __ 
 
 
INTRODUCTION AND RESPONSIBILITIES 
 
 
 
 
 
 
Current Edition: October 2002 3 3rd Edition 
Previous Revision: October 1998 
 
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. 
 
 
WELL CONTROL MANUAL 
 
 Drilling & Workover October 2002 
 __ 
 
 
INTRODUCTION AND RESPONSIBILITIESCurrent Edition: October 2002 4 3rd Edition 
Previous Revision: October 1998 
 
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. 
 
 
 
 
 
 
 
 
WELL CONTROL MANUAL 
 
 Drilling & Workover October 2002 
 __ 
 
 
INTRODUCTION AND RESPONSIBILITIES 
 
 
 
 
 
 
Current Edition: October 2002 5 3rd Edition 
Previous Revision: October 1998 
 
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: 
 
· Tourly 
· After a mud weight change 
· After a bit nozzle or BHA change (after breaking circulation gels) 
· After each 500 ft depth interval 
WELL CONTROL MANUAL 
 
 Drilling & Workover October 2002 
 __ 
 
 
INTRODUCTION AND RESPONSIBILITIES 
 
 
 
 
 
 
Current Edition: October 2002 6 3rd Edition 
Previous Revision: October 1998 
 
· 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: 
 
· 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 
 
 
 
WELL CONTROL MANUAL 
 
 Drilling & Workover October 2002 
 __ 
 
 
SECTION A – BASIC CALCULATIONS AND TERMINOLOGY 
 
 
 
 
 
 
Current Edition: October 2002 A - 1 3rd Edition 
Previous Revision: October 1998 
 
 
 
 
 
Table of Contents 
 
1.0 Understanding Pressures................................................................. A-2 
1.1 Hydrostatic Pressure .................................................................... A-2 
1.2 Pressure Gradient......................................................................... A-2 
1.3 Formation Pressure ...................................................................... A-3 
1.4 Surface Pressure .......................................................................... A-3 
1.5 Bottomhole Pressure .................................................................... A-4 
1.6 Equivalent Circulating Density...................................................... A-4 
1.7 Differential Pressure ..................................................................... A-5 
1.8 Choke Pressure ............................................................................ A-5 
1.9 Swab and Surge Pressures........................................................... A-5 
1.10 Fracture Pressure ......................................................................... A-6 
2.0 Relationship of Pressure to Volume .............................................. A-7 
2.1 Liquids .......................................................................................... A-7 
2.2 Gases............................................................................................ A-7 
3.0 Relationship of Pump Pressure to Mud Weight .......................... A-8 
4.0 Relationship of Pump Pressure to Circulating Rate.................. A-8 
5.0 Capacity Factors and Displacement.............................................. A-9 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
WELL CONTROL MANUAL 
 
 Drilling & Workover October 2002 
 __ 
 
 
SECTION A – BASIC CALCULATIONS AND TERMINOLOGY 
 
 
 
 
 
 
Current Edition: October 2002 A - 2 3rd Edition 
Previous Revision: October 1998 
 
 
 
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 
 where: 
 HP = Hydrostatic Pressure (psi) 
 MW = Mud Weight (pcf) 
 TVD = True Vertical Depth (ft) 
 
 
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 
 where: 
 PG = Pressure Gradient (psi/ft) 
MW = Mud Weight (pcf) 
 
 
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. 
 
 
 
WELL CONTROL MANUAL 
 
 Drilling & Workover October 2002 
 __ 
 
 
SECTION A – BASIC CALCULATIONS AND TERMINOLOGY 
 
 
 
 
 
 
Current Edition: October 2002 A - 3 3rd Edition 
Previous Revision: October 1998 
 
 
 
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. 
 
 
 
WELL CONTROL MANUAL 
 
 Drilling & Workover October 2002 
 __ 
 
 
SECTION A – BASIC CALCULATIONS AND TERMINOLOGY 
 
 
 
 
 
 
Current Edition: October 2002 A - 4 3rd Edition 
Previous Revision: October 1998 
 
 
 
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 Bottomhole Pressure 
 
 BHP = HP + SP + FP 
 
 where: BHP = Bottomhole Pressure (psi) 
 HP = Hydrostatic Pressure (psi) 
 SP = Surface Pressure (psi) 
 FP = 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. 
 
