Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. More information

PEH:Well Control: Procedures and Principles

Publication Information

Vol2DECover.png

Petroleum Engineering Handbook

Larry W. Lake, Editor-in-Chief

Volume II - Drilling Engineering

Robert F. Mitchell, Editor

Chapter 4 - Well Control: Procedures and Principles

By Neal Adams, Neal Adams Services

Pgs. 185-219

ISBN 978-1-55563-114-7
Get permission for reuse

Well control and blowout prevention have become particularly important topics in the hydrocarbon production industry for many reasons. Among these reasons are higher drilling costs, waste of natural resources, and the possible loss of human life when kicks and blowouts occur. One concern is the increasing number of governmental regulations and restrictions placed on the hydrocarbon industry, partially as a result of recent, much-publicized well-control incidents. For these and other reasons, it is important that drilling personnel understand well-control principles and the procedures to follow to properly control potential blowouts.

This chapter discusses the key elements that can be used to control kicks and prevent blowouts. These steps are based on the work of a blowout specialist and are briefly presented below:

  • Quickly shut in the well.
  • When in doubt, shut down and get help. Kicks occur as frequently while drilling as they do while tripping out of the hole. Many small kicks turn into big blowouts because of improper handling.
  • Act cautiously to avoid mistakes—take your time to get it right the first time. You may not have another opportunity to do it correctly.


These and other well-control details are presented in detail throughout this chapter. Unusual problems occurring during kick killing are discussed in other referenced sources.

Contents

Introduction to Kicks


Various drilling problems confront operators daily. Among these are lost circulation, stuck pipe, deviation control, and well control. The drilling problem specifically examined in this chapter is well control. Other drilling problems will be presented as they relate to aspects of well control. One of the most pervasive problems with well control is the "kick."

A kick is a well control problem in which the pressure found within the drilled rock is higher than the mud hydrostatic pressure acting on the borehole or rock face. When this occurs, the greater formation pressure has a tendency to force formation fluids into the wellbore. This forced fluid flow is called a kick. If the flow is successfully controlled, the kick is considered to have been killed. An uncontrolled kick that increases in severity may result in what is known as a "blowout."

Factors Affecting Kick Severity

Several factors affect the severity of a kick. One factor, for example, is the "permeability" of rock, which is its ability to allow fluid to move through the rock. Another factor affecting kick severity is "porosity." Porosity measures the amount of space in the rock containing fluids. A rock with high permeability and high porosity has greater potential for a severe kick than a rock with low permeability and low porosity. For example, sandstone is considered to have greater kick potential than shale because sandstone, in general, has greater permeability and greater porosity than shale.

And yet another factor affecting kick severity is the "pressure differential" involved. Pressure differential is the difference between the formation fluid pressure and the mud hydrostatic pressure. If the formation pressure is much greater than the hydrostatic pressure, a large negative differential pressure exists. If this negative differential pressure is coupled with high permeability and high porosity, a severe kick may occur.

Kick Labels

A kick can be labeled in several ways, including one that depends on the type of formation fluid that entered the borehole. Known kick fluids include gas, oil, salt water, magnesium chloride water, hydrogen sulfide (sour) gas, and carbon dioxide. If gas enters the borehole, the kick is called a "gas kick." Furthermore, if a volume of 20 bbl (3.2 m3) of gas entered the borehole, the kick could be termed a 20-bbl (3.2-m3) gas kick.

Another way of labeling kicks is by identifying the required mud weight increase necessary to control the well and kill a potential blowout. For example, if a kick required a 0.7-lbm/gal (84-kg/m3) mud weight increase to control the well, the kick could be termed a 0.7-lbm/gal (84-kg/m3) kick. It is interesting to note that an average kick requires approximately 0.5 lbm/gal (60 kg/m3), or less, mud weight increase.

Other Factors Affecting Well Control

Another important consideration in well control is the pressure the formation rock can withstand without sustaining an induced fracture. This rock strength is often called the "fracture mud weight," or "gradient," and is usually expressed in lbm/gal of equivalent mud weight.

The "equivalent mud weight" is the summation of pressures exerted on the borehole wall and includes mud hydrostatic pressure, pressure surges caused by pipe movement, friction pressures applied against the formation as a result of pumping the drilling fluid, or any casing pressure caused by a kick. For example, if the fracture mud weight of a formation is determined to be 16.0 lbm/gal, the well can withstand any combination of the above-mentioned pressures that yield the same pressure as a column of 16.0-lbm/gal (1920-kg/m3) mud to the desired depth. This combination could be 16.0-lbm/gal (1920-kg/m3) mud, 15.0-lbm/gal (1800-kg/m3) mud and some amount of casing pressure, 15.5-lbm/gal (1860-kg/m3) mud and a smaller amount of casing pressure, or other combinations.

Causes of Kicks

Kicks occur as a result of formation pressure being greater than mud hydrostatic pressure, which causes fluids to flow from the formation into the wellbore. In almost all drilling operations, the operator attempts to maintain a hydrostatic pressure greater than formation pressure and, thus, prevent kicks; however, on occasion the formation will exceed the mud pressure and a kick will occur. Reasons for this imbalance explain the key causes of kicks:

  • Insufficient mud weight.
  • Improper hole fill-up during trips.
  • Swabbing.
  • Cut mud.
  • Lost circulation.


Insufficient Mud Weight.

Insufficient mud weight is the predominant cause of kicks. A permeable zone is drilled while using a mud weight that exerts less pressure than the formation pressure within the zone. Because the formation pressure exceeds the wellbore pressure, fluids begin to flow from the formation into the wellbore and the kick occurs.

These abnormal formation pressures are often associated with causes for kicks. Abnormal formation pressures are greater pressures than in normal conditions. In well control situations, formation pressures greater than normal are the biggest concern. Because a normal formation pressure is equal to a full column of native water, abnormally pressured formations exert more pressure than a full water column. If abnormally pressured formations are encountered while drilling with mud weights insufficient to control the zone, a potential kick situation has developed. Whether or not the kick occurs depends on the permeability and porosity of the rock. A number of abnormal pressure indicators can be used to estimate formation pressures so that kicks caused by insufficient mud weight are prevented (some are listed in Table 4.1).


An obvious solution to kicks caused by insufficient mud weights seems to be drilling with high mud weights; however, this is not always a viable solution. First, high mud weights may exceed the fracture mud weight of the formation and induce lost circulation. Second, mud weights in excess of the formation pressure may significantly reduce the penetration rates. Also, pipe sticking becomes a serious consideration when excessive mud weights are used. The best solution is to maintain a mud weight slightly greater than formation pressure until the mud weight begins to approach the fracture mud weight and, thus, requires an additional string of casing.

Improper Hole Fill-Up During Trips.

Improperly filling up of the hole during trips is another prominent cause of kicks. As the drillpipe is pulled out of the hole, the mud level falls because the pipe steel no longer displaces the mud. As the overall mud level decreases, the hole must be periodically filled up with mud to avoid reducing the hydrostatic pressure and, thereby, allowing a kick to occur.

Several methods can be used to fill up the hole, but each must be able to accurately measure the amount of mud required. It is not acceptable—under any condition—to allow a centrifugal pump to continuously fill up the hole from the suction pit because accurate mud-volume measurement with this sort of pump is impossible. The two acceptable methods most commonly used to maintain hole fill-up are the trip-tank method and the pump-stroke measurements method.

