Well Control and Blowout Prevention

WELL CONTROL AND BLOWOUT PREVENTION

SECTION A: INTRODUCTION AND RESPONSIBILITIES

1. INTRODUCTION

The single most important step in blowout prevention is closing the blowout preventers when the well

kicks. The decision to do so ranks as high as 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 studies and previous experience have enabled the

industry to develop simple and easily understood procedures for detecting and controlling kicks. It

is crucial that supervisory personnel have a thorough understanding of these procedures as they

apply to Chevron operated drilling rigs.

There are many reasons for promoting proper well control and blowout prevention. 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 and/or loss of reservoir pressures; damage to the environment through pollution;

and adverse publicity or negative governmental reaction, especially near populated areas.

NOTE:

While definite procedures are outlined herein, it should be understood that this

manual is meant to be a guide for company drilling personnel, and is not an

infallible rule book. It should not override sound and mature judgement based

upon knowledge of well control principles and individual circumstances.

Experience has shown that wells are drilled most efficiently with lower costs and fewer hazards when

bottomhole pressures are maintained only slightly above formation pressures. Therefore, it's

imperative that supervisors using this method understand it thoroughly and follow good well control

procedures as described herein.

This is a training manual designed for Company and contract personnel, as a reference for Company

supervisors, and as a general information guide about blowout prevention.

2. RESPONSIBILITIES OF THE OFFICE DRILLING STAFF

Most drilling offices include a drilling staff comprised of a Drilling Manager, Engineering Advisor,

Drilling Superintendents, and Drilling Engineers.

Well Planning: Planning for maximum efficiency and safe operations is primarily the office drilling

staff's responsibility. With concurrence of the Drilling Manager, they must use their knowledge and

good judgment to make the best possible well plan for a particular area.

A-1

Rev12/94

CHEVRON DRILLING REFERENCE SERIES

VOLUME ELEVEN


Drilling Program: This program should include the casing and mud program, special equipment that

will be required for specific well problems, and any other information pertinent to the safe and efficient

drilling of a particular well. The drilling program is usually written by the Drilling Engineer and

approved by the Drilling Superintendent and/or Drilling Manager.

A directional program is also required to avoid existing holes 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 the precise surface and subsurface locations of the well.

In directionally drilled wells, the well course should be carefully planned and horizontal and vertical

sections should be maintained continuously during drilling to ensure that the well course is accurate.

Deviations should be corrected early to avoid excessive doglegs.

Multishot readings are often made prior to setting surface casing so that its position is accurately

known. Effort must be made to know the well position and course accurately from the surface to the

total depth. The degree of effort required varies with the drilling operation.

Geological Information: The Drilling Engineer needs all available geological information for the

area to prepare a good drilling program. Good communication with the geologists is necessary to

determine possible drilling problems and prepare methods of handling them.

Area Drilling Experience:

Each area has characteristic drilling problems that experienced

personnel can handle efficiently and safely. The Drilling Superintendent and Manager should be

primarily responsible for guaranteeing that such assignments are filled with qualified Drilling

Representatives.

Casing Design and Depths of Setting: Compliance with proper casing design and setting depths

calculated from expected formation pressures and fracture gradients is vital, particularly in high-

pressure areas. In some areas, governmental regulations on casing design must be considered in

addition to company practices.

Equipment Selection: Proper equipment is necessary for an efficient and safe operation. Consid-

erable care must be exercised in selecting the proper equipment with the correct pressure rating and

design for a specific job. Primarily, this should be the Drilling Superintendent’s responsibility and the

Drilling Manager and Engineering Advisor should agree.

Hiring Contract Rigs: The Drilling Superintendent and Engineering Advisor will usually provide the

proper rig for the job. How long the rig has been in the area could be a factor, and rig evaluations

should include past performance and the condition of the equipment. If crews change seasonally, the

decision could be based on the general performance of the contractor.

Specification of Rig Equipment: Selecting the proper equipment to do a particular job is of utmost

importance. The Drilling Superintendent’s familiarity with the operation makes him best qualified to

recommend equipment.

Contract Responsibilities: The Drilling Superintendent and Drilling Manager have the responsi-

bility to see that the contracts between Chevron and the drilling contractor are written programs

clearly defining the obligations of both contracting parties.

Rev 12/94

A-2


VOLUME ELEVEN


Training of Company and Contract Personnel: The Drilling Superintendent and Engineering

Advisor should maintain a training program for the least experienced drilling employees. The

program should pair the newer employees with experienced Drilling Representatives at the wellsite,

and include attendance at DTC schools and seminars. Drilling Superintendents should periodically

review well control procedures with the Drilling Representatives.

The contractor should be required to train employees in well control either by contract or under the

direction of the Drilling Superintendent or supervisors.

BOP Equipment: The Drilling Representative must ensure that the proper BOP equipment is

available in good working order and installed correctly. Equipment must be in compliance with all

Chevron and governmental requirements. All sections of the “BOP Test and Equipment Checklist”

should be completed upon initial nipple-up.

BOP Testing: Most Chevron wells are required to test the blowout preventer stack once a week and

before drilling out each new casing string. Accurate and complete testing of the BOP’s is the

responsibility of the Drilling Representative on location. The "BOP Test and Equipment Checklist"

should be completed after each test.

Well Control: The Drilling Representative is primarily responsible for keeping the well under control.

This responsibility includes maintaining proper mud properties, recognizing indicators of abnormal

pressure, and executing the proper well control procedures after the well kicks.

Prerecorded Data Sheet: The Prerecorded Data Sheet should be filled-out as completely as

possible at all times on drilling wells. The Data Sheet lists critical wellbore information which will be

needed in nearly all well control situations.

Slow Pump Rate Data: The Drilling Representative must make sure that slow pump rates and

pressures are recorded at least once per tour, or each time the mud weight is changed.

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 Representative must make sure that the

crews are properly trained and respond immediately in all well control situations. The Drilling

Representative should also verify that the shut-in procedures while tripping and drilling are clearly

posted at several locations around the rig, and that every crew member knows shut-in responsibilities.

If working in an OCS area, the Drilling Representative is responsible for verifying that all crew

members are MMS certified for well control training.

Information to be Posted: The Drilling Representative should 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.

A-3

Rev12/94


VOLUME ELEVEN


SECTION B : BASIC CALCULATIONS AND TERMINOLOGY

1. UNDERSTANDING PRESSURES

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 its density. It should

be remembered that both liquids and gases can exert hydrostatic pressure. Hydrostatic pressure

exerted by a column of fluid can be calculated using Equation B.1, below:

Hydrostatic Pressure

Eqn B.1 HP = MW x 0.052 x TVD

where:

HP =

MW =

TVD =

Hydrostatic Pressure (psi)

Mud Weight (ppg)

True Vertical Depth (ft)

While drilling ahead, hydrostatic pressure exerted by the drilling mud is the major deterrent against

kicks.

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 by using

the formula in Equation B.2.

Pressure Gradient

Eqn B.2

where:

PG

= MW x 0.052

PG = Pressure Gradient (psi/ft)

MW = Mud Weight (ppg)

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.

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 also the mud weight required in the well. If the formation pressure is greater than the hydrostatic

pressure of the mud column, fluids such as gas, oil, or saltwater can flow into the well from permeable

formations. Normal pressure gradients for formations will depend on the environment in which they

were laid down and will vary from area to area.

Rev. 12/94

B-1


VOLUME ELEVEN


Consider a formation located at a vertical depth of 5,000' and with a reservoir pressure of 2,325 psi.

The pressure gradient of this formation can be easily figured with the following formula:

Pressure

2,325 psi

PG =

-----------------------

=

---------------

= 0.465 psi/ft

Vertical Depth

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 is achieved by filling the hole with 9.0 ppg saltwater.

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 that 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 is that the pump pressure is created by 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 that 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 that we observe at the surface will also be conveyed

downhole.

Bottomhole Pressure: Bottomhole pressure is equal to the sum of all pressures 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, and the

effect of friction pressure must be added or subtracted depending on the direction of flow. This is

expressed mathematically in Equation B.3 to the right:

Bottomhole Pressure

Eqn B.3B

HP = 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 closed-in under static conditions, the bottomhole pressure will be equal to the sum of the

hydrostatic pressure and any observed surface pressure. In this case, the bottomhole pressure will

also equal the formation pressure.

Rev. 12/94

B-2


VOLUME ELEVEN


Equivalent Circulating Density: When circulating fluid in a wellbore, frictional pressures occur in

the surface system, drillpipe, bit, and annulus which in turn are reflected in the standpipe pressure.

As mentioned previously, these frictional pressures always act opposite to the direction of the flow.

When circulating conventionally (the "long way"), all the frictional pressures, including annular

friction, act against the pump. The annular friction, or annular pressure loss, acts against the bottom

of the wellbore, resulting in an increase in bottomhole pressure. This is known as Equivalent

Circulating Density, or ECD. ECD is normally expressed as a pound per gallon equivalent mud

weight, and is shown mathematically in Equation B.4.

Equivalent Circulating Density

Annular Pressure Loss + Present Mud Weight

Eqn B.4

ECD = ------------------------------------------------------------

0.052 x TVDhole

ECD is the 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 AV).

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 through a wellbore,

bottomhole pressure will be higher than when the well is static due to the presence of annular friction.

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.

Choke Pressure: Choke pressure is the pressure loss created by directing the return flow from a

closed-in well through a small opening or orifice for the purpose of creating a back pressure on the

well while circulating out a kick. The choke, or back pressure, can be thought of as a frictional pressure

loss that will be imposed on all points in the circulating system, including the bottom of the hole.

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 has the opposite effect,

whereby wellbore pressure is temporarily increased as pipe is run into the well. The movement of the

drill 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 below as the piston or the pipe

is moved upward in the cylinder or wellbore and a pressure increase occurs below as they move

downward.

Rev. 12/94

B-3


VOLUME ELEVEN


Swab and surge pressures are mostly affected by the velocity of upward or downward movement in

the hole. Other factors affecting these pressures include:

1)

2)

3)

4)

5)

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.

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 a formation can withstand before it fails or splits.

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

ppg, respectively.

2. 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 also related 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.

Liquids: Liquids of concern in well control include mud, saltwater, oil, brine, and combinations 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 are considered negligible for nearly all

well control calculations.

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, surface

pressure must be allowed to increase. The expanding gas also causes the pit level to increase and

must be considered. With constant surface pressure, the volume of the gas bubble will roughly double

Rev. 12/94

B-4


VOLUME ELEVEN


each time the bubble depth is halved. If V is the volume of a gas and P is the pressure, disregarding

temperature effects, the relationship between volume and pressure of a gas is given by Boyle's Law,

as shown in Equation B.5.

Boyle's Law

Eqn. B.5

where:

P1 x V1 = P2 x V2

P1 = Pressure of gas at depth 1

V1 = Volume of gas at depth 1

P2 = Pressure of gas at depth 2

V1 = Volume of gas at depth 2

3. 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 a mud pit, an open hole, the inside of a drillstring, 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. Formulas

for calculating these capacity factors are given below:

Internal Capacity Factor:

ID2

Eqn B.6

where:

CF =

CF =

ID =

----------

1029

Capacity Factor (bbl/ft)

Internal pipe diameter (inches)

Annular Capacity Factor:

ID2 - OD2

Eqn B.7

where:

CF = --------------

1029

CF = Capacity Factor (bbl/ft)

ID = Diameter of hole or inside diameter of larger pipe (inches)

OD= Outside diameter of smaller pipe (inches)

In lieu of these equations, Tables P.1 through P.4 can be used to determine internal and annular

capacity factors for several wellbore configurations.

Rev. 12/94

B-5


VOLUME ELEVEN


Capacity is the volume of fluid held within a specific container. Internal (drillstring) and annular

capacities are two of the most important parameters that are calculated in a well control situation.

Capacity is determined by multiplying the height (or length) of the container by its capacity factor.

Displacement is the volume of fluid displaced by placing a solid, such as drillpipe or tubing into a

fixed volume of liquid such as drilling mud. 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 through P.3.

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.

Rev. 12/94

B-6


VOLUME ELEVEN


SECTION C: CAUSES AND DETECTION OF KICKS

1. CAUSES OF KICKS

A kick is defined as any undesirable flow of formation fluids from the reservoir to the wellbore that

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:

Causes of Kicks

•

•

•

•

•

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 upon what can be done

early to avoid this situation.