 
 
 
 
 
 
 
WELL CONTROL MANUAL 
 
 Drilling & Workover October 2002 
 __ 
 
 
SECTION A – BASIC CALCULATIONS AND TERMINOLOGY 
 
 
 
 
 
 
Current Edition: October 2002 A - 5 3rd Edition 
Previous Revision: October 1998 
 
 
 
 
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 
 
 
Anaccurate 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 shut-
in 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. 
 
 
WELL CONTROL MANUAL 
 
 Drilling & Workover October 2002 
 __ 
 
 
SECTION A – BASIC CALCULATIONS AND TERMINOLOGY 
 
 
 
 
 
 
Current Edition: October 2002 A - 6 3rd Edition 
Previous Revision: October 1998 
 
 
 
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. 
WELL CONTROL MANUAL 
 
 Drilling & Workover October 2002 
 __ 
 
 
SECTION A – BASIC CALCULATIONS AND TERMINOLOGY 
 
 
 
 
 
 
Current Edition: October 2002 A - 7 3rd Edition 
Previous Revision: October 1998 
 
 
 
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 Boyle’s Law 
 
 P1 x V1 = P2 x V2 
 
 where: P1 = Pressure of gas at depth 1 
 V1 = Volume of gas at depth 1 
 P2 = Pressure of gas at depth 2 
 V2 = Volume of gas at depth 2 
 
 
 
WELL CONTROL MANUAL 
 
 Drilling & Workover October 2002 
 __ 
 
 
SECTION A – BASIC CALCULATIONS AND TERMINOLOGY 
 
 
 
 
 
 
Current Edition: October 2002 A - 8 3rd Edition 
Previous Revision: October 1998 
 
 
 
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: 
 
 
 Equation A.7 New Pump Pressure = Old Pump Pressure x ( New Circ. Rate/Old Circ. Rate )2 
 
 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? 
 
New Pump Pressure = 2800 x (60/80)2 = 1575 psi 
 
 
WELL CONTROL MANUAL 
 
 Drilling & Workover October 2002 
 __ 
 
 
SECTION A – BASIC CALCULATIONS AND TERMINOLOGYCurrent Edition: October 2002 A - 9 3rd Edition 
Previous Revision: October 1998 
 
 
 
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 = Capacity Factor (bbl/ft) 
 ID = Internal pipe diameter (inches) 
 
 
 
Equation A.9 Annular Capacity Factor 
 
 OD2 - ID2 
CF = 
 1029 
 
 where: CF = Capacity Factor (bbl/ft) 
OD = Inside diameter of larger pipe (inches) 
ID = 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. 
 
 
 
 
WELL CONTROL MANUAL 
 
 Drilling & Workover October 2002 
 __ 
 
 
SECTION A – BASIC CALCULATIONS AND TERMINOLOGY 
 
 
 
 
 
 
Current Edition: October 2002 A - 10 3rd Edition 
Previous Revision: October 1998 
 
 
 
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. 
 
WELL CONTROL MANUAL 
 
 Drilling & Workover October 2002 
 __ 
 
 
SECTION B – CAUSES AND DETECTION OF KICKS 
 
 
 
 
 
 
Current Revision: October 2002 B - 1 3rd Edition 
Previous Revision: October 1998 
 
 
 
 
Table of Contents 
 
 
1.0 Causes of Kicks................................................................................... B-2 
1.1 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 
2.0 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 
 
 
 
 
 
 
Current Revision: October 2002 B - 2 3rd Edition 
Previous Revision: October 1998 
 
 
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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SECTION B – CAUSES AND DETECTION OF KICKS 
 
 
 
 
 
 
Current Revision: October 2002 B - 3 3rd Edition 
Previous Revision: October 1998 
 
Table B.1 Effect of Gas-Cut Mud on Bottomhole Hydrostatic Pressure 
 
Pressure Reduction (psi) 
 