The trip-tank method has a calibration device that monitors the volume of mud entering the hole. The tank can be placed above the preventer to allow gravity to force mud into the annulus, or a centrifugal pump may pump mud into the annulus with the overflow returning to the trip tank. The advantages of the trip-tank method include that the hole remains full at all times, and an accurate measurement of the mud entering the hole is possible.

The other method of keeping a full hole—the pump-stroke measurement method—is to periodically fill up the hole with a positive-displacement pump. A flowline device can be installed with the positive-displacement pump to measure the pump strokes required to fill the hole. This device will automatically shut off the pump when the hole is full.

Swabbing.

Pulling the drillstring from the borehole creates swab pressures. Swab pressures are negative and reduce the effective hydrostatic pressure throughout the hole and below the bit. If this pressure reduction lowers the effective hydrostatic pressure below the formation pressure, a potential kick has developed. Variables controlling swab pressures are pipe pulling speed, mud properties, hole configuration, and the effect of "balled" equipment. Some swab pressures can be seen in Table 4.2.


Cut Mud.

Gas-contaminated mud will occasionally cause a kick, although this is rare. The mud density reduction is usually caused by fluids from the core volume being cut and released into the mud system. As the gas is circulated to the surface, it expands and may reduce the overall hydrostatic pressure sufficient enough to allow a kick to occur.

Although the mud weight is cut severely at the surface, the hydrostatic pressure is not reduced significantly because most gas expansion occurs near the surface and not at the hole bottom.

Lost Circulation.

Occasionally, kicks are caused by lost circulation. A decreased hydrostatic pressure occurs from a shorter mud column. When a kick occurs from lost circulation, the problem may become severe. A large volume of kick fluid may enter the hole before the rising mud level is observed at the surface. It is recommended that the hole be filled with some type of fluid to monitor fluid levels if lost circulation occurs.

Warning Signs of Kicks

Warning signs and possible kick indicators can be observed at the surface. Each crew member has the responsibility to recognize and interpret these signs and take proper action. All signs do not positively identify a kick; some merely warn of potential kick situations. Key warning signs to watch for include the following:

  • Flow rate increase.
  • Pit volume increase.
  • Flowing well with pumps off.
  • Pump pressure decrease and pump stroke increase.
  • Improper hole fill-up on trips.
  • String weight change.
  • Drilling break.
  • Cut mud weight.


Each is identified below as a primary or secondary warning sign, relative to its importance in kick detection.

Flow Rate Increase (Primary Indicator).

An increase in flow rate leaving the well, while pumping at a constant rate, is a primary kick indicator. The increased flow rate is interpreted as the formation aiding the rig pumps by moving fluid up the annulus and forcing formation fluids into the wellbore.

Pit Volume Increase (Primary Indicator).

If the pit volume is not changed as a result of surface-controlled actions, an increase indicates a kick is occurring. Fluids entering the wellbore displace an equal volume of mud at the flowline, resulting in pit gain.

Flowing Well With Pumps Off (Primary Indicator).

When the rig pumps are not moving the mud, a continued flow from the well indicates a kick is in progress. An exception is when the mud in the drillpipe is considerably heavier than in the annulus, such as in the case of a slug.

Pump Pressure Decrease and Pump Stroke Increase (Secondary Indicator).

A pump pressure change may indicate a kick. Initial fluid entry into the borehole may cause the mud to flocculate and temporarily increase the pump pressure. As the flow continues, the low-density influx will displace heavier drilling fluids and the pump pressure may begin to decrease. As the fluid in the annulus becomes less dense, the mud in the drillpipe tends to fall and pump speed may increase.

Other drilling problems may also exhibit these signs. A hole in the pipe, called a "washout," will cause pump pressure to decrease. A twist-off of the drillstring will give the same signs. It is proper procedure, however, to check for a kick if these signs are observed.

Improper Hole Fill-Up on Trips (Primary Indicator).

When the drillstring is pulled out of the hole, the mud level should decrease by a volume equivalent to the removed steel. If the hole does not require the calculated volume of mud to bring the mud level back to the surface, it is assumed a kick fluid has entered the hole and partially filled the displacement volume of the drillstring. Even though gas or salt water may have entered the hole, the well may not flow until enough fluid has entered to reduce the hydrostatic pressure below the formation pressure.

String Weight Change (Secondary Indicator).

Drilling fluid provides a buoyant effect to the drillstring and reduces the actual pipe weight supported by the derrick. Heavier muds have a greater buoyant force than less dense muds. When a kick occurs, and low-density formation fluids begin to enter the borehole, the buoyant force of the mud system is reduced, and the string weight observed at the surface begins to increase.

Drilling Break (Secondary Indicator).

An abrupt increase in bit-penetration rate, called a "drilling break," is a warning sign of a potential kick. A gradual increase in penetration rate is an abnormal pressure indicator and should not be misconstrued as an abrupt rate increase.

When the rate suddenly increases, it is assumed that the rock type has changed. It is also assumed that the new rock type has the potential to kick (as in the case of a sand), whereas the previously drilled rock did not have this potential (as in the case of shale). Although a drilling break may have been observed, it is not certain that a kick will occur, only that a new formation has been drilled that may have kick potential.

It is recommended when a drilling break is recorded that the driller should drill 3 to 5 ft (1 to 1.5 m) into the sand and then stop to check for flowing formation fluids. Flow checks are not always performed in tophole drilling or when drilling through a series of stringers in which repetitive breaks are encountered; unfortunately, many kicks and blowouts have occurred because of this lack of flow checking.

Cut Mud Weight (Secondary Indicator).

Reduced mud weight observed at the flow line has occasionally caused a kick to occur. Some causes for reduced mud weight are core volume cutting, connection air, or aerated mud circulated from the pits and down the drillpipe. Fortunately, the lower mud weights from the cuttings effect are found near the surface (generally because of gas expansion) and do not appreciably reduce mud density throughout the hole. Table 4.3 shows that gas cutting has a very small effect on bottomhole hydrostatic pressure.


An important point to remember about gas cutting is that if the well did not kick within the time required to drill the gas zone and circulate the gas to the surface, only a small possibility exists that it will kick. Generally, gas cutting indicates that a formation has been drilled that contains gas. It does not mean that the mud weight must be increased.

Kick Detection and Monitoring With MWD Tools


Measurement while drilling (MWD) systems monitor mud properties, formation parameters, and drillstring parameters during circulation and drilling operations. The system is widely used for drilling, but it also has applications for well control, including the following:

  • Drilling-efficiency data, such as downhole weight on bit and torque, can be used to differentiate between rate of penetration changes caused by drag and those caused by formation strength. Monitoring bottomhole pressure, temperature, and flow with the MWD tool is not only useful for early kick detection, but can also be valuable during a well-control kill operation. Formation evaluation capabilities, such as gamma ray and resistivity measurements, can be used to detect influxes into the wellbore, identify rock lithology, and predict pore pressure trends.
  • The MWD tool enables monitoring of the acoustic properties of the annulus for early gas-influx detection. Pressure pulses generated by the MWD pulser are recorded and compared at the standpipe and the top of the annulus. Full-scale testing has shown that the presence of free gas in the annulus is detected by amplitude attenuation and phase delay between the two signals. For water-based mud systems, this technique has demonstrated the capacity to consistently detect gas influxes within minutes before significant expansion occurs. Further development is currently under way to improve the system’s capability to detect gas influxes in oil-based mud.
  • Some MWD tools feature kick detection through ultrasonic sensors. In these systems, an ultrasonic transducer emits a signal that is reflected off the formation and back to the sensor. Small quantities of free gas significantly alter the acoustic impedance of the mud. Automatic monitoring of these signals permits detection of gas in the annulus. It should be noted that these devices only detect the presence of gas at or below the MWD tool.