A. Low Density Drilling Fluid

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 that could

initiate a kick. Diligence on the mud pits is the best way to ensure that the required fluid density

is maintained in the fluids pumped 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 should be

drawn between density reductions caused by gas cutting and those caused by oil or salt water

cutting.

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 unnecessary concern, and often results in over-weighting

of the mud. The reduction of bottomhole pressure due to gas cutting at the surface is illustrated

in the following table.

Rev. 12/94

C-1


VOLUME ELEVEN


Effect Of Gas Cut Mud On The Bottom Hole Hydrostatic Pressure

Pressure Reduction (psi)

---------------------------------------------------------------------------------------------------------------

10.0 PPG Cut To 18.0 PPG Cut To 18.0 PPG Cut To

Depth 5.0 PPG 16.2 PPG 9.0 PPG

1000

5000

10000

20000

51

72

86

97

31

41

48

51

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 that 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 substantial 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 possible that a well could be flowing

at the surface as the gas breaks out and still be overbalanced 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 when this occurs.

In a balanced or slightly overbalanced condition, gas originating from cuttings could reduce the

bottomhole pressure sufficiently to initiate a kick. Gradual increases 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.

Oil or Salt Water Cutting Oil and/or saltwater can also invade the wellbore from cuttings 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. Also, since

liquids are only slightly compressible, little or no expansion will occur when circulating them out.

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.

Rev. 12/94

C-2


VOLUME ELEVEN


B. 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 saltwater 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 subnormally 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. Saltwater is the most

common formation fluid and averages about 8.95 ppg or 0.465 psi/ft along the U.S. Gulf Coast.

Therefore, 0.465 psi/ft is considered the normal formation pressure gradient for the Gulf Coast.

Normally pressured formations are often drilled with about 9.5 to 10.0 ppg 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

the 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 the density per

unit volume will increase with depth. However, if a permeability barrier or 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 C.1

below.

Figure C.1

Abnormally Pressured Sand Formation

Less Dense Shale

Denser Shale

Normal Sand

Denser Shale

Less Dense Shale

(due to free water)

Over-Pressured Sand Formation

Denser Shale

Rev. 12/94

C-3


VOLUME ELEVEN


Figure C.2 - Abnormal Pressure Due to Faulting

8,000 ft.

10,000 ft.

4650 psi

4650 psi

Another common cause of ab-

normal pressure is faulting.

As can be seen in Figure C.2,

a formation originally depos-

ited under normal pressure

conditions is uplifted 2,000 ft.

The pressure within the up-

lifted 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 drill-

ing into an abnormal pressure

zone of this nature.

Abnormal pressure

can also occur as the

result of depth and

Figure C.3 - Abnormal Pressure due to Folding

structure changes

within a reservoir. As

shown in Figure C.3 ,

at 3,000 ft. the forma-

tion pressure at the

gas-water contact is

normal and equal to

0.465 psi/ft x 3000 ft =

3,000 ft.

WATER

2,000 ft.

GAS

1,395 psi. However,

at the top of the struc-

ture (2,000 ft), the formation is overpressured and approximately equal to 1,295 psi. (Note: 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/(0.052 x 2,000') = 12.5

ppg.

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 chapter.

Usually, abnormally pressured formations give enough warning that proper steps can be taken.

As noted elsewhere in this guide, low mud weights best indicate abnormal or high-pressure

zones. Once these zones are detected, it's 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 the highest 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.

Rev. 12/94

C-4


VOLUME ELEVEN


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 enter into the wellbore.

C. Swabbing

Swabbing is a condition that 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 that have almost certainly lowered the hydrostatic

pressure of the mud column. Usually, the volume of fluid swabbed-in to the well is 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 saltwater has probably

been swabbed into the wellbore. If swabbing is indicated (even if there's no flow), the pipe should

be immediately run back to bottom, the mud circulated out, and the mud densified or conditioned

before making the trip.

A short trip is often made to determine the combined effects of bottomhole pressure reductions

that are caused by a loss of equivalent circulating density and swabbing. When drilling under

or near balanced conditions, a short trip is particularly important since it quickly indicates 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.

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 that can swab more fluids 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.

Pulling Pipe Too Fast: The piston action is also enhanced when pipe is pulled too fast. The

Rig Supervisor 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. The maximum pulling speed can be determined for a given set of mud properties using

the available DRILPRO programs.

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.

Rev. 12/94

C-5


VOLUME ELEVEN


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.

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.

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 EP

additives are effective in many cases. Good hydraulics will often help clean a balled-up bit or

bottomhole assembly.

D. Not Keeping Hole Full

Blowouts that occur on trips are usually the result of either swabbing or not keeping the hole full

of mud. Substantial progress has been made in blowout 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 Representative to see that the rig crews are thoroughly

schooled in the necessity of keeping the hole full. Many mechanical devices have been

developed to help keep the hole full. These include:

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.

Stroke Counter: These counters, mounted near the Driller’s position, are convenient for

checking filling volume requirements. Because they are operated only by the Driller, there

should be no communication problem.

Pit Volume Monitoring: Bulk mud volume checking is also very helpful, but large pits will not

indicate 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, it should be manned

by an experienced crew hand.

Rev. 12/94

C-6


VOLUME ELEVEN


Flowline Monitors:

Besides monitoring flow while drilling, these devices detect fluid

immediately when the hole fills, ensuring a good comparison between pump strokes and

returning fluid flow rate. Also, these devices detect “no-flow” when lost circulation occurs. Their

proper use should prevent blowouts due to not keeping the hole full or swabbing. Since flowline

monitors can detect flow while the drill string is out of the hole, they should be left on

continuously.

E. 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:

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. If 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 the correct weight of mud that the

formation will support without fracturing. Upon gaining returns, verify that the well is not flowing

on its own.

Going into the Hole Too Fast: Loss of circulation can also result from rapidly lowering the drill

pipe and bottom assembly (drill collars, reamers, and bit). This is similar to swabbing, but 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. Surging calculations can be easily made using the

available DRILPRO programs.

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 pipe, or stabilizers

inside the protective casing. 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.

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 backpressure 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.

Rev. 12/94

C-7


VOLUME ELEVEN


2. 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 well bore and minimize the casing pressures.

Kick indicators are classified into two groups: positive and secondary. Anytime 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, steps should be taken to verify if the well is indeed kicking.

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

→

→

Increase in Pit Volume

Increase in Flow Rate

well whenever these indicators are experienced. It is

not recommended to check for flow after a positive

indicator has been identifed.

The "Secondary Indicators of a Kick" are shown

to the right. The occurence of any of these

Secondary Indicators of a Kick

indicators should alert the Drilling Representa-

tive 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.

Indicators of Abnormal Pressure

→

→

→

→

→

Decrease in Circulating Pressure

Gradual Increase in Drilling Rate

Drilling Breaks

Increase in Gas Cutting

Increase in Water Cutting or Chlorides

→

→

→

→

→

→

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 ac-

tion may range from increasing the mud weight

to setting casing.

The following pages describe these indicators in detail and prescribe the proper remedial action to

take in the event of their occurrence.

A. Increase in Pit Volume

A gain in the total pit volume at the surface, when there are no mud materials 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

Rev. 12/94

C-8


VOLUME ELEVEN


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. Each change in

addition rate, particularly of water or barite, should be reported. Any change in valve settings

that 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-ins of the well. Again, the Driller should always shut

the well in first, and then determine the reasons for a pit gain.

B. 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.

C. 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 from a washout in the drillstring. To verify the

cause, the pump should be shut down and the flow from the well should be checked. If the flow

continues, the well should be shut-in and checked for drillpipe pressure to determine whether

an underbalanced condition exists.

D. Gradual Increase in Drilling Rate

While drilling in the normally pressured shales of a well, there will be a uniform decrease in the

drilling rate. Assuming that bit weight, RPM, bit types, hydraulics and mud weight remain fairly

constant, the decrease will be due to the increase in shale density. When abnormal pressure

is encountered, the density of the shale is decreased and so is the porosity. Higher porosity

shales are softer and can be drilled faster. Therefore, the drilling rate will almost always increase

as the bit enters an 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 offset well electric logs to pinpoint the top of an abnormal pressure

zone before any other indicators appears.

Rev. 12/94

C-9


VOLUME ELEVEN


In areas where correlation with other wells

may be difficult, calculation and plotting of

the "d" exponent can be helpful in detect-

ing abnormal pressure. The "d" exponent

is obtained from the basic drilling equation

shown below. As penetration rate is ef-

fected by mud weight, a correction for

actual mud weight must be made, as shown

to the right:

Corrected "d" Exponents

9.0

dc = ---------------------------- x d : for Gulf Coast

Actual Mud Weight

8.25

dc = ---------------------------- x d : for Hard Rock

Actual Mud Weight

"d" Exponent Equation

R= K

12 Wd

-------------

10 3 D

60N

Figure 11C.4

dc Exponent vs. Depth

where:

10000

1

1.5

2

2.5

R = Penetration Rate (ft/hr)

K = Formation Drill Constant

W = Weight on Bit (m-lbs)

D = Bit Diameter (in)

N = Rotary Speed (rpm)

d = Drilling Exponent

Plotting “dc” versus depth result in a plot similar to

the one shown in Figure C.4. The point at which the

plot shifted left is where abnormal pressure was

encountered. A Mud Logger on location would

normally maintain a plot of this type.

E. 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, etc. and experience in the

Well

Depth, ft.

11000

12000

13000

specific area is required. In some sand-shale se-

quences, 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

14000

8 9 10 11

Mud Weight, ppg.

drilling in expected high pressure areas, if a rela-

tively long interval of slow (shale) drilling is sud-

denly interrupted by faster drilling ( indicating a sand) the kelly should be picked up immediately,

the pump 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 hydrostatic, flow may be difficult to detect. If there is doubt and drilling

is in an expected abnormal pressure area, it may be best to circulate the break to the surface.

Rev. 12/94

C-10


VOLUME ELEVEN


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) before increasing the mud weight and drilling ahead.

F. 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.

F.1. Drilled Gas

This is the gas entrained in the rocks that are drilled. The drilled (or background) gas will

usually increase as the bit penetrates an abnormally pressured shale. Abnormally pres-

sured 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.

F.2. Connection Gas

Connection gas is a measure of gas which is either swabbed into the hole while pulling up

for a connection or is a result of a 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

it takes to pump mud from the bottom of the hole to the surface and checking the gas

detector to record the 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.

F.3. Trip Gas

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 15-20 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. Trip gas will generally increase when an abnormal-

pressure section has been penetrated and the mud weight has not been raised. This is not

a good indicator of abnormal pressure by itself, but is useful with other evidence. Trip gas

should be reported as the total units observed.

G. 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 will be unaffected, but perhaps a change

in salinity will be apparent. This would depend on the salinity contrast between the formation

Rev. 12/94

C-11


VOLUME ELEVEN


fluid and the mud. Usually formation fluids are more salty 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.

H. Decrease in Shale Density

The shale density will generally decrease when an abnormal pressure zone is penetrated. This

would be a good indicator if bulk densities of representative samples could be accurately

measured. A decrease in density is a result of an increase in the water content within the shale.

I. Change in Cutting Size and Shape

The amount of shale cuttings will usually increase and change in shape will take place when an

abnormal pressure zone is penetrated. Cuttings from normally pressured shales are small with

rounded edges and are generally flat, while cuttings from an abnormally pressured often

become long and splintery with angular edges. As the differential between the pore pressure and

the drilling fluid hydrostatic pressure is reduced, 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.

J. 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.

K. 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 deceiving. Temperatures are also

increased temporarily by the addition of barites 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 large-scale depth vs. temperature plot.

L. 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.

M. Tight Hole on Connections

When making connections, a tight hole can indicate that an abnormally pressured shale is being

penetrated with low mud weight. Often the hole must be reamed several times before a

connection can be made. The drillpipe could stick or a blowout could occur if abnormal pressure

goes undetected.

Rev. 12/94

C-12


VOLUME ELEVEN


SECTION D: SHUT-IN PROCEDURES

1. MINIMIZE THE SIZE OF THE INFLUX

Chevron's Shut-in Procedure is designed with an overriding purpose in mind: minimizing 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 yield 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. Remember, the larger the influx, the

higher the casing pressures, so, minimize the size of the influx.