 75 PCF Cut to 135 PCF Cut to 135 PCF Cut to 
Depth (ft) 37 PCF 121 PCF 67 PCF 
1000 51 31 60 
5000 72 41 82 
10000 86 48 95 
20000 97 51 105 
 
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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SECTION B – CAUSES AND DETECTION OF KICKS 
 
 
 
 
 
 
Current Revision: October 2002 B - 4 3rd Edition 
Previous Revision: October 1998 
 
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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SECTION B – CAUSES AND DETECTION OF KICKS 
 
 
 
 
 
 
Current Revision: October 2002 B - 5 3rd Edition 
Previous Revision: October 1998 
 
 
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 anabnormal pressure zone of this nature. 
 
 
 Figure B.2 Abnormal Pressure Due 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 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Figure B.2 Abnormal Pressure Due To Faulting 
 
 
 
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SECTION B – CAUSES AND DETECTION OF KICKS 
 
 
 
 
 
 
Current Revision: October 2002 B - 6 3rd Edition 
Previous Revision: October 1998 
 
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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SECTION B – CAUSES AND DETECTION OF KICKS 
 
 
 
 
 
 
Current Revision: October 2002 B - 7 3rd Edition 
Previous Revision: October 1998 
 
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 balled-
up. 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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SECTION B – CAUSES AND DETECTION OF KICKS 
 
 
 
 
 
 
Current Revision: October 2002 B - 8 3rd Edition 
Previous Revision: October 1998 
 
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 tothe 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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SECTION B – CAUSES AND DETECTION OF KICKS 
 
 
 
 
 
 
Current Revision: October 2002 B - 9 3rd Edition 
Previous Revision: October 1998 
 
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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SECTION B – CAUSES AND DETECTION OF KICKS 
 
 
 
 
 
 
Current Revision: October 2002 B - 10 3rd Edition 
Previous Revision: October 1998 
 
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 mud-
cap 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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SECTION B – CAUSES AND DETECTION OF KICKS 
 
 
 
 
 
 
CurrentRevision: October 2002 B - 11 3rd Edition 
Previous Revision: October 1998 
 
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 mud-
cap 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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SECTION B – CAUSES AND DETECTION OF KICKS 
 
 
 
 
 
 
Current Revision: October 2002 B - 12 3rd Edition 
Previous Revision: October 1998 
 
 
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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SECTION B – CAUSES AND DETECTION OF KICKS 
 
 
 
 
 
 
Current Revision: October 2002 B - 13 3rd Edition 
Previous Revision: October 1998 
 
 
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 
 
 
 Positive Indicators of a Kick 
 
 ® Increase in Pit Volume 
 ® Increase in Flow Rate 
 
 
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. 
 
2.2 Secondary Indicators of a Kick 
 
 
 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 
 
 
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). 
 
2.3 Indicators of Abnormal Pressure 
 
 
Indicators of Abnormal Pressure 
 
 ® 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 
 
 
 
“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. 
 
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Current Revision: October 2002 B - 14 3rd Edition 
Previous Revision: October 1998 
 
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 incompressibilityof 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. 
 
WELL CONTROL MANUAL 
 
 Drilling & Workover October 2002 
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SECTION B – CAUSES AND DETECTION OF KICKS 
 
 
 
 
 
 
Current Revision: October 2002 B - 15 3rd Edition 
Previous Revision: October 1998 
 
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 
 
 
 Log ( )60NR 
 dexp = 
 Log ( ) 1000 12W 
 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 
 
 
db 
WELL CONTROL MANUAL 
 
 Drilling & Workover October 2002 
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SECTION B – CAUSES AND DETECTION OF KICKS 
 
 
 
 
 
 
Current Revision: October 2002 B - 16 3rd Edition 
Previous Revision: October 1998 
 
 
 
 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 
 
WELL CONTROL MANUAL 
 
 Drilling & Workover October 2002 
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SECTION B – CAUSES AND DETECTION OF KICKS 
 
 
 
 
 
 
Current Revision: October 2002 B - 17 3rd Edition 
Previous Revision: October 1998 
 
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,