Methods of killing a well after a kick

Killing a well or controlling a kick is stopping a well from flowing or having the ability to stop formation fluid (gas, oil or water) to flow into the wellbore. Kill procedures typically involve circulating reservoir or formation fluids out of the wellbore or pumping higher density mud into the wellbore, or both.

What is a Kick

Kick is defined as an undesirable influx of formation fluid into the wellbore. If left unchecked, a kick can develop into a blowout (an uncontrolled influx of formation fluid into the wellbore). The result of failing to control a kick leads to lost operation time, loss of well and quite possibly, the loss of the rig and lives of personnel.

Warning signs of a kick

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

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

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

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

Pump pressure decrease and pump stroke increase

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 fluid and the pump pressure may begin to decrease. As the fluid in the annulus becomes less dense, the mud in the drill pipe 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

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

Drilling fluid provides a buoyant effect to the drill string and reduces the actual pipe weight supported by the derrick. Heavier mud have a greater buoyant force than less dense mud. 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

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 top hole 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

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, Aerated mud circulated from the pits and down the drill pipe

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. 

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.

Primary well control

Primary well control is the process of maintaining hydrostatic pressure in the wellbore greater than the formation pressure being drilled, but less than formation fracture pressure. If hydrostatic pressure is less than formation pressure then formation fluids will enter the wellbore. If the hydrostatic pressure of the fluid in the wellbore exceeds the fracture pressure of the formation then the fluid in the well could be lost. In an extreme case of lost circulation the formation pressure may exceed hydrostatic pressure allowing formation fluids to enter into the well.

Secondary well control

Primary well control failed when the hydrostatic pressure in the well (i.e. drilling mud) fail to prevent formation fluids from entering the wellbore. Therefore, a secondary well control is introduced with special equipment called “Blow Out Preventer” or BOP to control unwanted formation fluids in the wellbore.

In order to control a kick, mud of the required density must be added and circulated while back pressure is maintained against the formation. This excess pressure must be slightly higher than the pressure of the fluids contained in the pores of the formation.

There is therefore a need for a line, the choke line, between the annulus and a manifold which directs the effluent to one of the following, depending on the type of fluid involved: mud tanks, degasser, flare, reserve pit

Methods of killing a well

Common circulating well methods of killing a well or well control techniques are:

• Driller’s method
• Wait and Weight
• Concurrent

These all use the same procedures and only differ when and if a kill weight fluid will be circulated.

• Volumetric Method & Lubricate and Bleed
• Reverse Circulation
• Bullheading

The Driller’s Method Procedure

• Shut-in well after kick: Close the annular preventer of Blow out Preventer (BOP). Open HCR valve (Hydraulically control remote valve) to the choke manifold.
• Record kick size and stabilized shut in drill pipe pressure (SIDPP) and shut in casing pressure (SICP).
• As soon as possible start circulating original mud (fluid) by gradually bringing the pump up to the desired kill rate while using the choke to maintain constant casing pressure at the shut-in value.
• Pump pressure should be equivalent to calculated initial circulating pressure (ICP). If not equivalent, investigate and recalculate if necessary.
• Maintaining pump pressure equal to ICP, kick/influx is circulated out of the well, adjusting pressure with choke as required. After Kick Circulated Out –Killing The Well:
• Continue to circulate from an isolated pit or slowly shut down the pump maintaining pressure on the choke (casing) gauge equivalent to the original SIDPP.
• Avoid trapping pressure or allowing additional influx if shutting back in – Avoid trapping pressure or allowing additional influx if shutting back in.
• The active system should be weighted up to the pre-determined kill fluid density and circulated in order to regain hydrostatic control.
• If the well was shut in, startup pump procedures are again used.
• It is advisable to calculate and use a pressure vs. stroke chart (ICP to FCP – final circulating pressure) to track the kill fluid and changes in circulating pressures.
• Circulate the kill fluid to the bit/end of string.

After Kick Circulated Out –Killing The Well:

• Once kill fluid is at the bit/end of string, FCP should be realized.
• Circulating pressure should be equivalent to the calculated FCP.
• Maintain constant FCP circulating pressure until the kill fluid completely fills the well.
• The gain in hydrostatic pressure (HP) should necessitate slowly reducing choke pressure.
• Once the kill fluid reaches surface, the choke should have been fully opened.
• Shut down pump and check for flow.
• Close choke and check pressures.
• If no pressure is noted, open choke (bleeding any trapped pressure), open BOP.