Figure D.1 - Effect of Influx Size on

Casing Pressure

Driller's Method

3000

2500

2000

1500

1000

500

0

0

50

100

150

200

250

300

350

400

450

500

Volume of Mud Pumped - Bbls

2. 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.

Rev. 12/94

D-1


VOLUME ELEVEN


Chevron's recommended "Three S" Shut-in Procedure While Drilling is given below:

Shut-In Procedure While Drilling

(1)

(2)

(3)

SPACE OUT

SHUT DOWN

SHUT-IN

Pull the kelly out of the hole. Position the kelly so that there are

no tool joints in the preventer stack.

Stop the mud pumps.

Close the annular preventer or uppermost pipe ram

preventer. Confirm that the well is shut-in and flow has stopped.

The person most likely to shut-in the well is the Driller. The Chevron Drilling Representative 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 Chevron Drilling Representative and the Contract Toolpusher. At this time, all

members of the drilling crew should be at their predetermined stations awaiting further instructions.

Chevron recommends 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 the well is 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. POST SHUT-IN PROCEDURES WHILE DRILLING

After the well has been shut-in, the Drilling Representative has several items to read and record.

These include:

(1) SICP

(2) SIDP

(3) PIT GAIN

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.

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.

However, since it is recommended practice, 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.

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.

Rev. 12/94

D-2


VOLUME ELEVEN


(4) TIME

Make a note of the time the kick occurred. Also, keep an accurate log of the entire

kill operation as it progresses.

(5) CLOSING PRESSURES If the Drilling Representative decides to work the pipe during the kill

circulation, then the closing pressure on the annular preventer should probably be

reduced to prolong the life of the element. The proper amount of closing pressure

will depend on the size and make of the preventer and the wellbore pressure

underneath. It should be high enough to prevent wellbore fluid from leaking around

the element.

After this information has been gathered, the Drilling Representative should notify his Supervisor to

discuss the appropriate method for killing the well.

4. SHUT-IN PROCEDURE WHILE TRIPPING

Statistics indicate that the majority of kicks occur while tripping. Pulling out of the hole is a critical

operation that demands diligence by the drilling crews and is not the time to be lax about well control!

Hole filling and hole monitoring equipment should be in top condition so that the kicking well can be

detected as early as possible. Preparation for a trip should be the same as the one 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 from the

negative pressure differential generated by the swabbing effect. The well may not continue to flow

after the pipe is stopped, but formation fluids that have entered the annulus reduce 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. 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 Install the fully opened safety valve in the drillstring. Close the safety valve.

(2) SPACE OUT

(3) SHUT-IN

Position the drillstring so that there are no tool joints in the preventer stack.

Close the annular preventer or uppermost pipe ram preventer. Confirm that

the well is shut-in and flow has stopped.

After the well is securely shut-in, the Driller should notify the Chevron Drilling Representative and the

contract Toolpusher while all members of the drilling crew are at their assigned stations awaiting

further instructions.

Rev. 12/94

D-3


VOLUME ELEVEN


NOTE:

It is recommended that this "Three S" Shut In Procedure be followed even when the rig

is equipped with a top drive unit. The temptation would be to screw in the top 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.

5. 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 Representative will need to gather as much information

about the wellbore condition as possible. These will include:

(1) SICP

(2) PIT GAIN

(3) TIME

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.

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 totalizers can be

examined in an attempt to determine the pit gain in these instances.

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.

(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:

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 shut-in drillpipe cannot be calculated.

After this information has been gathered, the Drilling Representative should consult with a Drilling

Supervisor to determine the proper remedial action to take in controlling the well. This will usually

involve stripping back to bottom, which is covered in Section I.

Rev. 12/94

D-4


VOLUME ELEVEN


6. 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, on the following

page.

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

detected.

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 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).

Check the shut-in casing pressure again. Any excess pressure may be bled-off 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.

7. 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 the shut-in pressures.

Rev. 12/94

D-5


VOLUME ELEVEN


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 the size of the 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 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.

7. DIFFERENTIAL PRESSURE STICKING

The drill string 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. In an attempt to avoid differential sticking during the kill operation, many Superintendents

will instruct their Drilling Representatives to “work the pipe” during the kill. Others rely on killing the

well first and then getting unstuck. While working the pipe has probably kept many wells from

becoming stuck, it can cause hazards. Each well control situation must be examined individually in

order to make a sound decision.

Rev. 12/94

D-6


VOLUME ELEVEN


SECTION E: WELL KILLING PROCEDURES

1. CONSTANT BOTTOMHOLE PRESSURE

Chevron recommends two well killing methods: the Driller’s Method and the Engineer’s (or Wait and

Weight) Method. Both of these methods, discussed later in this section, 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 rate 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 calculate pressures throughout the system. Also, it provides the minimum

pressure needed to balance the reservoir pressure, which helps prevent a second fluid influx and

holds surface pressures low enough to prevent formation breakdown and lost circulation.

Except for Volumetric Control, all methods discussed in this guide 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 B.1, when

circulating through a well, bottomhole pressure is increased due to annular friction. As the value of

ECD is very difficult to calculate and varies greatly from one situation to another, the effect of ECD

is not taken into account in any of the methods. However, it is important to realize that annular friction

does increase BHP throughout the circulation. Thus, holding more backpressure than required is

not necessary to prevent taking an additional influx, and could result in formation breakdown or lost

circulation.

Figure E.1 - Simple U-Tube Analogy

2. THE U-TUBE PRINCIPLE

A thorough understanding of the relation-

ship between bottomhole pressure, cas-

ing pressure, and drillpipe pressure is

necessary to effectively use the well con-

trol procedures discussed in this volume.

Perhaps the best way to illustrate this

relationship is through the concept of a U-

Tube.

Figure E.1 illustrates the cross section of

two vertical tubes of the same size con-

nected 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

Column A

Bottomhole Pressure

Column B

Rev 12/94

E-1


VOLUME ELEVEN


resembles the letter U. The U-Tube is a convenient way to depict 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 considered as the bottomhole pressure.

Basic Well Control Equations (Static Conditions)

Two equations that were pro-

vided earlier are needed to

understand and explain the

concept of the U-Tube.

These are shown again to

the right:

In U-Tubes where the fluid

levels are static, the bot-

tomhole pressure gener-

Bottomhole Pressure = Hydrostatic Pressure + Surface Pressure

Hydrostatic Pressure = 0.052 x Mud Weight x True Vertical Depth

Basic U-Tube Concept

ated by Column A is equal

to the bottomhole pressure

Hydrostatic Pressure

(Column A)

+ Surface Pressure

generated by Column B.

This relationship is stated

mathematically:

is equal to

Hydrostatic Pressure (Column B) + Surface Pressure (Column B)

is equal to

Bottomhole Pressure

U-Tubes are not very interesting when the same density fluid fills both columns. In these instances,

the hydrostatic pressure and surface pressure of both columns are equal. This 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.

However, U-tubes are more 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. An example of this occurs 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

underbalance is reflected as a surface pressure on the drillpipe gauge. 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. Thus, the annulus side is more

underbalanced than the drillpipe side and the resultant shut-in casing pressure is higher than the

shut-in drillpipe pressure. This effect is shown in Figure E.2 on the following page.

Rev. 12/94

E-2


VOLUME ELEVEN


Figure E.2

5740

540

680

Drill Pipe Mud

10 ppg

540

Annulas Mud

10 ppg

5740

680

Gas Kick

In Figure E.2, a 10,000 ft. well with 10 ppg mud has penetrated an overpressured sand with a reservoir

pressure of 5,740 psi and taken a 30 bbl kick. Since the hydrostatic head of the 10 ppg mud is only

5,200 psi (10,000' x 10 ppg x 0.052 = 5,200 psi), the drillpipe is underbalanced by 540 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.

3. THE DRILLER’S METHOD

The Driller’s Method of well control requires two separate circulations of the well. The first circulation

is required to remove the influx from the annulus using the mud density in the hole at the time of the

kick. After the pumps are started, the drillpipe pressure is held constant by choke manipulation 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.

Rev 12/94

E-3


VOLUME ELEVEN


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 that 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 is checked for flow.

Any time a well under pressure is circulated, the start-up and shut-down procedures are critical and

should be done with exceptional care. Whenever the pump speed is increased or decreased

(including start-up and shut-down), 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. THE ENGINEER’S METHOD

Also called the Wait and Weight 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 and the pressures and pit volume increase have been

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:

Sample Drillpipe Pressure Schedule for the Engineer's Method

Strokes

Drillpipe

Pumped

0

100

200

300

400

500

600

700

800

Pressure

540

520

500

480

460

440

420

400

380

Comment

Well is shut-in.

100 strokes of kill mud pumped.

Kill mud half-way to the bit.

600 strokes of kill mud pumped.

Kill mud reaches the bit.

Rev. 12/94

E-4


VOLUME ELEVEN


Once the kill mud reaches the bit, the drillpipe pressure should be held constant until it 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 same 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 constant.

As with the Driller’s Method, any time a well under pressure is circulated, the start-up and shut-down

procedures are critical and should be done with exceptional care. The following advice on this topic

warrants repeating. Whenever the pump speed is increased or decreased (including start-up and

shut-down), the casing pressure must be held constant at the value it had immediately before the

pump speed changed in order to keep bottomhole pressure constant. This procedure is valid because

casing pressure will virtually be the same whether the well is closed-in or being pumped. However,

the drillpipe pressure will 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 due to the

changing height of the influx caused by the irregular annulus and gas expansion.

5. COMPARISON OF THE METHODS

Both the Driller’s and Engineer’s Methods have advantages and disadvantages, depending on the

general conditions of the area of operation or the specific conditions in a well. The correct kill method

is determined through discussions between the Drilling Representative on location and the Drilling

Supervisor.

Figures E.3 and E.4 illustrate a gas kick being circulated to the surface using both the Driller’s and

the Engineer’s Method. Observing both figures, note that when the gas bubble reaches the casing

shoe, the Driller’s method produces 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. Since the

bottomhole pressure is held constant, the surface casing pressure must increase. 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 increase 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. Exceptions to this take place when the kick volume enters

the well filling it above the shoe, or 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, or

at 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 and the pressure at the shoe

is reduced.

Rev 12/94

E-5

Figure E.3 - Removing Gas Influx with the Driller's Method

Driller's Method -

First Circulation

500

Well

Shut-In

700

1500

Break

Circulation

700

1500

Kill Mud

at the Bit

850

1500

1000

Gas Bubble

at Shoe

1500

1800

Gas Bubble

at Surface

500

Influx

Removed

500

Figure E.4 - Removing Gas Influx with the Engineer's Method

Engineer's Method

500

Well

Shut-In

700

1500

700

Break

Circulation

1000

Kill Mud

at the Bit

850

1000

950

Gas Bubble

at Shoe

1000

1000

Gas Bubble

at Surface

0

Influx

Removed

0


VOLUME ELEVEN


In both methods, once the top of the bubble passes the shoe, the shoe pressure decreases 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. In the Engineer's Method, as long

as BHP is kept constant, shoe pressure continues to decline until kill mud fills the annulus below the

shoe. Therefore, the Engineer's Method will always be less than or equal to the shoe pressure with

the Driller's Method. A summary of the advantages and disadvantages of both methods is provided

in Table E.1 below.

Table E.1 - Kill Method Comparison

Method

Driller’s

Advantages

1. Simplicity, few calculations

2. Can be used until barite arrives

3. Circulate quickly, reduce sticking

and gas migration.

Disadvantages

1. Requires two circulations

2. Higher surface pressures

3. Higher casing shoe pressures

Engineer’s

1. One circulation required

2. Lower surface casing pressures

3. Lower casing shoe pressures

1.

2.

3.

4.

More complex calculations

Waiting may stick pipe

Waiting allows gas to migrate

Mud mixing capabilities

6. OTHER WELL CONTROL METHODS

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 equates pit volume change with annulus

pressure. When possible, the drillpipe should be stripped back to bottom and the well killed using

the Driller’s Method. This procedure will be discussed later in detail later.

The Low Choke Pressure Method: This method is used if pressures threaten to become excessive.

