Well Control And Blowout Prevention pl38

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 WELL CONTROL AND BLOWOUT PREVENTION

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. Considerable 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 responsibility 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


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 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 ing that all crew 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


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 ed 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 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 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


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 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


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 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


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


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


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


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 overweighting 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


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

1000 5000 10000 20000

5.0 PPG

16.2 PPG

9.0 PPG

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 shutin 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


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 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 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


Figure C.2 - Abnormal Pressure Due to Faulting

8,000 ft. 10,000 ft.

4650 psi

4650 psi

Another common cause of abnormal pressure is faulting. As can be seen in Figure C.2, a formation originally deposited under normal pressure conditions is uplifted 2,000 ft. The pressure within the uplifted section is trapped in the formation. The pressure in the formation is now abnormal for that depth. There may be no rig floor warning prior to 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 formation pressure at the gas-water 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 structure (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


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


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


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 without fracturing. Upon gaining returns, 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


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 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 Representative 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 action 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 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 shutin 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 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


In areas where correlation with other wells may be difficult, calculation and plotting of the "d" exponent can be helpful in detecting abnormal pressure. The "d" exponent is obtained from the basic drilling equation shown below. As penetration rate is 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 sequences, a break may be from 10 ft/hr to 50 ft/hr, or perhaps from 5 ft/hr to 10 ft/hr. In any case, while

14000

8

9

10

Mud Weight, ppg.

11

drilling in expected high pressure areas, if a relatively long interval of slow (shale) drilling is suddenly interrupted by faster drilling ( indicating a sand) the kelly should be picked up immediately, the pump 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


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 pressured shale gas will continue to feed in after all drilled-up gas has been removed from the mud. Occasionally, drilled gas will be slow to drop out, but will finally do so if the mud weight is high enough to control the formation pressure.

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 abnormalpressure 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


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


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. , 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


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 ts 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 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 shutin. 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) SI

(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

CHEVRON DRILLING REFERENCE SERIES 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 ts 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 of the drilling crew are at their assigned stations awaiting further instructions.

Rev. 12/94 D-3


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 steadystate 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) SI

(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



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 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 bleedoffs. 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 SI 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


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


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 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 relationship between bottomhole pressure, casing pressure, and drillpipe pressure is necessary to effectively use the well control procedures discussed in this volume. Perhaps the best way to illustrate this relationship is through the concept of a UTube.

Figure E.1 illustrates the cross section of two vertical tubes of the same size connected at the base by a horizontal tube. When a fluid of uniform density is added to the system, the levels will equalize in columns A and B. This assembly is often referred to as a U-Tube because its shape

Column A

Bottomhole Pressure

Column B

Rev 12/94 E-1


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 bottomhole 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


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


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


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


In both methods, once the top of the bubble es 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

CHEVRON DRILLING REFERENCE SERIES 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 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


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


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 SI

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:

MISI = (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 SI 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


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. 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


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


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.)

Drill Pipe HW Drill Pipe

ID(in.)

in. (OD) in. (OD)

lb./ft. lb./ft.

7

by by

2.8125

INTERNAL CAPACITIES:

Drill Pipe

8,550


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 SI TO FRACTURE FORMATION AT SHOE:

Max. SI = (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


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

(in. OD)

(in. Avg ID)


(feet)

(feet)


10,000

psi.


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


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


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 MAX INITIAL SI TO FRACTURE FORMATION AT SHOE: Max. SI = (Shoe Test - Present Mud Wt.) x 0.052 x Shoe TVD

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


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


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 ts 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 ts are clear of the preventers.

Close the annular preventer or uppermost pipe ram preventer.

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


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 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)

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 its seat. Record the drillpipe pressure when the lull is first seen. To 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


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


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


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 SI 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 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


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 ts). 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


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 filledout 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. 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


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


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

, when using the Driller's Method circulating pressures aren't calculated, but are selfdetermined. 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


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


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


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


DRILLER'S METHOD WORKSHEET (use the Tab key to advance to next required input)

PRERECORDED INFORMATION

SPM

psi

bbl/stk

bbl/min

A. Slow Pump Rate Data

Pump #1

( Use SPR Pressure through Riser for Subsea )

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 (SI)

Pump #2

Initial Pit Volume Increase 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 { 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. { 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

C 0.052

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

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. { 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


DRILLER'S METHOD WORKSHEET

RESERVOIR PRESSURE (Pr)

(page 2)

K . Pr

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)

N

0.52

psi/ft.

O.

Pc

max

Part 1 = SIDP

(Surface) O

235

psi

(Optional Correction for Subsea Wells) O. (Subsea) A correction must be added to Pcmax, Part1 calculated above to for the choke line.

(Subsea) O = Subsea Correction + (Surface) O = Vol . Choke Line Subsea Correction =

( ft ) -

L

(bbl )

(Subsea) O

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

- (0. 38

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

P

0.78

=

(O)

2

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 R

T

64

bbl

U. Volume Gain While Circulating Out Gas Kick

U

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 559

strokes 3253

A

l

C

{

d d} T

Rev. 12/94 G-14

bbl


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

Rev 12/94 G-15



Rev. 12/94 G-16


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 ts are clear of the preventer stack.

SHUT DOWN Stop the mud pumps.

(3)

SHUT-IN

Close the annular preventer or uppermost pipe ram preventer. Confirm that the well is shut-in and 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 ts are clear of the

preventer stack.

(3)

SHUT-IN

Close the annular preventer or uppermost pipe ram preventer.

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


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 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)

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 its seat. Record the drillpipe pressure when the lull is first seen. To 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 shutin drillpipe pressure.

Rev 12/94 H-2


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 bledoff 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


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 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


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


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 Representative 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 ts). 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


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


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


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

CHEVRON DRILLING REFERENCE SERIES

VOLUME ELEVEN WELL CONTROL AND BLOWOUT PREVENTION GUIDE

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


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


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



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

(in. OD)

(in. Avg ID)


(feet)

(feet)


10,000

psi.


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.)


in. (OD) in. (OD)

lb./ft. lb./ft.

ID(in.)

7

by by

2.8125


Drill Pipe Drill Pipe HW Drill Pipe

ft. ft. ft.

x x x

0.0178


8,550

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. =

281.8 320.5

21.2


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 MAX INITIAL SI TO FRACTURE FORMATION AT SHOE: Max. SI = (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 H-13


ENGINEER'S METHOD WORKSHEET (use the Tab key to advance to next required input)

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 (SI) Initial Pit Volume Increase 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

C 0.052

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

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

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

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


ENGINEER'S METHOD WORKSHEET RESERVOIR PRESSURE (Pr)

(page 2)

P. Pr

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

T. New Mud Weight Gradient, psi/ft

S

0.78

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 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 )

(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 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


WELL CONTROL AND BLOWOUT PREVENTION GUIDE

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


Figure 11P.3

Pc Max Part 2 for Engineer's Method

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


Rev 12/94 H-17



Rev 12/94 H-18


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 temperature 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


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


These factors are required

Annulus Capacity Factor

OD2 -ID2 ACF = -----------------1029

in order to calculate the re-

duction in hydrostatic pressure which occurs each time mud is bled from the annulus. 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 result 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


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) MW = Mud Weight (ppg)

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


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


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


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


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 SI: 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) + SI 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


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


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

∆ SI

Eqn I.2 ROR =

------------------------MW x 0.052 x

where: ROR = Rate of Rise (ft/min) ∆ SI = Change in Shut-in Casing Pressure MW = Mud Weight (ppg) ∆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. , 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.

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