Wait and Weight Method Procedure

• Shut-in well after kick. Close the annular preventer of Blow out Preventer (BOP). Open HCR valve (Hydraulically control remote valve) to the choke manifold.

2. Record kick size and stabilized SIDPP and SICP, calculate kill fluid density.

3. Pits are weighted up as other calculations are performed.

4. If there are increases in shut-in pressure, the Volumetric Method should be used to bleed off mud/fluid from the annulus to maintain constant stabilized drill pipe/tubing pressure.

5. Once pits are weighted, start circulating kill weight fluid by gradually bringing up the pump up to the kill rate while using the choke to maintain constant casing pressure at the shut-in value. Remember to hold pump rate constant.

6. Circulating pressure should be equivalent to (ICP) Initial Circulating Pressure. If not, investigate and recalculate ICP if necessary.

7. Follow pressure chart/graph as kill fluid is pumped down the string to bit/end of string.

8. Once kill fluid is at the bit/end of string, FCP should be realized.

• Circulating pressure should be equivalent to the calculated FCP.

9. Maintain constant FCP circulating pressure until the kill fluid completely fills the well.

• The gain in HP should necessitate slowly reducing choke pressure.
• Once the kill fluid reaches surface the choke should have been fully opened.

10. Shut down pump and check for flow.

11. Close choke and check pressures.

12. If no pressure is noted, open choke (bleeding any trapped pressure), open BOP.

Concurrent Method

Sometimes referred to as the Circulate and Weight Method or Slow Weight-Up Method. It involves gradually weighting up fluid while circulating out the kick.

Additional calculations are required when tracking different fluid weights in the string at irregular intervals.

Sometimes, crew members are required to record concurrent method data even if this is not the method intended to be used.

The Concurrent Method Procedure:

• Shut-in well after kick. Close the annular preventer of Blow out Preventer (BOP). Open HCR valve (Hydraulically control remote valve) to the choke manifold.

2. Record kick size and stabilized SIDPP and SICP.

3. ASAP start circulating original mud (fluid) by gradually bringing the pump up to the desired kill rate while using the choke to maintain constant casing pressure at the shut-in value.

• Pump pressure should be equivalent to calculated ICP. If not equivalent, investigate and recalculate if necessary.

4. Mixing operations begin and pits are slowly weighted up and each unit of heavier fluid reported.

5. Each interval or unit of increased fluid density is then noted and recorded with the pump stroke count at that time.

• The change in circulating pressure for the different density is calculated.
• Once this fluid reaches the bit/end of tubing, circulating pressure is adjusted with the choke by that amount.

6. The kick is circulated out and the fluid in the well continues to be gradually increased.

7. Once the kill fluid is consistent throughout the well, shut down pump and check for flow.

8. Close choke, shut well in and check pressures.

9. If no pressure is noted, open choke (bleeding any trapped pressure), open BOP.

Volumetric Method of Well Control

The volumetric method is a way of allowing controlled expansion of gas during migration

• It replaces volume with pressure (or vice versa) to maintain bottom hole pressure that is equal to, or a little higher than BHP, and below the formation fracture pressure.

With a swabbed in kick, the volumetric method can be used to bring influx to surface and then replace the gas with fluid in order to return the well to normal hydrostatic pressure. It is not used to weight up and kill the well.

• Used to control the well until a circulating method can be implemented.
• Can be used to regain HP if the existing fluid is adequate and gas is allowed to reach surface.

Situations where Volumetric Methods can be used:

• String is plugged.
• String is out of the hole.
• Pumps are not working.
• String is off bottom.
• During stripping or snubbing.
• A shut-in period or repairs to surface equipment.
• Tubing or packer leak causes casing pressure to develop on production or injection well.
• A washout in string prevents displacement of kick by one of the circulating methods.
• In subsea operations only 1 line should be used to prevent gas separation effects.

If casing pressure does not increase 30 minutes after a kick is shut in, gas migration is minimal. This means that the Volumetric Method need not be used. However, if casing pressures continues to increase there is a need to initiate Volumetric techniques.