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, light weight mud, and low choke pressure all balance the formation pressure. Formations

with high permeabilities cannot be effectively killed by this method; the influx won't be controllable.

The corresponding reduction of hydrostatic pressure will prevent the killing of the well and possibly

cause loss of the hole. Numerical analysis of the Darcy equation indicates that this method is

questionable where formation permeabilities are greater than 200 millidarcys. This method should

not be used when there is uncertainty about formation permeability, and therefore is not

generally recommended.

Rev. 12/94

E-8


VOLUME ELEVEN

WELL CONTROL AND BLOWOUT PREVENTION GUIDE

SECTION F: PRERECORDED DATA SHEET

1. PURPOSE OF THE PRERECORDED DATA SHEET

The Prerecorded Data Sheet is a two-sided information page which lists the wellbore capacities and

volumes for a particular well. This is a critical well control document that must be kept as current and

as accurate as possible. The Drilling Representative will need this information to complete the

Engineer’s or Driller’s Method Worksheets if a kick occurs.

The information on the Prerecorded Data Sheet is used to calculate pumping volumes and strokes

and is therefore crucial to the successful completion of most well killing operations. A sheet must

be filled out when a kick is taken so that the information it contains will be readily available. When

the Data Sheet has been filled out ahead of time, the Drilling Representative does not have to spend

his time figuring wellbore capacities and volumes after a kick has occurred when time may be critical.

Also, this gives the Drilling Representative additional time to check the accuracy of the figures.

NOTE: Therefore, it is strongly recommended that the Prerecorded Data Sheet be

filled-out as completely as possible at all times while drilling.

Much of the data on the Prerecorded Data Sheet remains the same from day-to-day, so it’s fairly

simple to keep it up-to-date. Many of the measurements are easily memorized because they are used

so frequently. However, it's advisable to keep important figures written down and on hand for

everyone on the rig to refer to in a critical situation.

2. USING THE PRERECORDED DATA SHEET

The following is a guide for Drilling Representatives on filling in the blanks on a Prerecorded Data

Sheet:

Well Data

The well data section is composed of the well name, field name, and rig name. These items should

be filled out completely.

Hole Data

Size: Record the hole size as the diameter of the bit in the hole.

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 survey data.

Capacity Factor: Record the capacity factor of the hole size listed above in bbls/ft. Use Table 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).

To determine the open hole capacity for subsea wells, multiply by the measured depth minus the RKB

to mud line length by the open hole capacity factor.

Rev. 12/94

F-1


VOLUME ELEVEN


Pump Data

Liners: Record as the pump liner diameter (inches) for duplex or triplex pumps.

Stroke: Record as the pump stroke (inches) for duplex or triplex pumps.

Rod Size: Record as the pump rod diameter (inches) for duplex pumps only.

% Efficiency: Record as the mechanical pump efficiency as determined by top plug displacement

during a cement job or by pumping into the trip tank.

Bbl/stk: Use Table P.5 to determine the theoretical pump displacement and multiply by % Efficiency

above to determine the actual pump output.

Casing Data

Record the outside diameter, inside diameter, measured depth, and true vertical depth of the last full

string of casing in the ground.

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.

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.

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.

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 internal 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.

Rev 12/94

F-2


VOLUME ELEVEN


Annulus Capacities (surface stacks only)

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 System Total

Capacity (not including the active pit volume).

Divide the Total Annulus capacity (bbls) and the System Total capacity by the pump output (bbls/stk)

to determine these capacities in strokes.

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 lbs/gal) and then multiplying

this figure by the true vertical depth of the shoe and by 0.052. This formula is stated in equation form

below:

MISICP = (Shoe Test, lb/gal EMW - Present Mud Weight, lb/gal) x TVDshoe ,ft x 0.052

3. “KEEP THIS WELL DATA SHEET CURRENT AT ALL TIMES”

The Prerecorded Data Sheet should be kept as current and as accurate as possible so that time won’t

be 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:

Sections Fully Completed

Well Data Section

Pump Data Section

Casing Data Section

Wellhead or Casing Pressure Limitation Section

Liner Casing Data Section

Drillstring Data Section

Maximum Initial SICP Section

However, some of the Sections on the Prerecorded Data Sheet cannot be fully completed until after

the well has kicked. These include:

Sections Partially Completed

Hole Data Section:

Internal Capacities:

Annulus Capacities:

All items should be completed except the Measured Depth and True

Vertical m Depth. These depths are recorded after the kick occurs.

All items should be completed except the Drillpipe Length (ft) and

Volume (bbls). These items are recorded after the kick occurs.

All items should be completed except Drillpipe x Casing or Hole (ft)

and Volume (bbls). These items are recorded after the kick occurs.

Rev. 12/94

F-3


VOLUME ELEVEN


If the Prerecorded Data Sheet is completed as described above, the only blanks remaining on the

sheet will be those whose which require the length of drillpipe in the hole (which is constantly

increasing as you drill deeper). If a kick is taken, the Drilling Representative simply needs to

determine the length of drillpipe in the hole and the remaining capacities (hole, internal, and annulus)

can be easily calculated.

4. SOME COMPLICATING SITUATIONS

Sometimes, complicated wellbore and drillstring configurations combine to make completion of the

Prerecorded Data Sheet unclear. Some of these special situations (with remedies) are described

below.

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 component, which is opposite the liner top needs to have two separate annular capacity

figures (one for the liner, a second for the casing). Therefore, 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 to do this only

for the drillstring component that 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 when drilling. 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.

Tapered Drillstring: A tapered drillstring changes both the internal and the external capacity figures

at the point of crossover. Include the capacity figures (bbl/stk) for both sizes of drillpipe on the

Prerecorded Data Sheet. Compute the internal and annular capacities opposite the smaller diameter

drillpipe in the same manner as the Drill Collars.

5. SUBSEA CONSIDERATIONS

Use of a subsea preventer stack creates several situations that are not addressed in the previous

discussions. The opposite side of the Prerecorded Data Sheet is designed for subsea use only and

replaces or augments the prerecorded information on the front.

Internal Capacity: The internal capacity of the drillstring is transferred from the front side of the

sheet.

Annular Capacity: The annular capacity calculations must be modified when a subsea blowout

preventer is used. The Annular Capacity Section on the front side of the sheet should not be used.

Instead, the following subsea items of interest must be considered.

Rev 12/94

F-4


VOLUME ELEVEN


1. Choke line length is recorded as the total length of the actual piping from the subsea

stack to the choke manifold. Allowances may be made for loops in the moon pool and

other turns when determining this length. Record this length in the Annulus Capacity

Section.

2. D.P. x Casing or Hole Length is determined by the subtracting the D.C. x Hole Length

and the RKB to Mud Line Length from the Measured Depth of the hole. This will provide

the length of drillpipe from the bottomhole assembly to the subsea stack.

DP x Casing or Hole Length = Measured Depth - (D.C. x Hole Length) - (RKB to Mud

Line Length)

3. D.C. x Hole Length is simply the length of the bottomhole assembly.

NOTE: Addition of these three lengths may yield a value which is greater than the Measured Depth

of the hole. This is normal and should be expected. The difference should be equal to the difference

between the RKB to Mud Line Length and the Choke Line Length.

Choke Line Friction:

This section is provided to record the most recent choke line friction

measurements. Refer to Section M on Subsea Well Control Procedures later in this volume for more

information.

Riser Capacity: Use this section to record the riser capacity.

6. EXAMPLE PRERECORDED DATA SHEET

The following pages contain two prerecorded data sheets that have been completed for a surface and

a subsea well. The raw information used to complete the data sheets is provided above each one.

On bottom drilling depths are also provided.

Rev. 12/94

F-5


VOLUME ELEVEN


SURFACE WELL

Well Depth - 9000'MD/TVD

2-duplex pumps - 16-in. stroke, 3-in. rod, 96% vol. eff.,

6-1/4-in. liner.

Casing size - 10-3/4 in., set at 4000 ft.

Drill collar size - 7 in. OD x 2-13/16 in. ID x 450 ft long.

Mud weight - 10 lb/gal

Active surface mud system - 450 bbls before kick; 200 bbl at

start of kill operation.

Hole size - 9-7/8 in.

Casing pressure limitation - 2864 psi (80% burst)

Remaining collapse resistance of drill pipe- 4109 psi

PRERECORDED WELL DATA

KEEP THIS DATA SHEET CURRENT AT ALL TIMES

(use the Tab key to advance to next required input)

Well Name

OCSG 0544 #5

Field

E. Cam. 160

Rig

DIGGER #4

Hole Data:

Size(avg)

9.8750

Hole MD

9,000

ft.

Hole TVD

9,000

ft.

Hole Capacity: no pipe in hole

0.0948

bbls/ft x

9,000

ft. =

852.9

bbl

(from BOP to MD)

*Use

DP

PUMP DATA:

Liners (in.) Stroke(in.)

Rod(in. )

% Eff.

bbl./stk For Kill?

CSG

No. 1

No. 2

CASING (LAST SET) DATA:

* X if used, empty if not

10.7500

by

9.8750

Shoe MD

4,000

Shoe TVD

4,000

(in. OD) (in. Avg ID)

WELLHEAD OR CASING PRESSURE LIMITATION:

(feet)

(feet)

The lessor of: 100% BOP Rating

10,000

psi.

100% Wellhead Rating

80% Casing Burst

5,000

2,864

psi.

psi.

Limitation =

2,864

psi.

LINER CASING DATA:

by

Top @

ft. Shoe @

(in. OD)

DRILL STRING DATA:

(in. Avg ID)

(feet)

(feet)

DRILL COLLARS

Drill Pipe

5.0000

in. (OD)

19.5

lb./ft.

OD(in.) ID(in.)

Drill Pipe

HW Drill Pipe

in. (OD)

in. (OD)

lb./ft.

lb./ft.

7

by

by

2.8125

INTERNAL CAPACITIES:

Drill Pipe 8,550

Drill Pipe

HW Drill Pipe

ft.

ft.

ft.

x

x

x

0.0178

bbl./ft. =

bbl./ft. =

bbl./ft. =

152.1

bbl.

bbl.

bbl.

Drill Collars

450

ft.

x

0.0077

bbl./ft. =

3.5

bbl.

Drill Collars

ft.

x

bbl./ft. =

bbl.

M. Depth(Bit)

9,000

ft.

Total Internal = 155.6

bbl. =

905

Strokes

ANNULUS CAPACITIES:

(Note: Use other side for subsea)

DP x Csg. 4,000

or Hole 4,550

HW DP

DC x Hole 450

DC x Hole

ft. x 0.0704 bbl./ft. =

ft. x 0.0704 bbl./ft. =

ft. x bbl./ft. =

ft. x 0.0471 bbl./ft. =

ft. x bbl./ft. =

281.8

320.5

21.2

bbl.

bbl.

bbl.

bbl.

bbl.

M. Depth(Bit)

9,000

ft.

Total Annulus

623.5

bbl. =

3,626

Strokes

System Volume =

779.1

bbl.

=

4,530

Strokes

(Internal + Annulus)

Active Pit Volume

MAX INITIAL SICP TO FRACTURE FORMATION AT SHOE:

Max. SICP = (Shoe Test - Present Mud Wt.) x 0.052 x Shoe TVD

200

bbl.

(

13.5

lb./gal EMW -

10.0

lb./gal) x 0.052 x

4,000

ft. =

728

psi.

Version 1.3 (8/1/94)

Rev 12/94

F-6


VOLUME ELEVEN


SUBSEA WELL

Well Depth - 8200' MD, 7500' TVD

Water Depth - 1930'

Casing Size - 9-5/8", 53.5#, S-95 (assume 8-1/2" average ID)

Hole Size - 8-1/2"

Shoe Test - 17.3 ppg

Drillpipe Size - 4-1/2", 20.0 #, S-135 XH

Drill Collar Size - 6" x 2-1/4", 360' long

Mud Weight - 12.0 ppg

Pumps - 2 Triplex, 15" stroke, 5" liners, 95% eff.

Choke Line - 3" ID, 2100' long

Subsea Wellhead - 18-3/4", 15M

Riser ID - 18-3/4"

Active Pit Capacity - 680 Bbls

RKB to Mudline - 2010'

Heavy Weight DP Size - 4-1/2", 41.5 #, 990' long




Well Name

Boots #1

Field

DeeTee "C"

Rig

TMB #713

Hole Data:

Size(avg)

8.5000

Hole MD

8,200

ft.