The MWD tool offers kick-detection benefits if the response time is less than the time it takes to observe the surface indicators. The tool can provide early detection of kicks and potential influxes as well as monitor the kick-killing process. Tool response time is a function of the complexity of the MWD tool and the mode of operation. The sequence of data transmission determines the update times of each type of measurement. Many MWD tools allow for reprogramming of the update sequence while the tool is in the hole. This feature can enable the operator to increase the update frequency of critical information to meet the expected needs of the section being drilled. If the tool response time is longer than required for surface indicators to be observed, the MWD only serves as a confirmation source.

Shut-In Procedures


When one or more warning signs of kicks are observed, steps should be taken to shut in the well. If there is any doubt that the well is flowing, shut it in and check the pressures. It is important to remember that there is no difference between a small-flow well and a full-flowing well, because both can very quickly turn into a big blowout.

In the past, there has been some hesitation to close in a flowing well because of the possibility of sticking the pipe. It can be proven that, for common types of pipe sticking (e.g., differential pressure, heaving, or sloughing shale), it is better to close in the well quickly, reduce the kick influx, and, thereby, reduce the chances of pipe sticking. The primary concern at this point is to kill the kick safely; when feasible, the secondary concern is to avoid pipe sticking.

There is some concern about fracturing the well and creating an underground blowout resulting from shutting in the well when a kick occurs. If the well is allowed to flow, it will eventually become necessary to shut in the well, at which time the possibility of fracturing the well will be greater than if the well had been shut in immediately after the initial kick detection. Table 4.4 shows an example of higher casing pressures resulting from continuous flow because of failure to close in the well.

Initial Shut-In

Considerable discussion has occurred regarding the merits of "hard" shut-in procedures vs. "soft" shut-in procedures. In the hard shut-in procedure, the annular preventer(s) are closed immediately after the pumps are shut down. In soft shut-in procedures, the choke is opened before closing the preventers, and then, once the preventers are closed, the choke is closed. Some arguments in favor of soft shut-in procedures are that they avoid a "water-hammer" effect caused by abruptly stopping the fluid flow, and they provide an alternate means of well control (i.e., the low-choke-pressure method) if the casing pressure becomes excessive. But, the water-hammer effect has no proven substance, and the low-choke-pressure method is an unreliable procedure. The primary argument against the soft shut-in procedure is that a continuous influx is permitted while the procedures are executed. For these reasons, only the hard shut-in procedures are presented in this chapter.

Hard shut-in procedures for well control depend on the type of rig and the drilling operation occurring when the kick is taken, such as the following:

  • Drilling—land or bottom-supported offshore rig.
  • Tripping—land or bottom-supported offshore rig.
  • Drilling—floating rig.
  • Tripping—floating rig.
  • Diverter procedures—all rigs (when surface pipe is not set).


Drilling—Land or Bottom-Supported Offshore Rig.

These rigs do not move during normal drilling operations. They include land-and-barge rigs, jack-ups, and platform rigs.

Shut-In Procedures

When a primary kick warning sign has been observed, do the following immediately:

  1. Raise the kelly until a tool joint is above the rotary table.
  2. Stop the mud pumps.
  3. Close the annular preventer.
  4. Notify company personnel.
  5. Read and record the shut-in drillpipe pressure, the shut-in casing pressure, and the pit gain.


Raising the kelly is an important procedure. With the kelly out of the hole, the valve at the bottom of the kelly can be closed if necessary. Also, the annular-preventer members can attain a more secure seal on the pipe than a kelly.

Tripping—Land or Bottom-Supported Offshore Rig.

A high percentage of well-control problems occur when a trip is being made. The kick problems may be compounded when the rig crew is preoccupied with the trip mechanics and fails to observe the initial warning signs of the kick.

Shut-In Procedures

When a primary warning sign of a kick has been observed, do the following immediately:

  1. Set the top tool joint on the slips.
  2. Install and make up a full-opening, fully opened safety valve on the drillpipe.
  3. Close the safety valve and the annular preventer.
  4. Notify company personnel.
  5. Pick up and make up the kelly.
  6. Open the safety valve.
  7. Read and record the shut-in drillpipe pressure, shut-in casing pressure, and pit gain.



Installing a fully opened, full-opening safety valve in preference to an inside blowout preventer (BOP), or float, valve is a prime consideration because of the advantages offered by the full-opening valve. If flow is encountered up the drillpipe as a result of a trip kick, the fully opened, full-opening valve is physically easier to stab. Also, a float-type inside-BOP valve would automatically close when the upward-moving fluid contacts the valve.

If wireline work, such as drillpipe perforating or logging, becomes necessary, the full-opening valve will accept logging tools approximately equal to its inside diameter, whereas the float valve may prohibit wireline work altogether. After the kick is shut in, an inside-BOP float valve may be stabbed on the full-opening valve to allow stripping operations.

Drilling—Floating Rig.

A floating rig moves during normal drilling operations. The primary types of floating vessels are semisubmersibles and drillships.

Several differences in shut-in procedures apply to floating rigs. Drillstring movement can occur, even with a motion compensator in operation. Also, the BOP stack is on the sea floor. To solve the problem of possible vessel and drillstring movement, and the resulting wear on the preventers, a tool joint may be lowered on the closed pipe rams. The string weight is hung on these rams. This procedure may not be necessary if the rig has a functional motion compensator.

When the stack is located a considerable distance from the rig floor, the problem is to ensure that a tool joint does not interfere with closing the preventer elements. A spacing-out procedure should be executed when the BOP is tested. After running the BOP stack, close the rams, slowly lower the drillstring until a tool joint contacts the rams, and record the position of the kelly at that point. Space out should occur so that a tool joint and lower-kelly valve are above the rotary table. Spacing should be correlated to tide-measuring equipment on the rig floor.

The following procedure could be altered in emergency situations to use the annular preventer and motion compensator for cases in which the shut-in drillpipe pressure and shut-in casing pressure are low and near the same value (indicating oil or water), or the "kick volume" is less than 20 to 30 bbl and the time to kill the well is less than 2 to 3 hours. The closing pressure on the annular preventer must be reduced to the range recommended by the manufacturer for this situation to avoid annular element failure.

Shut-In Procedures

When a primary warning sign of a kick has been observed, do the following immediately:

  1. Raise the kelly to the level previously designated during the spacing-out procedure (tide adjusted).
  2. Stop the mud pumps.
  3. Close the annular preventer.
  4. Notify company personnel.
  5. Close the upper set of pipe rams.
  6. Reduce the hydraulic pressure on the annular preventer.
  7. Lower the drillpipe until the pipe is supported entirely by the rams.
  8. Read and record the shut-in drillpipe pressure, shut-in casing pressure, and pit gain.



Tripping—Floating Rig.

The procedures for kick closure during a tripping operation on a floater is a combination of floating drilling procedures and immobile rig-tripping procedures.

