Shut-in procedures for well control

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.

Overview

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 1 shows an example of higher casing pressures resulting from continuous flow because of failure to close in the well.

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  Table 1-The Effect of Continuous Influx On The Casing Pressure Resulting From 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 p_sidp. Shut-in casing pressure is p_sic. (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. 1 and 2 express this relationship for the drillpipe and the annular side, respectively:

....................(1)

where p_sidp = shut-in drillpipe pressure, psi; p_dph = drillpipe hydrostatic pressure, psi; p_form = formation pressure, psi; and

....................(2)

where p_sic = shut-in casing pressure, psi; p_ah = annular-hydrostatic pressure, psi; and p_i = influx-hydrostatic pressure, psi.

Example 1 and Fig. 1 show how the shut-in pressures are read.

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  Fig. 1—Pressure relationships at shut-in conditions.

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Example 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 2.

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  Table 2-Shut-In Pressure And Pit Gain

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

p_sidp = 780 psi

p_sic = 1,040 psi

Pit gain = 20 bbl

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Interpreting recorded pressures

An important basic principle can be seen in Fig. 1. It shows that formation pressure (p_form) is greater than the drillpipe hydrostatic pressure by an amount equal to the p_sidp. 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. 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 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 3.

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  Table 3-Guidelines To Check For Trapped Pressure

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 describes the procedures to obtain the drillpipe pressure if the slow pumping rate (kill rate) is known. Table 5 outlines the procedure if the kill rate is not known; Fig. 2 illustrates this process.

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  Table 4-Procedures To Establish The Shut-In Drillpipe Pressure If The Kill Rate Is Not Known

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  Table 5-Procedures To Establish Shut-In Drillpipe Pressure If The Kill rate Is Known

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  Fig. 2—Procedure to establish the shut-in drillpipe pressure when the kill rate is not known.

Table 4 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. 3),

....................(3)

could be modified to

....................(4)

where p_kr = pump pressure at kill rate, psi, and p_Σ = total pressure, psi.

The procedures in Table 4 remain the same, with the exception that Eq. 4 would be substituted for Eq. 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 5 must be used initially to determine the p_sidp, after which Eq. 4 and Table 4 must be implemented to establish the kill rate.

Nomenclature

pah	= annular hydrostatic pressure, psi
pdph	= drillpipe hydrostatic pressure, psi
pform	= formation pressure, psi
pi	= influx-hydrostatic pressure, psi
pkr	= pump pressure at kill rate, psi
psic	= shut-in casing pressure, psi
psidp	= shut-in drillpipe pressure, psi
pΣ	= total pressure, psi

Noteworthy papers in OnePetro

Liv A. Carlsen, Gerhard Nygaard, Jan Einar Gravdal, Michael Nikolaou, and Jerome Schubert 2008. Performing the Dynamic Shut-In Procedure Because of a Kick Incident When Using Automatic Coordinated Control of Pump Rates and Choke-Valve Opening, SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference and Exhibition, 28-29 January. 113693-MS. http://dx.doi.org/10.2118/113693-MS

Matthews, J.L., Bourgoyne Jr., A.T. 1983. Techniques for Handling Upward Migration of Gas Kicks in a Shut-In Well, IADC/SPE Drilling Conference , 20-23 February. 11376-MS. http://dx.doi.org/10.2118/11376-MS

See also

Kicks

Well control

Variables affecting kill procedures

PEH:Well_Control:_Procedures_and_Principles