Hole TVD

7,500

ft.


0.0702

bbls/ft x

6,190

ft. =

434.6

bbl

(from BOP to MD)

*Use

DP

PUMP DATA:


Rod(in. )

% Eff.

bbl./stk For Kill?

CSG

No. 1

No. 2



9.6250

by

8.5000

Shoe MD

7,200

Shoe TVD

6,500



(feet)

(feet)


10,000

psi.


80% Casing Burst

10,000

7,528

psi.

psi.

Limitation =

7,528

psi.

LINER CASING DATA:

by

Top @

ft. Shoe @

(in. OD)

DRILL STRING DATA:

(in. Avg ID)

(feet)

(feet)

DRILL COLLARS

Drill Pipe

4.5000

in. (OD)

20

lb./ft.

OD(in.) ID(in.)

Drill Pipe

HW Drill Pipe 4.5000

in. (OD)

in. (OD)

41.5

lb./ft.

lb./ft.

6

by

by

2.2500


Drill Pipe 6,850

Drill Pipe

HW Drill Pipe 990

ft.

ft.

ft.

x

x

x

0.0130

0.0074

bbl./ft. =

bbl./ft. =

bbl./ft. =

89.1

7.3

bbl.

bbl.

bbl.

Drill Collars

360

ft.

x

0.0049

bbl./ft. =

1.8

bbl.

Drill Collars

ft.

x

bbl./ft. =

bbl.

M. Depth(Bit)

8,200

ft.

Total Internal =

98.2

bbl. =

1,135

Strokes

ANNULUS CAPACITIES:

(Note: Use other side

for subsea)

DP x Csg. 6,850

or Hole

HW DP 990

DC x Hole 360

DC x Hole

ft. x 0.0505

ft. x 0.0505

ft. x 0.0505

ft. x 0.0352

ft. x

bbl./ft. =

bbl./ft. =

bbl./ft. =

bbl./ft. =

bbl./ft. =

346.0

50.0

12.7

bbl.

bbl.

bbl.

bbl.

bbl.

M. Depth(Bit)

8,200

ft.

Total Annulus

408.7

bbl. =

4,722

Strokes

System Volume =

506.9

bbl.

=

5,857

Strokes


Active Pit Volume



200

bbl.

(

17.3

lb./gal EMW -

12.0

lb./gal) x 0.052 x

6,500

ft. =

1,791

psi.

Version 1.3 (8/1/94)

Rev. 12/94

F-7


VOLUME ELEVEN


PRERECORDED WELL DATA (page 2)

(SUBSEA USE ONLY)


(from other side)

DP

Csg

Total Internal Capacity

98.2

bbl. =

1,135

strokes

choke

kill line

ANNULUS CAPACITIES:

(replaces other side)

Choke Line

2,100

ft.

x

0.0087

bbl./ft. =

18.3

bbl.

RKB to ML

2,010

ft.

DP x Csg.

or Hole

4,840

ft.

ft.

x

x

0.0505

0.0505

bbl./ft.

bbl./ft.

=

=

244.5

bbl.

bbl.

annul

HWDP x Hole

DC x Hole

990

360

ft.

ft.

x

x

0.0505

0.0352

bbl./ft.

bbl./ft.

=

=

50.0

12.7

bbl.

bbl.

DC x Hole

ft.

x

bbl./ft.

=

bbl.

connec

annul

M. Depth(Bit)

8,200

ft.

blind/sh

Total Annulus =

325.4

bbl. =

3,760

strokes

pipe

System Volume =

423.6

bbl. =

4,895

strokes

pipe

pipe

connec

mud


RISER CAPACITY:

(with no pipe in the hole)

Riser ID

Capacity Fact.

Length

Capacity

18.7500

inches

0.3417

bbl./ft. x

2,010

ft.

=

686.7 bbls.

inches

bbl./ft. x

Total Riser = 686.7

bbl. =

ft.

=

7,934

strokes

bbls.

Notes:

1. Use slow pump rate through riser for calculations on Engineers Method worksheet

2. All barite requirements and system volume calculations exclude riser capacity.

3. If monitoring static Kill Line pressure while adjusting pump rate, ignore Choke

Line Friction.

CHOKE LINE FRICTION:

Choke Line Change in

SPM

BPM

Psys(Riser)Psys(Choke) Friction Choke Friction

Rev 12/94

F-8


VOLUME ELEVEN


SECTION G: DRILLER'S METHOD

1. 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 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.


(1) SPACE OUT

(2) SHUT DOWN

(3) SHUT-IN

(1) STAB VALVE

(2) SPACE OUT

(3) SHUT-IN

Pull the kelly out of the hole. Position the kelly so that the tool joints

are clear of the preventers.

Stop the mud pumps.

Close the annular preventer or uppermost pipe ram preventer.

Confirm that the well is shut-in and flow has stopped.


Install the fully opened safety valve in the drillstring. Close the

safety valve.

Position the drillstring so that the tool joints are clear of the

preventers.


Confirm that the well is shut-in and flow has stopped.

It should be emphasized that in nearly all well kicks, the Driller will be responsible for closing

the preventers and shutting the well in. The Driller must have the experience and the initiative

to do this by himself if he is working alone. It is the responsibility of the Chevron Drilling

Representative to make sure that the Driller knows the proper shut-in procedure. The Driller will

have 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 the well in.

Rev 12/94

G-1


VOLUME ELEVEN


Step 2a - Allow The Well To Stabilize, Record Pressures 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, it should be possible to 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, the float will have to be

"bumped" open by slowly pumping down the drillpipe. The correct procedure for bumping the

float is given below.


(1)

(2)

(3)

(4)

(5)

(6)



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 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 recorded 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.

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 bursts 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.

Rev. 12/94

G-2


VOLUME ELEVEN


If excess pressure is trapped on the

drillpipe when bumping the float ...

Shut-in

Shut-in drillpipe

Increase in shut-in

Drillpipe

Pressure

= pressure after

bumping float

-

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 that must be kept in mind while performing 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 gas 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.

Step 4 - Establish Circulation

After the kick control calculations have been performed, 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.

Be sure that every member of the crew knows exactly what his duties are before the

kill operation begins. (See Section O in this manual 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.

Rev 12/94

G-3


VOLUME ELEVEN


3.

4.

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, back pressure on the well is

very difficult to control. This procedure is critical since additional influx will result if too little back

pressure is held, or the formation can breakdown if too much back pressure 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 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.

A 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 drillpipe pressure. If the choke is adjusted to bring the drillpipe 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 if the choke is adjusted to increase the drillpipe pressure, it may create 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 must be 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. (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 prerecorded 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 drillpipe 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 drillpipe 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 new 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

Rev. 12/94

G-4


VOLUME ELEVEN


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 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)

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 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 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 in 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 the 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 the Prerecorded Well Data

Sheet. The casing pressure should drop to zero as the light weight mud is displaced from the

annulus.

Rev 12/94

G-5


VOLUME ELEVEN


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.

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.

To prepare for a trip after conditioning the mud, raise the mud weight to provide a suitable "trip

margin," as determined by the DRILPRO Swab/Surge calculations.

2. USING THE DRILLER'S METHOD WORKSHEET

The Driller's Method Worksheet is a step-by-step instruction sheet to help the Drilling Representative

calculate the critical well control parameters that are necessary to successfully kill a well using the

Driller's Method. Use of the Worksheet is demonstrated below with an example problem.

Sample Problem - A well is being drilled, and the following data are known prior to a kick:

2-duplex pumps - 16-in. stroke, 3-in. rod, 96% vol. eff., 6-1/4-in. liner.

Casing size - 10-3/4 in, set at 4000 ft.

Hole size - 9-7/8 in.

Casing pressure limitation - 2864 psi (burst)

Shoe Test: 720 psi with 10 lb/gal mud

Drill pipe size - 5 in., 19.5 lb/ft (20.7 lb/ft w/tool joints).

Remaining collapse resistance of drill pipe - 3885 psi

Drill collar size - 7 in. OD x 2-13/16 in. ID x 450 ft long.

Mud weight - 10 lb/gal.

Active surface mud system - 450 bbls, before kick; 200 bbls at start of kill operation.

Slow Pump Rate Data:

Strokes/min

20

30

PSI

280

590

Rev. 12/94

G-6


VOLUME ELEVEN


While drilling at 9000' TVD, the well kicked and the BOP's were closed. The following data was

observed:

Initial drill pipe pressure = 470 psi.

Initial casing pressure = 600 psi.

Pit volume gain = 15 bbl.

The following pages describe a step-by-step procedure for determining the well control

parameters which are necessary to kill the well in the example problem using the Driller's

Method.

Step 1 - Prerecorded 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, including:

Old Mud Weight

Initial Shut-in Drill Pipe Pressure

Initial Shut-in Casing Pressure

Pit Volume Increase

True Vertical Depth Of Hole

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 it is established.

Space is provided on the Driller's Method Worksheet to record the circulating drillpipe pressure

which is observed after the pumps are operating at a 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.

Rev 12/94

G-7


VOLUME ELEVEN


NOTE: For added peace of mind during the kill operation, it's 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.

The initial circulating pressure should be approximately 590 + 470 = 1060 psi.

Jot down this value down 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).

Step 4 - Determining Mud Weight To Balance The Kick

Using the equation below, calculate the increase in mud weight necessary to balance the kick.

Initial Shut-in Drillpipe Pressure

Increase in Mud Weight = -------------------------------------------------------

0.052 X True Vertical Depth

470

=

=

--------------------------- = 1.0043

0.052 X 9000

1.0 lb/gal

Rounding-Up Rule: The increase in mud weight should be calculated to the hundredths place.

If the number in the hundredths place is greater than zero, then round the number in the tenths

place up one full tenth. In this example, the number in the hundredths place is zero, so the

number in the tenths place is not rounded-off.

Record a 1.0 lb/gal 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

= 10.0 + 1.0

= 11.0 lb/gal

Enter the new mud weight in part "H" of the worksheet.

Rev. 12/94

G-8


VOLUME ELEVEN


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.

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 200 bbls of active pit volume with 779 bbls of system volume for a total volume

of 979 bbls. to weight-up. Record this value on part "I" of the Worksheet.

Step 6 -Barite Required To Weight-Up

Its an easy matter to determine the amount of barite that will be required once the total volume

to weight-up is known. Use the following formula and record the value at "J".

15.0 X Increase In Mud Weight

Barite Required = Total Volume to Weight-up x ----------------------------------------------

35.0 - New Mud Weight

15.0 x 1.0

= 979 x -------------------

35.0 - 11.0

= 612 sacks

Step 7 - Determining Pressures For The Second Circulation

Remember, when using the Driller's Method circulating pressures aren't calculated, but are self-

determined. This means that the pressures observed on the gauges are the pressures that are

held constant while circulating. The values recorded on the Driller's Method Worksheet for the

casing and drillpipe pressures should be observed values.

On the Driller's Method Worksheet, 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, another kick could be in the hole and it may be necessary to 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 until the kill mud reaches the bit. Record the drillstring

internal capacity (in strokes) on the Worksheet to determine when kill mud will reach the bit.

Rev 12/94

G-9


VOLUME ELEVEN


As soon as the kill mud reaches the bit, attention 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 must be written in the appropriate space on the

Driller's Method Worksheet.

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 0.052 x True Vertical Depth

= 11.0 x 0.052 x 9000

= 5148 psi

Record this value on the back of the Worksheet.

Step 9 - Determining Equivalent Bottomhole Gas Bubble Height

This is the height of the gas bubble at the bottom of the hole with 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 the height on the Worksheet.

Initial Pit Volume Increase

Gas Bubble Height = -----------------------------------------------------------

Annulus Capacity Factor (D.P. x Hole)

15 bbl

= -----------------------

0.0704 bbl/ft

=

213 feet

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. This value must be calculated before its arrival to determine if the wellhead and casing

can withstand the pressure. The mathematical formula used to determine the maximum casing

pressure is shown in sections ) and Q. To simplify the calculation of maximum casing pressure

for those who do not want to use the formula, charts have been developed that are included in

Section P of this manual. The maximum casing pressure (Pc Max) is calculated in two steps.