Shut-In Procedures

When a primary warning sign of a kick has been observed, do the following immediately:

  1. Set the top tool joint on the slips.
  2. Install and make up a full-opening, fully opened safety valve in the drillpipe.
  3. Close the safety valve and the annular preventer.
  4. Notify company personnel.
  5. Pick up and make up the kelly.
  6. Reduce the hydraulic pressure on the annular preventer.
  7. Lower the drillpipe until the rams support it.
  8. Read and record the shut-in drillpipe pressure, shut-in casing pressure, and pit gain.


Diverter Procedures—All Rigs.

When a kick occurs in a well with insufficient casing to safely control a kick, a blowout will occur. Because a shallow underground blowout is difficult to control and may cause the loss of the rig, an attempt is usually made to divert the surface blowout away from the rig. This is common practice on land or offshore rigs that are not mobile. Special attention must be given to this procedure so that the well is not shut in until after the diverter lines are opened.

Shut-In Procedures

When a primary warning sign of a kick has been observed, do the following immediately:

  1. Raise the kelly until a tool joint is above the rotary table.
  2. Increase the pump rate to maximum output.
  3. Open the diverter line valve(s).
  4. Close the diverter unit (or annular preventer).
  5. Notify company personnel.


Recent experiences show that shallow gas flows are difficult to control, but the industry philosophy is improving, and new handling procedures are being developed.

Crewmember Responsibilities for Shut-In Procedures

Each crewmember has different responsibilities during shut-in procedures. These responsibilities follow and are listed according to job classification.

Floorhand (Roughneck).

These responsibilities for shut-in procedures belong to the floorhand:

  1. Notify the driller of any observed kick-related warning signs.
  2. Assist in installing the full-opening safety valve if a trip is being made.
  3. Initiate well-control responsibilities after shut-in.



Derrickman.

These responsibilities for shut-in procedures belong to the derrickman:

  1. Notify the driller of any observed kick-related warning signs.
  2. Initiate well-control responsibilities.
  3. Begin mud-mixing preparations.



Driller.

These responsibilities for shut-in procedures belong to the driller:

  1. Immediately shut in the well if any of the primary kick-related warning signs are observed.
  2. If a kick occurs while making a trip, set the top tool joint on the slips and direct the crews in the installation of the safety valve before closing the preventers.
  3. Notify all proper company personnel.


Obtaining and Interpreting Shut-In Pressures


"Shut-in pressures" are defined as pressures recorded on the drillpipe and on the casing when the well is closed. Although both pressures are important, the drillpipe pressure will be used almost exclusively in killing the well. The shut-in drillpipe pressure is shown as psidp. Shut-in casing pressure is psic. (At this point, assume that the drillpipe does not contain a float valve.)

Reading Pressures

During a kick, fluids flow from the formation into the wellbore. When the well is closed to prevent a blowout, pressure builds at the surface because of formation fluid entry into the annulus, as well as because of the difference between the mud hydrostatic pressure and the formation pressure.

Because this pressure imbalance cannot exist for long, the surface pressures will finally build so that the surface pressure, plus the mud and influx hydrostatic pressures in the well, are equal to the formation pressures. Eqs. 4.1 and 4.2 express this relationship for the drillpipe and the annular side, respectively:

Vol2 page 0194 eq 001.png....................(4.1)

where psidp = shut-in drillpipe pressure, psi; pdph = drillpipe hydrostatic pressure, psi; pform = formation pressure, psi; and

Vol2 page 0194 eq 002.png....................(4.2)

where psic = shut-in casing pressure, psi; pah = annular-hydrostatic pressure, psi; and pi = influx-hydrostatic pressure, psi.

Example 4.1 and Fig. 4.1 show how the shut-in pressures are read.


Example 4.1

While drilling at 15,000 ft, the driller observed several primary warning signs of kicks and proceeded to shut in the well. After the shut-in was completed (note: the well was shut in at 6 a.m.), he called company personnel and began recording the pressures and pit gains in Table 4.5.


After 15 minutes, the final shut-in pressures were recorded as follows:

psidp = 780 psi

psic = 1,040 psi

Pit gain = 20 bbl



Interpreting Recorded Pressures

An important basic principle can be seen in Fig. 4.1. It shows that formation pressure (pform) is greater than the drillpipe hydrostatic pressure by an amount equal to the psidp. The drillpipe pressure gauge is the bottomhole pressure gauge. The casing pressure cannot be considered a direct bottomhole pressure gauge because of generally unknown amounts of formation fluid in the annulus.

Constant-Bottomhole-Pressure Concept

Fig. 4.1 can be used to illustrate another important basic principle. It was stated that the 780 psi (5.4 MPa) observed on the drillpipe gauge was the amount necessary to balance mud pressure at the hole bottom with the pressure in the gas sand at 15,000 ft (4600 m). Formation fluids travel from areas of high pressure to areas of lower pressures only. They do not travel between areas of equal pressures, assuming gravity segregation is neglected.

If the drillpipe pressure is controlled so that the total mud pressure at the hole bottom is slightly greater than formation pressure, then there will be no additional kick influx entering the well. This concept is the basis of the constant-bottomhole-pressure method of well control, in which the pressure at the hole bottom is constant and at least equal to formation pressure.

Effects of Time

In Example 4.1, 15 minutes were used to obtain shut-in pressures. The purpose of this time is to allow pressures to reach equilibrium sufficient to balance formation pressures. The required time will depend on variables such as the rock type, permeability, porosity, and the original amount of pressure underbalance. This may take a few minutes to several hours. The required time depends on conditions surrounding the kick.

Several other factors affect the time allowed for pressures to stabilize. Gas migration is the movement of low-density fluids up the annulus. It tends to build pressure at the surface, if time is allowed for migration. Also, the influx may have a tendency to deteriorate the hole stability and cause either stuck pipe or hole bridging. These problems must also be considered when reading the shut-in pressures.

Trapped Pressure

"Trapped pressure" is any pressure recorded on the drillpipe or annulus greater than the amount needed to balance the bottomhole pressure. Pressure can be trapped in the system in several ways. Common ways include gas migrating up the annulus and tending to expand, or closing the well in before the mud pumps have stopped running. Using pressure readings containing trapped pressure results in erroneous kill calculations.

Guidelines help when releasing trapped pressure. If they are not properly executed, the well will be much more difficult to kill. These guidelines are listed and explained in Table 4.6.


Because trapped pressure is greater than the amount needed to balance bottomhole pressure, trapped pressure can be bled without allowing any additional influx into the well. However, after the trapped pressure is bled off, and if the bleeding is continued, more influx will be allowed into the well, and the surface pressures will begin to increase.

Although bleeding procedures can be implemented at any time, it is advisable to check for trapped pressure when the well is shut in initially and to recheck it when the drillpipe is displaced with kill mud if any pressure remains on the shut-in drillpipe.

Drillpipe Floats

A kick can occur when a drillpipe float valve is used. Because a float valve prevents fluid and pressure movement up the drillpipe, there will not be a drillpipe pressure reading after the well is shut in. Several procedures can obtain the drillpipe pressure, and each depends on the amount of information known when the kick occurs.

Table 4.7 describes the procedures to obtain the drillpipe pressure if the slow pumping rate (kill rate) is known. Table 4.8 outlines the procedure if the kill rate is not known; Fig. 4.2 illustrates this process.