• Some basic scientific principles must be understood before using the Volumetric Method:

Boyle’s Law–shows the pressure/volume relationship for gas. It states that if gas is allowed to expand, pressure within the gas will decrease. This is the same concept used by the Volumetric Method in that it allows gas to expand by bleeding off an estimated fluid volume at surface, which results in decreasing of wellbore pressures.

Boyle’s LawP1 V1 = P2 V2

Single Bubble Theory–The biggest misconception in well control schools is that the gas enters the well as a “single bubble”.

• In reality it is dispersed as pumping and observance of the kick is noted, then more “pure” kick as the pumps are shut down and well is shut in.
• It may be many minutes before the kick is actually noted resulting in an annulus filled with influx/regular fluid.
• So, in reality, a single large kick rarely occurs, and once the well is shut in, the pressures on the casing shoe/weak zone have probably reached it’s maximum.
• This is not to say that MAASP should not be observed, just that it should be considered that the maximum pressure should be based on the latest pressure test of the BOP or casing.

Stripping/Moving Pipe and Volumetric Considerations

A stripping pressure schedule must be created in order to control pressures during stripping operations while gas is migrating, pipe is moving, and fluid is being bled off at choke.

Lubricate & Bleed (Lubrication)

 The Lubricate & Bleed Method is used when kick fluid reaches the wellhead.

 It is considered a continuation of the Volumetric Method.

 Generally, workover operations more commonly use the Lubricate and Bleed technique because circulating ports in the tubing are plugged, sanded tubing, or circulation is not possible.

Lubricate & Bleed (Lubrication)

 In this method, fluid is pumped into the well on the annulus side.

 Enough time must be allowed for fluid to fall below gas.

 Volume must be precisely measured so hydrostatic pressure gain in the well can be calculated.

 This value increase will then be bled off at surface.

Reverse Circulation Method of Well Control

 Reverse circulation is the reversal of normal circulation or normal well kill pump direction.

 In reverse circulation, due to friction (APL, ECD) most of the circulating pump pressure is exerted on the annulus.

 Standard start up procedures apply.

Advantage

1. It is the quickest method of circulating something to the surface.

2. Gets the problem inside the strongest pipe from the beginning.

3. Generally, the annular fluid is dense enough to maintain control of the formation, which reduces fluid mixing and weighting requirements.

Disadvantage

1. Higher pressure is placed on formation and casing.

2. Excessive pressure may cause fluid losses/casing and/or formation failures.

3. Not applicable for uses where plugging of circulating ports, bit nozzles of string are possible.

4. Gas filled or multiple densities in tubing may present problems establishing proper circulating rates.

Bullheading Method of Well Control

 Bullheading, or deadheading, is often used as a method of killing wells in workover situations.

 Bullheading is only possible when there are no obstructions in the tubing and there can be injection in the formation without exceeding pressure restraints.

 Bullheading involves pumping back well fluid into the reservoir, displacing the tubing or casing with a good amount of kill fluid.

Complications can make bullheading difficult in certain situations:

– Sometimes, when bullheading down the tubing, pressure may have to be exerted on the casing in order to prevent the tubing from collapsing. Both, tubing and casing burst/collapse pressures, should be known and not exceeded.

– Formation fracture pressure may have to be exceeded due to low reservoir permeability

– Gas migration through the “kill fluid” can pose a problem. In this situation, viscosifiers should be added to the kill fluid to minimize the effect of migration.

Bullheading Procedure

1. Well is shut in and formation pressure is calculated. If bullheading down the tubing, maximum pressures should be calculated.

2. Prepare a rough pressure chart of volume pumped versus maximum pressures at surface. Friction and formation pressure must be overcome to achieve injection of the liquid in the tubing back into the formation. If pressures or pump rate is too high, damage to the formation may occur.

3. Once the pumped liquid reaches the formation, an increase in pump pressure may occur. This is due to a non-native fluid injected to the formation.

4. Once the calculated amount of fluid is pumped, shut down, observe pressures. If no pressure increase is observed, bleed off injection pressure and, again, observe. If no pressure change is seen, the well should be dead. Proceed operations with caution.