An equation is used to calculate Part 1, and either the equation or a chart is used to calculate

Part 2.

Rev. 12/94

G-10


VOLUME ELEVEN


Pc Max - Part 1: The first part of Pc Max is determined with the following simple formula:

Shut-in Drillpipe Pressure

Pc Max - Part 1, Driller's Method = ------------------------------------

2

For our example, Pc max part 1 is therefore equal to:

470

Pc Max - Part 1, Driller's Method = -------- = 235 psi

2

Pc Max - Part 2: Pc Max - Part 2 is calculated using the equations in sections P and Q or it can

be obtained from charts. Both "low pressure" and "high pressure" charts are provided to

calculate Pc Max Part 2. Figure P.1a is designed for use with "low pressure" wells, whereas

Figure P.1b is more suitable for high pressure wells. On either chart, enter the upper left vertical

axis at the original mud weight (10 lb/gal). Read across to an imaginary line for the reservoir

pressure (5,148 psi); then drop vertically to the line matching the equivalent bottom hole gas

bubble height (213 ft). Run a horizontal line to the curve for the PcMax-I value calculated earlier;

then run a vertical line up to the PcMax-II axis and read 720 psi. Record this value at "Q" on the

worksheet. Add "O" and "Q" to determine "R", the maximum surface casing pressure (955 psi).

Generally speaking, the casing pressure is significant only if it should exceed the pressure rating

of the casing, wellhead or BOP's. It is seldom possible to accurately calculate 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 on whether to circulate the formation fluid out of the hole or not.

Step 11 - Determining Volume Gain For A Gas Kic k

In part "T" an equation or a convenient chart can be used to determine the maximum pit volume

gain which will occur if the kick is completely gas. To use a chart, if the value for Pc max

calculated above is less than 1,000 psi, then figure P4.a should be used, else if Pc max is greater

than 1,000 psi, use Figure P.4b. On either chart, enter the left vertical axis at the maximum

surface casing pressure (955 psi). Read across to the reservoir pressure (5,148 psi), then down

to the original kick volume (15 bbl). Read across to the right vertical axis to obtain the volume

of gas at the surface (62 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 (47 bbl). Record this value at "U".

Rev 12/94

G-11


VOLUME ELEVEN


Step 12 - Determining Maximum Casing Pressure And Excess Volume

Subtract the volume of gas at the surface "T," from the annulus capacity on the Prerecorded

Well Data Sheet. This will show approximately when the maximum casing pressure and

excess volume will occur. (623 - 62 = 561 bbl, 3264 strokes.) Record these values in the

proper spaces provided.

The following pages provide completed examples of the Worksheets and Figures described

previously, including:

• The Driller's Method Worksheet

• Figure P.1a (Pc Max Part 2)

• Figure P.4 a (Volume Gain)

Rev. 12/94

G-12


VOLUME ELEVEN


DRILLER'S METHOD WORKSHEET


PRERECORDED INFORMATION

SPM psi

bbl/stk

bbl/min

A. Slow Pump Rate Data Pump #1

( Use SPR Pressure through Riser for Subsea ) Pump #2

INFORMATION RECORDED WHEN WELL KICKS

Time of Kick:

1:30

B.

C.

D.

E.

F.

Old Mud W eight

Initial Shut-In Drill Pipe Pressure (SIDP)

Initial Shut-In Casing Pressure (SICP)


True Vertical Depth of Hole

Measured Depth of Hole (for Capacity Calculations ONLY)

B

C

D

E

F

10.0

470

600

15

9,000

9,000

lb/gal

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}

Read and Record Initial Circulating Pressure on Drill Pipe

[Should Approximately = Slow Pump Rate Pressure (A) + SIDP (C)]

Maintain Constant DP Pressure Until Influx is Circulated Out. Then Shut Down

Pumps W hile 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

30

1060

SPM

psi

G

Initial SIDP

0.052 TVD

C

0.052 F

G

1.0

lb/gal

H. New Mud Weight

I. Total Volume to W eight up

J. Barite Required

H=B+G=

I = Active Pit Vol + System Vol =

J I

H

I

J

11.0

979

612

lb/gal

bbl

sacks

SECOND CIRCULATION TO BALANCE WELL

Bring Pumps up to Speed While Holding

Casing Pressure Constant. {Account for

≈ SIDP (C)

Casing Pressure

470

psi

CLF if Subsea} Maintain Constant Casing

Pressure Until New Mud Reaches the Bit.

Drill String Internal Capacity

905

strokes

Read and Record Drill Pipe Pressure

When New Mud Reaches the Bit

≈ SPRP ( A )

KWM ( H )

Old MW (B )

Final Circulating Pressure

649

psi

Maintain Constant Drill Pipe Pressure

Until the System is Displaced.

System Volume

4,530

strokes

Version 1.3 (8/1/94)

Rev 12/94

G-13


VOLUME ELEVEN


DRILLER'S METHOD WORKSHEET

RESERVOIR PRESSURE (Pr)

(page 2)

K . Pr

0 . 052

New MW

TVD

0 . 052

H

F

K

5148

psi

HEIGHT OF GAS BUBBLE AROUND DRILL PIPE (KH)

L. Annulus Capacity Factor (DP x Casing) Right Below Wellhead

L

0.0704

bbls/ft

M. Height

=

Initial Pit Vol Increase

Annulus Capacity Factor

(E )

( L )

M

213

ft.

MAXIMUM CASING PRESSURE (Pcmax) WHEN GAS GETS TO SURFACE

N. Grad = Mud W eight Gradient

MW (B) 0.052 =

N

0.52

psi/ft.

O.

Pc

max

Part 1 = SIDP

2 = ( C ) 2 =

(Surface) O

235

psi

(Optional Correction for Subsea Wells)

O. (Subsea) A correction must be added to Pcmax, Part1 calculated above to

account for the choke line.

(Subsea) O = Subsea Correction + (Surface) O =

Vol . Choke Line

Subsea Correction = ( ft ) -

L

(bbl )

(Subsea) O

2

0

psi

(use this new O for Part Q. and Part R. below)

P. TZ= Compressibility and Temperature Effects (fig 11P.5)

or Tz = 4.03 - (0. 38 ln(Pr)) = 4.03 - (0. 38 ln(K ))

Q. Pcmax, Part2 (figure 11P.1)

P

0.78

=

( O )

2

( K )( M )( N )( P )

Q

708

psi

R. Maximum Casing Pressure,

Pc MAX = (Pc MAX , Part 1 ) + (Pc MAX , Part 2) = O + Q =

R

943

psi

S. Does Pcmax Exceed the Wellhead or Casing Pressure Limitation?

YES

VOLUME GAIN WHILE CIRCULATING OUT GAS BUBBLE

T. Volume of Gas at Surface (from Fig. 11P.4 or Formula below)

NO

X

Vg , Volume of gas at surface

, bbl

E K P

R

T

64

bbl

U. Volume Gain While Circulating Out Gas Kick

U T− E

U

49

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

559

strokes

3253

A

l

C

{

d d} T

Rev. 12/94

G-14


VOLUME ELEVEN


(Ref. 11P-16 to 18, Symbols and Equations)

Rev 12/94

G-15


VOLUME ELEVEN



Rev. 12/94

G-16


VOLUME ELEVEN


SECTION H: ENGINEER'S 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, shown below.


(1)

(2)

SPACE OUT Pull the kelly out of the hole. Position the kelly so that the tool

joints are clear of the preventer stack.

SHUT DOWN Stop the mud pumps.

(3)

SHUT-IN


Confirm that the well is shut-in and the flow has stopped.


(1)

(2)

STAB VALVE Install the fully opened safety valve in the drillstring. Close the

safety valve.

SPACE OUT Position the drillstring so that the tool joints are clear of the

preventer stack.

(3)

SHUT-IN


Confirm that the well is shut-in and the flow has stopped.

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 Chevron Drilling Representative 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 the

well in.

Rev 12/94

H-1


VOLUME ELEVEN


Step 2a - Allow The Well To Stabilize, Record Pressures 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 lined-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 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.


(1)

(2)

(3)

(4)

(5)

(6)



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 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.

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 bursts 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.

Rev 12/94

H-2


VOLUME ELEVEN


If excess pressure is trapped on the

drillpipe when bumping the float ...

Shut-in

Shut-in drillpipe

Increase in shut-in

Drillpipe

Pressure

= pressure after

bumping float

-

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 casing 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 exceeds barite on hand, either further reduce the

volume in the active system or proceed with the Driller’s Method. The mud mixing facilities and pit

volumes on a 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.

Rev 12/94

H-3


VOLUME ELEVEN


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) Be sure that all members of the crew knows exactly what their duties are before the

kill operation begins. (See Section O, "Training and Well Control Drills," for more

detail.)

(2) 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.

(3) Make sure the circulating system (including manifolds and pits) are lined-up

correctly.

(4) Zero the stroke counter and make a note of the time.

When establishing circulation in a well closed in under pressure, back pressure on the well is very

difficult to control. The procedure is critical, since additional influx will result if too little back pressure

is held, and the formation can break down if too much back pressure 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.

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

should be 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 bottomhole 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

Rev 12/94

H-4


VOLUME ELEVEN


displaced with kill mud. When an influx rises above the drill collars and 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 pressure is being maintained by following the drillpipe profile, it's 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 drill pipe 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 easily turn a good job into a disaster.

It can sometimes be difficult to bleed the gas off fast enough to keep the drillpipe 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's 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 pump 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 prerecorded 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 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.

Rev 12/94

H-5


VOLUME ELEVEN


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.

After the mud has been conditioned and the yield point reduced, if a trip is made, it may be necessary

to raise the mud weight slightly to provide a suitable "trip margin". This can be determined with the

DRILPRO Swab/Surge calculations.

2. USING THE ENGINEER'S METHOD WORKSHEET

The Engineer's Method Worksheet is a step-by-step instruction sheet to help the Drilling Represen-

tative 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 a kick:

2-duplex pumps - 16-in. stroke, 3-in. rod, 96% vol.. eff., 6-1/4-in. liner.

Casing size - 10-3/4 in., set at 4,000 ft. Hole size - 9-7/8 in.

Casing pressure limitation - 2,864 psi (burst)

Shoe Test - 720 psi with 10 lb/gal. mud

Drill pipe size - 5 in., 19.5 lb/ft. (20.7 lb/ft. w/tool joints).

Remaining collapse resistance of drill pipe - 4,109 psi

Drill collar size - 7 in. OD x 2-13/16 in. ID x 450 ft. long.

Mud weight - 10 lb./gal.

Active surface mud system - 450 bbl. before kick; 200 bbl. at start of kill operation.

Slow pump rate data:

Strokes/min.

20

30

PSI

280

590

While drilling at 9,000 ft. TVD, the well kicked and the BOP's were closed.

The following data was observed.

Initial drill pipe pressure = 470 psi.

Initial casing pressure = 600 psi.

Pit volume gain = 15 bbl.

Following is a step-by-step procedure for determining the well control parameters which are

necessary to kill the example well using the Engineer's Method.

Rev 12/94

H-6


VOLUME ELEVEN


Engineer's Method Worksheet

Step 1 - Prerecorded Information

Prior to the kick (and at all times), a Prerecorded Data Sheet should be completely filled out except

for the measured depth and the length of drillpipe in the hole. After entering these items, 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 Engineer'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

Initial Shut-in Drill Pipe Pressure

Initial Shut-in Casing Pressure

Pit Volume Increase

True Vertical Depth Of Hole

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.

Initial Shut-in Drillpipe Pressure

Increase in Mud Weight = -------------------------------------------------------

0.052 X True Vertical Depth

470

= ------------------------ = 1.0043

0.052 X 9000

Therefore,

Increase in Mud Weight = 1.0 lb./gal

Rounding-Up Rule: The increase in mud weight should be calculated to the hundredths place. If

the number in the hundredths place is greater than zero, then round up the number in the tenths place

one full tenth. In this example, the number in the hundredths place is zero, so the number in the tenths

place is not rounded up.

Record a 1.0 lb/gal 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.

Rev 12/94

H-7


VOLUME ELEVEN


New Mud Weight To Balance The Kick = Old Mud Weight + Increase In Mud Weight

= 10.0 + 1.0

= 11.0 lb/gal

Enter the new mud weight in part "H" of the worksheet.