Table 4.7 is important in other applications. For example, assume a kick was taken, the shut-in drillpipe pressure was known (no float valve), and a kill rate had not yet been established. Step 6 of this table (Eq. 4.3),

Vol2 page 0196 eq 001.png....................(4.3)

could be modified to

Vol2 page 0197 eq 001.png....................(4.4)

where pkr = pump pressure at kill rate, psi, and pΣ = total pressure, psi.

The procedures in Table 4.7 remain the same, with the exception that Eq. 4.4 would be substituted for Eq. 4.3.

Establishing the shut-in drillpipe pressure becomes more complex if the kill rate is not previously determined and a float valve in the string prohibits pressure readings at the surface. Table 4.8 must be used initially to determine the psidp, after which Eq. 4.4 and Table 4.7 must be implemented to establish the kill rate.

Kick Identification


When a kick occurs, note the type of influx (gas, oil, or salt water) entering the wellbore. Remember that well-control procedures developed here are designed to kill all types of kicks safely. The formula required to make this kick influx calculation is as follows:

Vol2 page 0197 eq 002.png....................(4.5)

where gi = influx gradient, psi/ft; gmdp = mud gradient in drillpipe, psi/ft; and hi = influx height, ft. The influx gradient can be evaluated using the guidelines in Table 4.9.


Although psidp and psic can be determined accurately for Eq. 4.5, it is difficult to determine the influx height. This requires knowledge of the pit gain and the exact hole size. Example 4.2, described later, illustrates Eq. 4.5.

Kill-Weight Mud Calculation


It is necessary to calculate the mud weight needed to balance bottomhole formation pressure. "Kill-weight mud" is the amount of mud necessary to exactly balance formation pressure. It will be shown in later sections that it is safer to use the exact required mud weight without variation.

Because the drillpipe pressure has been defined as a bottomhole pressure gauge, the psidp can be used to calculate the mud weight necessary to kill the well. The kill mud formula follows:

Vol2 page 0198 eq 001.png....................(4.6)

where ρkw = kill-mud weight, lbm/gal; 19.23 = conversion constant; Dtv = true vertical-bit depth, ft; and ρo = original mud weight, lbm/gal.

Because the casing pressure does not appear in Eq. 4.6, a high casing pressure does not necessarily indicate a high kill-weight mud. The same is true for pit gain because it does not appear in Eq. 4.6. Example 4.2 uses the kill-weight mud formula.


Example 4.2

What will the kill-weight mud density be for the kick data given below?

Dtv = 11,550 ft

ρo = 12.1 lbm/gal

psidp = 240 psi

psic = 1,790 psi

Pit gain = 85 bbl

Solution.

ρkw = psidp × 19.23/ Dtv + ρo

= 240 psi × 19.23/11,550 ft + 12.1 lbm/gal

= 0.4 lbm/gal + 12.1 lbm/gal

= 12.5 lbm/gal


Well-Control Procedures


Many well-control procedures have been developed over the years. Some have used systematic approaches, while others are based on logical, but perhaps unsound, principles. The systematic approaches will be presented here.

In previous sections, the constant-bottomhole-pressure concept was introduced. With this concept, the total pressures (e.g., mud hydrostatic pressure and casing pressure) at the hole bottom are maintained at a value slightly greater than the formation pressures to prevent further influxes of formation fluids into the wellbore. And, because the pressure is only slightly greater than the formation pressure, the possibility of inducing a fracture and an underground blowout is minimized. This concept can be implemented in three ways:

  • One-Circulation, or Wait-and-Weight, Method. After the kick is shut in, weight the mud to kill density and then pump out the kick fluid in one circulation using the kill mud. (Another name often applied to this method is "the engineer’s method.")
  • Two-Circulation, or Driller’s, Method. After the kick is shut in, the kick fluid is pumped out of the hole before the mud density is increased.
  • Concurrent Method. Pumping begins immediately after the kick is shut in and pressures are recorded. The mud density is increased as rapidly as possible while pumping the kick fluid out of the well.


If applied properly, each method achieves constant pressure at the hole bottom and will not allow additional influx into the well. Procedural and theoretical differences make one procedure more desirable than the others.

One-Circulation Method

Fig. 4.3 depicts the one-circulation method. At Point 1, the shut-in drillpipe pressure is used to calculate the kill-weight mud. The mud weight is increased to kill density in the suction pit. As the kill mud is pumped down the drillpipe, the static drillpipe pressure is controlled to decrease linearly until at Point 2, the drillpipe pressure is zero. The heavy mud has killed the drillpipe pressure. Point 3 shows that the initial pumping pressure on the drillpipe is the total of psidp plus the kill-rate pressure. While pumping kill mud down the pipe, the circulating pressure decreases until, at Point 4, only the pumping pressure remains. From the time kill mud is at the bit until it reaches the flow line, the choke is used to control the drillpipe pressure at the final circulating pressure. The driller ensures the pump remains at the kill speed.

Two-Circulation Method

In the two-circulation method, the circulation is started immediately. Kill mud is not added in the first circulation. As seen in Fig. 4.4, the drillpipe pressure will not decrease during the first circulation. The purpose is to remove the kick fluid from the annulus.


In the second circulation, the mud weight increases, but causes a decrease from the initial pumping pressure at Point 1, to the final circulating pressure at Point 2. This pressure is held constant while the annulus is displaced with kill mud.

Concurrent Method

This method is the most difficult to execute properly (see Fig. 4.5). As soon as the kick is shut in and the pressures are read, pumping immediately begins. The mud density is increased as rapidly as rig facilities will allow. The difficulty is determining the mud density being circulated and its relative position in the drillpipe. Because this position determines the drillpipe pressures, the rate of pressure decrease may not be as consistent as in the other two methods. As a new density arrives at the bit, or a predetermined depth, the drillpipe pressure is decreased by an amount equal to the hydrostatic pressure of the new mud-weight increment. When the drillpipe is displaced with kill mud, the pumping pressure is maintained constant until kill mud reaches the flow line.

Choosing the Best Method


Determining the best well-control method for most situations involves several considerations including the time required to execute the kill procedure, the surface pressures from the kick, the complexity relative to the ease of implementation, and the downhole stresses applied to the formation during the kick-killing process. All points must be analyzed before a procedure can be selected. The following list briefly summarizes the general opinion in the industry regarding these methods:

  • The one-circulation method should be used in most cases.
  • The two-circulation method should be used if a good casing shoe exists and there is going to be a delay in weighting up the system.


The concurrent method should be used only in rare cases, such as for a severe (1.5 lbm/gal or greater) kick with a large influx and a potential problem with developing lost circulation. In this case, the pump rate should be kept to a minimum to allow the weight to be raised continuously. In an analysis of kick-killing procedures, emphasis is placed on the one- and two-circulation methods (i.e., the wait-and-weight method and the driller’s method, respectively). Inspection of the procedures will show that these are opposite approaches, while the concurrent method falls somewhere in between.

Time

Two important considerations relative to time are required for the kill procedure: initial wait time and overall time required. The first concern with time is the amount required to increase the mud density from the original weight to the final kill-weight mud. Because some operators are very concerned with pipe sticking during this time, the well-control procedure that minimizes the initial wait time is often chosen. These are the concurrent method and the two-circulation method. In both procedures, pumping begins immediately after the shut-in pressures are recorded.

The other important time consideration is the overall time required for the complete procedure to be implemented. Fig. 4.3 shows that the one-circulation method requires one complete fluid displacement (i.e., within the drillpipe and the annulus), while the two-circulation method (Fig. 4.4) requires the annulus to be displaced twice, in addition to the drillpipe displacement. In certain situations, extra time for the two-circulation method may be extensive with respect to hole stability or preventer wear.

Surface Pressures

During the course of well killing, surface pressures may approach alarming heights. This may be a problem in gas-volume expansion near the surface. The kill procedure with the least surface pressure required to balance the bottomhole formation pressure is important.

Figs. 4.6 and 4.7 show the different surface-pressure requirements for several kick situations. The first major difference is noted immediately after the drillpipe is displaced with kill mud. The amount of casing pressure required begins to decrease because of the increased kill-mud hydrostatic pressure during the one-circulation procedure. This decrease is not seen in the two-circulation method because this procedure does not circulate kill mud initially. In fact, in the two-circulation method, the casing pressure increases as the gas-bubble expansion displaces mud from the hole.


The second difference in pressure occurs as the gas approaches the surface. The two-circulation procedure has higher pressures resulting from the lower-density original mud weight. It is interesting to note these high casing pressures that are necessary to suppress the gas expansion to a small degree result in a later arrival of gas at the surface.

Procedure Complexity

Process suitability partially depends on the ease with which the procedure can be executed. The same principle holds true for well control. If a kick-killing procedure is difficult to comprehend and implement, its reliability diminishes.

The concurrent method is less reliable because of its complexity. To perform this procedure properly, the drillpipe pressure must be reduced according to the mud weight being circulated and its position in the pipe. This implies that the crew will inform the operator when a new mud weight is being pumped, that the rig facilities can maintain this increased mud-weight increment, and that the mud-weight position in the pipe can be determined by counting pump strokes. Many operators have stopped using this complex method entirely.

One- and two-circulation methods are used more prominently because of their ease of application. In both procedures, the drillpipe pressure remains constant for long intervals of time. In addition, while displacing the drillpipe with kill mud, the drillpipe pressure decrease is virtually a straight-line relationship, not staggered, as in the concurrent method (Fig. 4.5).

Downhole Stresses

Although all considerations for choosing the best method are important, the primary concern should always be the stresses imposed on the borehole wall. If the kick-imposed stresses are greater than the formation can withstand, an induced fracture occurs, creating the possibility of an underground blowout. The procedure that imposes the least downhole stress while maintaining constant pressures on the kicking zone is considered the most conducive to safe kick killing.

One way to measure downhole stresses is by use of "equivalent mud weights," or the total pressures to a depth converted to lbm/gal mud weight. For example,

Vol2 page 0205 eq 001.png....................(4.7)

where ρe = equivalent mud weight, lbm/gal.
The equivalent mud weights for the systems in Figs. 4.6 and 4.7 are presented in Figs. 4.8 and 4.9. The one-circulation method has consistently lower equivalent mud weights throughout the killing process after the drillpipe has been displaced. The procedures generally exhibit the same maximum equivalent mud weights. They occur from the time the well is shut in until the drillpipe is displaced.


Figs. 4.8 and 4.9 illustrate an important principle: maximum stresses occur very early in circulation for the deeper depth, not at the maximum casing pressure intervals. The maximum lost-circulation possibilities will not occur at the gas-to-surface conditions, as might seem logical. If a fracture is not created at shut-in, it probably will not occur throughout the remainder of the process. A full understanding of this behavior may calm operators’ concerns about formation fracturing as the gas approaches the surface.

Variables Affecting Kill Procedures


Although variables that affect kick-killing do not necessitate a change in the basic procedural structure, they may cause unexpected behaviors that can mislead an operator into choosing the wrong procedure. The one-circulation method will be used in this section to demonstrate the effect of these variables.

Influx Type

The influx type entering the wellbore plays a key role in casing-pressure behavior. The influx can range from heavy oil to fresh water. The most common is gas or salt water; each has a pronounced casing pressure curve and different downhole effects.

Gas Kicks. Gas kicks are generally more dramatic than other influx types. Reasons for this include the rate at which gas enters the wellbore, the high casing pressures resulting partially from the low-density fluid, gas expansion as it approaches the surface, fluid migration up the wellbore, and fluid flammability. A typical gas-kick casing-pressure curve is shown in Fig. 4.10.


Gas expanding from a decrease in confining pressures while the fluid is pumped up the wellbore affects the kick-killing process (Fig. 4.10). As the gas begins to expand, the previously decreasing casing pressure begins to increase at an accelerating rate. This higher casing pressure may give the false impression that another kick influx is entering the well. Immediately after the gas-to-surface conditions, the casing pressure decreases rapidly, which may give the impression that lost circulation has occurred. Both casing pressure changes are expected behaviors and do not indicate an additional influx or lost circulation. The possibility of lost circulation is smaller at the gas-to-surface conditions than at the initial shut-in conditions (Figs. 4.8 and 4.9).

When gas expands, the increased gas volume displaces fluid from the well, resulting in a pit gain. Fig. 4.11 shows the pit gain for the problem illustrated in Fig. 4.6. This pit gain is in addition to the volume increase from weight materials. Because the pit gains in volume, the flow rate exiting the well increases (Fig. 4.12).


Gas migration may cause special problems. There have been numerous recent studies of gravity-segregation phenomena in an effort to quantify a migration rate. Field data from one professional well-killing corporation suggests a rate of 7 to 15 ft/min in mud systems. Regardless of the rate, the migration effect must be considered because of the potential for gas expansion. If the fluid is not allowed to expand properly during the migration period, trapped pressure will be generated at the surface. If unnecessary expansion occurs, additional formation gas will enter the well. Example 4.3 illustrates the gas-migration phenomenon with an actual field case.


Example 4.3

While drilling a development well from an offshore platform, a kick was taken. The psidp was 850 psi, and the psic was 1,100 psi. Storm conditions forced the tender (barge) to be towed away from the platform to avoid damage to the tender or platform legs. The removal of the tender caused all support services to the platform to be severed, including the mud and pumps.

The engineer on the platform knew the kick would become a problem from gas migration up the annulus. To rectify the situation, he allowed the migration to build pressure on the drillpipe, up to 900 psi, which he used as a 50-psi safety margin. Thereafter, the migration was allowed to build the psidp up to 950 psi before he bled a small volume of mud from the annulus to reduce the drillpipe pressure down to 900 psi. Because bottomhole pressure was still 50 psi more than formation pressure, no additional influx occurred. This procedure was continued until the gas reached the surface, at which time the pressures ceased to increase and remained at 900 psi. After support services were restored to the rig, the gas was pumped from the well, and kill procedures were initiated.

This example points out the manner in which gas migration can be safely controlled with the drillpipe pressure acting as a bottomhole pressure indicator.


Saltwater Kicks.

Saltwater-kick problems differ from gas-kick problems. Volume expansion does not occur. Because salt water is more dense than gas, casing pressures are lower than for a comparable volume of gas (Fig. 4.13). Shut-in pressures for the 50-bbl (7.9-m3) saltwater kick are approximately the same as those seen in Fig. 4.6 for a 20-bbl (3.2-m3) gas kick under the same conditions.