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 the volume of mud in surface pits

should be reduced before weighting up. Again, some of these reasons are:

(1) It takes less time to weight up less volume.

(2) It requires less barite to weight up less volume.

(3) While circulating the influx out, the pits may overflow.

Whatever the reason, decide on the volume to use and add it to the system volume from the

Prerecorded Data Sheet to determine the total volume to weight up. In our example, we again used

200 bbl. to arrive at a total volume to weight up of 979 bbl. 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:

15.0 x Increase in Mud Weight

Barite Required =Total Volume to Weight Up x -----------------------------------------------

35.0 - New Mud Weight

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

In this example, 30 SPM was selected. Therefore, the initial circulating pressure will be 590 + 470 =

1060 psi. Record this value at "K."

Rev 12/94

H-8


VOLUME ELEVEN


NOTE: If for some reason the prerecorded circulating pressures at various rates are unavailable,

the initial drillpipe circulating pressure can be determined by proceeding as follows: a) hold the casing

pressure constant until the pump is at the desired speed, b) read the drillpipe pressure at that time.

This pressure minus the initial shut-in drillpipe pressure will be the reduced circulating pressure at

the desired speed and would be used to calculate the final circulating drillpipe pressure.

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 estimated by the formula:

New Mud Weight

Final Circulating Pressure = Slow Pump Rate Pressure X --------------------------------

Old Mud Weight

11

= 590 X -----

= 649 psi

10

Step 8 - Drillpipe Pressure Schedule

Successful well killing with the Engineer's Method requires that the drillpipe pressure decrease from

a higher value (the Initial Circulating Pressure) to a lower value (the 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 a 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 Representative

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 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 Prerecorded Data Sheet to lines "M" and "N" on the Engineer's Method

Worksheet.

Next, record the calculated Initial Circulating Pressure, "K", on the top/right side of the schedule table

and record zero strokes on the left-side.

Next, record the 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).

Rev 12/94

H-9


VOLUME ELEVEN


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:

Initial Circulating Pressure - Final Circulating Pressure

Drillpipe Pressure Drop = ----------------------------------------------------------------------------------

(per stroke) Total Internal Stroke Capacity

1060 - 649

= -----------------

905

= 0.45 psi/stroke

This equation will normally yield a fraction of a psi reduction per pump stroke, which is too small to

accurately measure on the rig. Therefore, we arbitrarily choose a stroke increment of 100 strokes,

which becomes our point of reference as kill mud is pumped down the drillpipe. Instead of reducing

the drillpipe pressure 0.45 psi per stroke, we reduce it 45 psi per 100 strokes (which is essentially

the same thing).

We can then subtract this pressure decline (45 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.

Step 9 - 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 0.052 X True Vertical Depth

= 11.0 X 0.052 X 9000

= 5148 psi

Record this value on the back of the Worksheet.

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 can calculate this value before the kick arrives at surface to determine if the wellhead and casing

can withstand the pressure. Mathematical formulas used to determine the maximum casing pressure

are used in parts "U" and "V" of the Killsheet. For those who do not wish to make this calculation, charts

Rev 12/94

H-10


VOLUME ELEVEN


have been developed and are included in the back of this section and in Section P. The maximum

casing pressure (Pc Max) is calculated in two steps, so two charts are required.

Pc max part 1: On Figure P.2, enter the left vertical axis at the total internal drillpipe capacity (156

Bbl.), and read across to the line for the drillpipe x hole annulus capacity factor (0.0704 bbl./ft.). Drop

a vertical line to the increase in mud weight (1.0 lb/gal), then read across to the right vertical axis to

find Pc max part 1(60 psi). Record this figure at "U".

Pc max part 2: On Figure P.3, begin at the upper horizontal axis, at the new mud weight (11.0 lb/

gal). Drop a vertical line to the reservoir pressure curves at 5,150 psi, then run a horizontal line to

the curve corresponding the original kick volume (15 bbl). Drop another vertical line to the drillpipe

x hole annulus capacity factor (0.0704 Bbl/ft.), then run a horizontal line to the right vertical axis, Pc

max part 2. Record this value (690 psi) at "V" on the worksheet.

To determine the maximum surface casing pressure while properly circulating out a pure gas kick

(Pc Max) simply add "U" and "V" to obtain 750 psi. Record this value at "W". The next question is

very important and its answer may determine the course of action that will be taken for the kill. In most

cases, it can 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, wellhead 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. Water or oil will decrease the casing pressure and volume gain from those shown on the

worksheet.

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.

Step 11 - Determining Pit Volume Gain For A Gas Kic k

The volume of the gas at surface is calculated in part "X". Again for those who do not wish to make

this calculation, a convenient chart is also provided to determine the maximum pit volume gain which

will occur if the kick is completely gas. If the value for Pc max that was calculated above is less than

1,000 psi, then use Figure P.4a to calculate the volume gained. If Pc max is greater than 1000 psi,

use Figure P.4b. On either chart, enter the left vertical axis at the maximum surface casing pressure

(750 psi). Read across to the reservoir pressure (5,150 psi), then down to the original kick volume

(15 bbl). Read across to the right vertical axis to obtain the volume of gas at the surface (78 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 (60 bbl). Record

this 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 15 sacks of barite per bbl of additional

volume increase. Record this figure at part "Z". The total volume gain while circulating out a gas kick

is calculated by adding part "Y" to part "Z". Record this value.

Rev 12/94

H-11


VOLUME ELEVEN


Step 12 - Determining When Maximum Casing Pressure And Excess Volume Will 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 (624 - 79 = 544 bbl, or 3,163 strokes).

Record these values in the proper spaces provided.

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:

1.

2.

3.

4.

5.

The Prerecorded Data Sheet

The Engineer's Method Worksheet

Figure P.2 (Pc Max part 1)

Figure P.3 (Pc Max part 2)

Figure P.4 (Volume Gain)

Rev 12/94

H-12


VOLUME ELEVEN





Well Name

OCSG 0544 #5

Field

E. Cam. 160

Rig

DIGGER #4

Hole Data:

Size(avg)

9.8750

Hole MD

9,000

ft.

Hole TVD

9,000

ft.


0.0948

bbls/ft x

9,000

ft. =

852.9

bbl

(from BOP to MD)

*Use

DP

PUMP DATA:


Rod(in. )

% Eff.

bbl./stk For Kill?

CSG

No. 1

No. 2



10.7500

by

9.8750

Shoe MD

4,000

Shoe TVD

4,000



(feet)

(feet)


10,000

psi.


80% Casing Burst

5,000

2,864

psi.

psi.

Limitation =

2,864

psi.

LINER CASING DATA:

by

Top @

ft. Shoe @

(in. OD)

DRILL STRING DATA:

(in. Avg ID)

(feet)

(feet)

DRILL COLLARS

Drill Pipe

5.0000

in. (OD)

19.5

lb./ft.

OD(in.) ID(in.)

Drill Pipe

HW Drill Pipe

in. (OD)

in. (OD)

lb./ft.

lb./ft.

7

by

by

2.8125


Drill Pipe 8,550

Drill Pipe

HW Drill Pipe

ft.

ft.

ft.

x

x

x

0.0178

bbl./ft. =

bbl./ft. =

bbl./ft. =

152.1

bbl.

bbl.

bbl.

Drill Collars

450

ft.

x

0.0077

bbl./ft. =

3.5

bbl.

Drill Collars

ft.

x

bbl./ft. =

bbl.

M. Depth(Bit)

9,000

ft.

Total Internal = 155.6

bbl. =

905

Strokes

ANNULUS CAPACITIES:

(Note: Use other side

for subsea)

DP x Csg. 4,000

or Hole 4,550

HW DP

DC x Hole 450

DC x Hole

ft. x 0.0704

ft. x 0.0704

ft. x

ft. x 0.0471

ft. x

bbl./ft. =

bbl./ft. =

bbl./ft. =

bbl./ft. =

bbl./ft. =

281.8

320.5

21.2

bbl.

bbl.

bbl.

bbl.

bbl.

M. Depth(Bit)

9,000

ft.

Total Annulus

623.5

bbl. =

3,626

Strokes

System Volume =

779.1

bbl.

=

4,530

Strokes


Active Pit Volume



200

bbl.

(

13.5

lb./gal EMW -

10.0

lb./gal) x 0.052 x

4,000

ft. =

728

psi.

Version 1.3 (8/1/94)

Rev 12/94

H-13


VOLUME ELEVEN


ENGINEER'S METHOD WORKSHEET


PRERECORDED INFORMATION

SPM

psi

bbl/stk

bbl/min

A. Slow Pump Rate Data

( Use SPR Pressure thru Riser for Subsea )

Pump #1

Pump #2

INFORMATION RECORDED WHEN WELL KICKS

Time of Kick:

1:30

B.

C.

D.

E.

F.

Old Mud Weight

Initial Shut-In Drill Pipe Pressure (SIDP)

Initial Shut-In Casing Pressure (SICP)


True Vertical Depth of Hole

Measured Depth of Hole (for Capacity Calculations ONLY)

B

C

D

E

F

10.0

470

600

15

9000

9000

lb/gal

psi

psi

bbl

ft (TVD)

ft (MD)

MUD WEIGHT TO BALANCE KICK

G. Increase in Mud Weight required to Balance Kick

G

Initial SIDP

0.052 TVD

C

0.052 F

G

1.0

lb/gal

H. New Mud W eight

I. Total Volume to Weight up

H=B+G=

I = Active Pit Vol + System Vol =

H

I

11.0

979

lb/gal

bbl

J. Barite Required

J I

35.0− H

J

612

sacks

INITIAL CIRCULATING PRESSURE

K. Slow Pump Rate Pressure + SIDP

K =A+C=

K

1060

psi

FINAL CIRCULATING PRESSURE

L. Slow Pump Rate Pressure X (New Mud Wt / Old Mud Wt)

L A

H

B

L

649

psi

DRILL PIPE PRESSURE PROFILE

strokes

M. Total Internal Capacity (from Prerecorded W ell Data)

M

905

N. Total Annulus Capacity (from Prerecorded W ell Data)

O. System Volume (from Prerecorded Well Data)

N

O

3626

4530

624

bbl

Pressure Decline

Internal Capacity Strokes (M)

Strokes

Pressure (psi)

0

100

200

300

400

500

600

700

800

900

1060

1015

969

924

878

833

787

742

697

651

= Initial Circ Press (K)

Total Internal Cap (M) =

905

649

= Final Circ Press (L)

Version 1.3 (8/1/94)

Rev 12/94

H-14


VOLUME ELEVEN


ENGINEER'S METHOD WORKSHEET

RESERVOIR PRESSURE (Pr)

(page 2)

P. Pr 0.052 New MW TVD 0. 052 H F

P

5148

psi

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

Q

R

156

0.0704

bbl

bbl/ft

S. Temperature and Compression Effects. (from fig. 11P.5 or formula below)

S TZ 4.03− (0.38 ln(P))

T. New Mud Weight Gradient, psi/ft

S

0.78

0.052 H =

U. PcMAX , Part 1 (from Fig. 11P. 2 or from Formula Below )

= =

T

(Surface) U

0.572

57

psi/ft

psi

(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

(Subsea) U

0

psi

Subsea correction

= RKB to ML

( ft ) -

Vol . Choke Line(

R

bbl )

T

(use this new U for Part V. and Part W. below)

V. PcMAX Part 2 (from Fig. 11P.3 or from Formula Below )

2

U

V

703

psi

W. Maximum Casing Pressure,

PCmax=PCmax, Part 1 + PCmax, Part2 = U + V =

W

760

psi

Does Pcmax Exceed the Wellhead or Casing Pressure Limitation?