Hole stability and pipe sticking are generally more severe with a saltwater kick than a gas kick. The saltwater fluid causes a freshwater mud-filter cake to flocculate and create pipe-sticking tendencies and unstable hole conditions. The severity increases with large kick volumes and extended waiting periods before the fluid is pumped from the hole.

Volume of Influx

The fluid volume entering the well is a variable controlling the casing pressure throughout the kill process. Increased influx volumes give rise to higher initial psic, as well as greater pressure differences at the gas-to-surface conditions. Fig. 4.14 depicts the importance of quick closure over closure with hesitation.

Kill-Weight Increment Variations

The original mud density must be increased in most kick situations to kill the well. The incremental density increase has some effect on casing pressure behavior. In Fig. 4.15, the gas-to-surface pressure conditions are higher than the original shut-in pressures for 0.5-lbm/gal (60-kg/m3) and 1.0-lbm/gal (120-kg/m3) kicks. The 2.0-lbm/gal (240-kg/m3) and 3.0-lbm/gal (360-kg/m3) mud weight increases do not show this tendency. The 3.0-lbm/gal (360-kg/m3) kick has a lower gas-to-surface pressure than at the initial closure. This is caused by suppressed gas expansion, which minimizes the associated pressures. This is generally observed in kicks requiring greater than a 2.0-lbm/gal (240-kg/m3) incremental increase.


An important mud-weight variation is the difference between the kill-mud weight necessary to balance bottomhole pressure and the mud weight actually circulated. If the circulated mud is less than the kill-mud weight, the casing pressure is higher than if kill mud had been used because it was necessary to maintain a balanced pressure at the hole bottom (Figs. 4.6 and 4.7). The equivalent mud weights will then be greater, increasing formation fracture possibility.

Circulated mud weights greater than the calculated kill mud weight do not decrease the casing pressure. The situation is synonymous with mud-weight safety factors and is termed "overkill." As the extra-heavy mud is pumped down the drillpipe, the U-tube effect (Fig. 4.16) causes the casing pressure to increase (Fig. 4.17). The U-tube principle states that the pressures on each side of the tube must be equal. These higher casing pressures have associated downhole stresses that increase formation fracture potential.


Several attempts have been made to achieve the benefits of "safety factors" while avoiding the ill effects of high casing pressures caused by the U-tube effect. The most common attempt at this effort is to subtract the hydrostatic pressure supplied by the extra mud-weight increment from the final circulating pressure, creating a net-zero effect from the added mud weight.

In a static situation, the casing pressure is reduced by an amount equal to the safety-factor hydrostatic pressure, which results in a zero net effect. From a theoretical standpoint, the approach is based on sound principles; however, field experience has shown that this procedure is not practical because of its complexity. This procedure is not necessary for proper well control, and only experienced well-control engineers should use it.

Hole Geometry Variations

In practical kick-killing situations, hole- and drillstring-size changes cause the kick fluid geometry to be altered. This is particularly a problem in deep tapered holes in which several pipe and hole sizes are used. The influx may occupy a large vertical space at the hole bottom, creating a high casing pressure. As the fluid is pumped into the larger annular spaces, the vertical height is decreased, thus increasing the mud column height and resulting in lower casing pressures. Figs. 4.18a through 4.18c show a typical tapered hole and the associated casing and drillpipe pressure curves.

Implementation of the One-Circulation Method


To implement the one-circulation method, certain guidelines must be followed to ensure a safe kick-killing exercise. Although the procedure is relatively simple, its mastery demands basic knowledge of the practical steps taken during the process. Checkpoints indicate potential problems.

A kill sheet is normally used during conventional operations. It contains prerecorded data, formulas for the various calculations, and a graph—or other means—for determining the required pressures on the drillpipe as the kill mud is pumped. Although many operators have complex kill sheets, only the basic required kick-killing data is necessary. A kill sheet is shown in the example problem in the following section.
A summary of the steps involved in proper kick killing follows. The sections not directly applicable to deepwater situations are noted. When a kick occurs, shut in the well using the appropriate shut-in procedures. Once the pressures have stabilized, follow these steps to kill the kick:

  1. Read and record the shut-in drillpipe pressure, the shut-in casing pressure, and the pit gain. If a float valve is in the drillpipe, use the established procedures to obtain the shut-in drillpipe pressure.
  2. Check the drillpipe for trapped pressure.
  3. Calculate the exact mud weight necessary to kill the well and prepare a kill sheet.
  4. Mix the kill mud in the suction pit. It is not necessary to weight up the complete surface-mud volume, initially. First pump some mud into the reserve pits.
  5. Initiate circulation after the kill mud has been mixed, by adjusting the choke to hold the casing pressure at the shut-in value, while the driller starts the mud pumps. (Not applicable in deep water.)
  6. Use the choke to adjust the pumping pressure according to the kill sheet while the driller displaces the drillpipe with the exact kill-mud weight at a constant pump rate (kill rate).
  7. Consider shutting down the pumps and closing the choke to record pressures when the drillpipe has been displaced with kill mud. (Note: If the kill mud is highly weighted up, settling and plugging may occur.) The drillpipe pressure should be zero, and the casing should have pressure remaining. If the pressure on the drillpipe is not zero, execute the following steps:
    • Check for trapped pressure using the established procedures. If the drillpipe pressure is still not zero, pump an additional 10 to 20 bbl (1.5 to 3 m3) to ensure that kill mud has reached the bit. The pump efficiency may be reduced at the low circulation rate.
    • If pressure remains on the drillpipe, recalculate the kill mud weight, prepare a new kill sheet, and return to the first steps of this procedure.
  8. Maintain the drillpipe pumping pressure and pumping rate constant to displace the annulus with the kill mud by using the choke to adjust the pressures, as necessary.
  9. Shut down the pumps and close the choke after the kill mud has reached the flow line. The well should be dead. If pressure remains on the casing, continue circulation until the annulus is dead.
  10. Open the annular preventers, circulate and condition the mud, and add a trip margin when the pressures on the drillpipe and casing are zero. In subsea applications, the trapped gas under the annular is circulated out by pumping down the kill line and up the choke line with the ram preventer below the annular closed. The riser must then be circulated with kill mud by reverse circulation, down the choke line and up the riser, before the preventers can be opened.



Well-control learning experiences are often best accomplished by observing an actual kick problem. Example 4.4 has been provided for this purpose.



Example 4.4 -- Prekick Considerations

While drilling the R.B. Texas No. 1 in the Louisiana Gulf Coast offshore area, a company representative carried out his normal drilling responsibilities related to well control in the event that a kick should occur. Some items that the representative did are listed below:

  • Read the appropriate MMS orders and complied with the provisions.
  • Checked the barite supplies to ensure that a sufficient amount of barite was on board to kill a 1.0-lbm/gal kick, if necessary.
  • Recorded on the driller’s book that the kill rate was 21 spm and 800-psi pump pressure.
  • Calculated the drillstring volume as follows:


4½-in. drillpipe to 14,000 ft.

6½×2-in. drill collars to 15,000 ft.

4½-in., 16.6-lbf pipe capacity

= 0.01422 bbl/ft×14,000 ft =199 bbl

6½×2-in. collar capacity

=0.0039 bbl/ft×1,000 ft = 3.9 bbl

Total = 199 + 3.9 = 202.9 bbl



Shut-In and Weight-Up Procedures.