VOLUME GAIN WHILE CIRCULATING OUT GAS BUBBLE

X. Volume of Gas at Surface (From Formula Below)

YES

NO

X

Vg , Vol gas at surf , bbl

E P S

W

X

79

bbl

Y. Volume Gain While Circulating Out Gas Kick

Y=X-E

Y

64

bbl

Z. Volume Gain due to Barite Addition

Z

Total Volume Gain While Circulating Out Gas Kick

J

15 sacks / bbl

= Y+Z

Z

41

105

bbl

bbl

STROKES TO MAXIMUM CASING PRESSURE AND VOLUME

Maximum casing Pressure and Excess Volume Occur When the Pumped Volume Equals

bbl

strokes

Total Annulus Capacity - Volume of Gas at Surface

= N - X 544

3163

Rev 12/94

H-15


VOLUME ELEVEN


Figure 11P.2

Pc Max Part 1 for Engineer's Method

(Internal DP Cap) (0.052) ( Mud Wt)

Pc Max, 1 =

(2) (Annulus Capacity Factor)


Rev 12/94

H-16


VOLUME ELEVEN


Figure 11P.3

Pc Max Part 2 for Engineer's Method

Pc Max, 2 = (PR )(H1) (P 2) (TZ)


Rev 12/94

H-17


VOLUME ELEVEN



Rev 12/94

H-18


VOLUME ELEVEN


SECTION I: VOLUMETRIC CONTROL

1. INTRODUCTION

In controlling a threatened blowout, special problems may arise that interfere with 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 drillpipe, drillpipe above the

influx (as in a kick taken while tripping), or when pipe is 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. In the case of a plugged bit, it would be

necessary to perforate the drillpipe; or if the drillpipe 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

salt water 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 that 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 is Boyle's Law, which states that the pressure of a gas is directly related to its

volume. The second is hydrostatic pressure, and the third involves fluid volume and height as

determined by annular capacities.

2. BASIC VOLUMETRIC CONTROL PRINCIPLES

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:

Boyle's Law

This equation is a simplification of

the gas law equation, PV=ZnRT,

(Equation I.1)

P 1V1 = P2V2

which neglects the effect of the tem-

perature and gas compressibility fac-

where: 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

tors.

Rev 12/94

I-1


VOLUME ELEVEN


Relating this phenomenon to well control, as a gas kick migrates up without expansion the pressure

of the gas bubble will remain constant. If the gas bubble is allowed to expand as it migrates, 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 gas bubbles, they tend to rise in a fluid which

has a 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 and will bring bottomhole formation pressure to the

surface! The consequences can be disastrous, often resulting in ruptured casing or an underground

blowout.

On the other hand, if we allow the volume of 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 taken when

using Volumetric Control. We allow the gas bubble to expand by bleeding off mud at the surface

through the choke.

Second Basic Principle - Hydrostatic Pressure: The rising gas bubble can be treated as a surface

pressure with respect to the mud below it. Any time 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 the

mud is bled from the annulus, it is very important that it is done in a way that holds the casing pressure

(surface pressure) constant. From the above equation, it's clear that if we bleed mud from the annulus

while holding the casing pressure constant, then the bottomhole pressure will decrease.

Therefore, in Volumetric Control, there are two ways to influence the bottomhole pressure:

1. Do nothing. The gas bubble will rise, and bottomhole pressure will go up.

2. Bleed mud from the annulus. The hydrostatic pressure and bottomhole pressure

will go down.

We must be very careful when bleeding mud from the annulus, because if the hydrostatic pressure

is lowed too much, an underbalanced condition may result and additional gas may enter 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 casing pressure can be allowed to increase by

this lost pressure in order to keep bottomhole pressure from changing. It is for this reason, that we

measure the amount of mud bled-off from the annulus and equate that volume to a reduction in

hydrostatic pressure.

Third Basic Principle - Volume and Height: Everyone should be comfortable with annular volume

and height relationships. They are used in cement jobs, Pre-Recorded Data Sheets, and numerous

other everyday calculations on the rig. Annulus capacity factors are tabularized in Tables P.1, P.2,

and P.3, or can be calculated with the formula on the following page:

Rev 12/94

I-2


VOLUME ELEVEN


These factors are required

Annulus Capacity Factor

OD2 -ID2

ACF = ------------------

1029

in order to calculate the re-

duction in hydrostatic pres-

sure which occurs each time

mud is bled from the annu-

lus. The drop in hydrostatic

Where:

ACF = Annulus Capacity Factor (bbl/ft)

OD = Outside Diameter of Annular Space(in)

ID = Inside Diameter of Annular Space (in)

pressure occurring as a re-

sult of each mud volume bled

must be known.


The Volumetric Control Method is not a kill method, but instead is a method of controlling the

bottomhole pressure until provisions can be made to circulate or bullhead kill mud into the well.

The purpose of Volumetric Control is to control the 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, as follows:

Each barrel of mud that we bleed from the annulus causes......

......

......

......

......

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 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 casing pressure and bottomhole pressure

go up. We keep casing pressure from increasing further by bleeding mud from the annulus and the

bottomhole pressure goes down. Then we let the gas bubble rise, and then we hold casing pressure

constant by bleeding 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. These are:

1. Safety Factor

2. Pressure Increment

3. Mud Increment

Rev 12/94

I-3


VOLUME ELEVEN


The safety factor is an increase in the bottomhole pressure which occurs 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 ensure 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.

Depending on how close the shoe is to exceeding its fracture pressure under initial shut-in

conditions, it may 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.

The pressure increment is the reduction in hydrostatic pressure that occurs each time a given

volume of mud is bled from the annulus. The Drilling Representative 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

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 below. It is very important

that some means be available to measure the small volumes of mud that are bled from the

annulus.

Mud Increment

PI x ACF

Mud Increment = --------------------

MW x 0.052

where:

PI = Pressure Increment (psi)

ACF = Annulus Capacity Factor (bbl/ft)


As an example, if a hydrostatic reduction (pressure increment) of 50 psi is desired, and the

annulus capacity factor is 0.0704 bbl/ft with a mud weight of 11.3 ppg, then the proper mud

increment is 6 bbl.

Rev 12/94

I-4


VOLUME ELEVEN


Step Two - Allow Casing Pressure to Increase to 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. This would

actually be occurring as calculations were made. We allow the casing pressure to increase 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


(Goes Up)

(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 casing pressure can be kept from

rising further by bleeding mud from the well. This can be done until the first mud increment has

been bled from the well. The manner in which the mud is bled off 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 ensure 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


(Goes Down)

(Goes Down)

(Stays the Same)

Each time the mud is bled 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.

Rev 12/94

I-5


VOLUME ELEVEN


Step Four - Wait for the Casing Pressure to Rise as the Gas Bubb le Migrates

Each volume of mud bled from the annulus reduces the bottomhole pressure by the amount of

the pressure increment. This decreases the 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,

bottomhole pressure has also increased 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 full overbalance returns to the well, the casing pressure can again be held constant by

bleeding mud from the annulus. As with the first bleed step, this has to stop when the mud

increment has been bled from the well. 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 Bubb le Migrates

After the bleed step, again we wait for the gas bubble to migrate with the well shut-in in order

to raise the bottomhole pressure 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 holding casing

pressure constant and letting it rise, holding casing pressure constant and letting it rise, holding

casing pressure constant and letting it rise, until the gas has finally migrated all the way to the

surface. Each time the casing pressure is held constant and mud is bled, the bottomhole

pressure falls and each time the casing pressure is allowed to rise as the bubble migrates, the

bottomhole pressure rises. During each bleed step, the gas bubble expands and 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.

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 it's essential 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.

Rev 12/94

I-6


VOLUME ELEVEN


4. LUBRICATE & 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 & may change throughout the procedure. The rise in surface pressure

can be calculated by applying Boyle's law of P1V 1 = P 2V2 and realizing that for every barrel of

mud pumped into the well the bubble size decreases 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.

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 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 the gasallowed 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.

5. VOLUMETRIC CONTROL EXAMPLE

"JJ" Flash, the Chevron Drilling Representative, was glad he had been to Well Control School last

week on his days off because he needed to use what he had learned 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 and knew he would have to use Volumetric

Control. JJ gathered up the following information and jotted it down in his tally book:

Rev 12/94

I-7


VOLUME ELEVEN


Hole Size: 8-1/2"

Drill Pipe: 5" X.H.

Ann. Cap. Factor: 0.0459 bbl/ft

TD:14,400' MD/TVD

Shoe Test:16.8 ppg EMW

Kick Size: 24 bbl

Mud Weight: 15.2 ppg

SICP: 640 psi

SIDP: 520 psi

Casing Shoe: 12,220' MD/TVD

JJ knew that he had to determine the safety factor, pressure increment, and mud increment. But, he

knew he had to check the shoe pressures first. Under shut-in conditions, he calculated the shoe

pressure as:

Shoe Pressure = (TVD shoe x Mud Weight x 0.052) + SICP

or,

= (12220' x 15.2 ppg x 0.052) + 640 psi = 10298 psi

He knew the shoe would break down at a pressure of,

Shoe Fracture Pressure = (TVDshoe x Shoe Test x 0.052)

= (12220 x 16.8 ppg x 0.052) = 10675 psi

JJ saw that the casing pressure could rise another 377 psi (10675 psi - 10298 psi = 377 psi) before

breaking the shoe down, so he decided on a safety factor of 200 psi.

The pressure increment was quickly calculated by dividing the safety factor by 3:

200 psi

Pressure Increment = ------------ = 67 psi, or 70 psi

3

JJ then had to calculate the mud increment, or the volume of mud to generate 70 psi of hydrostatic

pressure in the annulus.

PI x ACF 70 x 0.0459

Mud Increment = -------------------- = ------------------- = 4.0 bbls

MW x 0.052 15.2 x 0.052

He then knew that for every 4.0 bbls of mud that was bled from the annulus, the hydrostatic pressure

would be reduced by 70 psi. With these calculations completed, he was ready to proceed.

JJ 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. JJ had determined that he would use the small tank to measure the mud volume

which was bled from the well. JJ 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. JJ knew that the this was as far as he was going to let it rise.

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. As the

Rev 12/94

I-8


VOLUME ELEVEN


pressure tried to creep up above 840 psi, JJ 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 back to 840 psi. JJ closed the choke. He continued prevent the

casing pressure from rising above 840 psi by bleeding mud in small increments. Over two hours later,

the Roughneck finally had 4.0 bbls in the small tank.

JJ 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 70 psi to 910 psi (840 psi + 70 psi = 910 psi).

Now that he had his full 200 psi of bottomhole overbalance back on the well, it was time to hold the casing

pressure constant again. He kept the casing pressure from rising above 910 psi until he had bled another

4.0 barrels of mud from the annulus. It took a long time to accumulate this 4.0 barrels of mud but not

as long as the first 4.0 barrels.

For the next seven hours, JJ held the casing pressure constant until he had bled 4.0 bbls of mud and

then let it rise to replace the lost 70 psi, then held casing pressure constant and then let it rise, and then

held it constant and let it rise again for a total of fourteen steps. The fifteenth time he was holding casing

pressure constant (at 1820 psi) JJ 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 the location to shoot some holes in the drill collars. He'd be circulating

within the hour.

Figure 1.1 Volumetric Control Example Pressures

12200

12100

12000

11900

Migrate

Bleed

1180 0

0

4

8

12 16 20 24 28 32 36 40 44 48 52 56 60

1400

1000

Migrate

Bleed

600

0

4

8

12 16 20 24 28 32 36 40 44 48 52 56 60

Rev 12/94

I-9


VOLUME ELEVEN


A plot of JJ's Volumetric Control procedure is shown in Figure I.1. Each time he held the casing

pressure constant, the bottomhole pressure decreased, and on each time he let the casing pressure

rise the bottomhole pressure increased. The gas bubble volume increased by 4.0 bbls each time he

held casing pressure constant by bleeding mud and it 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).

6. OTHER CONSIDERATIONS

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 a 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 the formula below:

Rate of Gas Bubble Rise

∆ SICP

Eqn I.2 ROR =

-------------------------

MW x 0.052 x∆T

where:

ROR = Rate of Rise (ft/min)

∆ SICP = Change in Shut-in Casing Pressure


∆T = 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 each time the casing pressure is allowed to rise. Remember, however, that the gas bubble

will continue to rise when the casing pressure is being held constant.

Directional Wells: Bubble migration rates will be higher and the bubble will tend to spread out more.

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. 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, except that the casing

pressure may be higher due to the additional safety factor applied to the well.

Casing Pressure Continues to Rise With Gas at the Surface: This may occur if the gas bubble

is strung-out. 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

Representative should keep the casing pressure from rising by bleeding gas from the well, until the

casing pressure is no longer trying to rise.

Well Control and Blowout Prevention

Documents

Transcript of Well Control and Blowout Prevention