The drillers on the rig had just changed tours when a drilling break was observed. The well was checked for flow. A flow was recorded with the pumps off, and the following steps were taken:

  1. The kelly was raised until a tool joint cleared the floor. (A jackup rig was in use.)
  2. The pumps were shut down.
  3. The annular preventer was closed.
  4. The company representative was notified that the well was shut in.
  5. The driller told his crew in the mudroom to stand by in case the mud weight had to be increased. Then, the company representative went to the floor and read the pressures as follows:

psidp = 240 psi

psic = 375 psi

Pit gain = 31 bbl

After checking for trapped pressures, he recorded the information on his kill sheet. From the kill sheet, he calculated that he needed to raise the mud weight from the 13.1-lbm/gal original weight to 13.4 lbm/gal. He was walking to the mudroom, to tell the derrickman that he needed 13.4-lbm/gal kill mud, when he noticed the pits were almost full. He knew the needed barite would raise the mud level, so he instructed the derrickman to pump off a foot of mud, section off the suction pit, and increase the weight to 13.4 lbm/gal. The representative judged that it would be better to pump off the mud at that time, rather than after the killing operation was started.

Pump Rates.

The pump output was read from the mud engineer’s report as 5.2 strokes/bbl for the 6×18-in. duplex mud pump. The volumetric output at 21 spm was 0.1916 stroke/bbl×21 spm = 4.0 bbl/min. The representative knew he could cripple his pumps according to the chart previously provided to him but felt that 4.0 bbl/min was not much more than the recommended 1 to 3 bbl/min as a kill rate.

Kill Sheet Preparation.

The representative prepared his kill sheet as shown in Fig. 4.19.


Working the Pipe.

While the mud weight was increased and the kill sheet was being prepared, the driller was instructed to work the pipe every 10 minutes by moving it up and down. He was also instructed not to move a tool joint through the annular preventer.

Displacing the Drillpipe.

After the mud was weighted to 13.4 lbm/gal, the representative was ready to displace the drillpipe. He instructed the driller to start his pumps and run them at 21 spm. Then, he cracked open the choke slightly and held his casing pressure at 375 psi until the driller had the pumps at the kill rate. The choke was used to control the drillpipe pressure to decrease it gradually according to values on his kill sheet. The pressures were maintained as shown in Table 4.10.


When the drillpipe had been displaced, the pump was shut down and the choke was closed. The pressures were then as follows:

psidp = 0 psi psic = 350 psi

The pressure on the drillpipe told the representative that the heavier kill-mud weight was sufficient to kill the well. If it had not been of sufficient density, some pressure would have remained on the drillpipe.

Displacing the Annulus.

The representative was now ready to displace the annulus with kill mud. He initiated pumping by adjusting his choke to maintain 350 psi on the casing while the driller started the pumps. After the pumps were running at 21 spm, he used the choke to maintain the drillpipe pressure constant at the final circulating pressure of 820 psi. He held this pressure until a 13.4-lbm/gal mud weight was observed at the shaker, at which time he closed in the well. The drillpipe and casing had zero pressure. The choke and the annular preventer were opened. The well was dead.

Post-Kick Considerations.

There are several items that the representative considered after the well was dead to ensure that the procedure was complete. He circulated and conditioned the mud in the hole and added a trip margin to the mud weight so that he could make a short trip. Additional barite was ordered from the mud company to resupply the bulk tank. He also took time to inspect his equipment to identify any damage sustained from the kick.

Nonconventional Well-Control Procedures


Many attempts have been made to develop well-control procedures based on principles other than the constant-bottomhole-pressure concept. These procedures may be based on specific problems peculiar to a geological area. One example is low-permeability, high-pressured formations contiguous to structurally weak rocks that cannot withstand hydrostatic kill pressures. Often, nonconventional procedures are used to overcome problem situations that result from poor well design.

Nomenclature


d = other drilling equations
De = depth equivalent, ft
Dtv = true vertical depth, bit depth, ft
gi = influx gradient, psi/ft
gmdp = mud gradient in drillpipe, psi/ft
hi = influx height, ft
pah = annular hydrostatic pressure, psi
ρe = equivalent mud weight, lbm/gal
pdph = drillpipe hydrostatic pressure, psi
pform = formation pressure, psi
pi = influx-hydrostatic pressure, psi
pkr = pump pressure at kill rate, psi
ρkw = kill mud weight, lbm/gal
ρo = original mud weight, lbm/gal
psic = shut-in casing pressure, psi
psidp = shut-in drillpipe pressure, psi
pΣ = total pressure, psi

General References


Abel, L.W., Bowden, J.R., and Campbell, P.J. 1996. Firefighting Blowout Control. Tulsa, Oklahoma: Wild Well Control Incorporated.

Adams, N.J. 1975. Low-choke-pressure method of well control generally not recommended. Oil Gas J. 73 (39): 109-115.

Adams, N.J. 1977. Deep Water Poses Unique Well Control Problems. Petroleum Engineer. (May 1977).

Adams, N. 1979. Well control. Part 1. Pressures define well control objectives. Oil Gas J. 77 (41): 63-66.

Adams, N. 1979. Well control. Part 2. Kicks give clear warning signs. Oil Gas J. 77: 132-136, 141-142.

Adams, N. 1979. Well control. Part 3. Drilling variables fix kick control method. Oil Gas J. 87: 155-156, 158-159.

Adams, N. 1979. Well control. Part 4. Variables can affect kill procedure. Oil Gas J. 77: 242, 247-248, 250.

Adams, N. 1979. Well control. Part 5. How to implement the one-circulation method. Oil Gas J. 77: 54-56.

Adams, N.J. 1980. Deepwater Kick--Control Methods Take Special Planning. Oil Gas J. 78 (4 February).

Adams, N. 1980. Well control. Part 11. Nonconventional control methods may offer emergency solutions. Oil Gas J. 78: 92-94,99-102.

Adams, N.J. 1980. Well Control Problems and Solutions. Tulsa, Oklahoma, USA: Petroleum Publishing Company.

Adams, N.J. 1981. Workover Well Control. Tulsa, Oklahoma, USA: Petroleum Publishing Company.

Adams, N.J. 1985. Drilling Engineering: A Well Planning Approach. Tulsa, Oklahoma, USA: PennWell Publishing Company.

Adams, N.J. 1994. Kicks and Blowout Control, Second edition. Houston, Texas, USA: Gulf Publishing Company.

Grace, R.D. 1994. Advanced Blowout and Well Control. Houston, Texas, USA: Gulf Publishing Company.

Holand, P. 1997. Offshore Blowouts. Burlington: Gulf Professional Publishing. http://www.sciencedirect.com/science/book/9780884155140.

Westergaard, R.H. 1987. All About Blowout. Oslo, Norway: Norwegian Oil Review.

SI Metric Conversion Factors


bbl × 1.589 873 E–01 = m3
ft × 3.048* E–01 = m
ft3 × 2.831 685 E–02 = m3
ft/min × 5.080* E–03 = m/sec
in × 2.54* E+00 = cm
kg/m × 1.488 164 E+00 = lbm/ft
lbf × 4.448 222 E+00 = N
lbm/gal × 9.977 633 E+01 = kg/m3
MPa × 1.378 951 E+01 = Pa
psi × 6.894 757 E+00 = kPa
psi/ft × 2.262 059 E+01 = Pa/m
*Conversion factor is exact.