Special Kick Problems and Procedures:� The majority of problems which occur during well control operations are caused by equipment failure, formation breakdown or improper operating procedures.
Excessive Casing Pressure:� Mechanical failure or formation breakdown can occur if excessive casing pressure is allowed to build up. Mechanical failure at the surface can be catastrophic, while formation breakdown can lead to lost circulation, an underground blowout and/or possible surface fracturing. A “maximum allowable casing pressure” must be determined and if casing pressure rises to this maximum level during the initial closing of the well, a decision must be made whether or not to shut-in the well. If excessive casing pressures occur, the following alternatives may be considered:
1. The “Low Choke” procedure
2. Turn the well loose
3. Close in the well and consider bullheading
With the correct casing design, equipment selection and frequent testing of the surface equipment, the chances of mechanical failure are greatly reduced.
Formation breakdown can also be catastrophic, especially if the last casing shoe is shallow, with the possibility of fractures reaching the surface.
If the maximum casing pressure is reached while circulating out a kick, the decision must be made whether to:
1. Controlled circulation of the kick with drillpipe pressure while allowing the casing pressure to increase. This can lead to mechanical failure of the casing and/or formation breakdown.
2. Adjust the choke to hold the maximum allowable casing pressure and follow the low choke procedure until the well can be shut-in. However, the control of a high volume gas flow using the low choke method is extremely difficult.
3. Close in the well and bullhead the kick back down the annulus to reduce casing pressure or spot a pill of heavy mud or cement. This may also cause formation breakdown. If the casing pressure is likely to exceed that of the surface equipment, or if the possibility of surface fracturing due to casing or formation failure exists, the well cannot be shut-in. As stated earlier, if these conditions exist the alternatives include using the low choke pressure procedure, pumping a barite pill, pumping cement, or allowing the well to flow until pressure is reduced. If the surface equipment rating will not be exceeded and fracturing to the surface is not likely, consideration can be given to shutting in the well and allowing formation breakdown to occur.
The Low Choke procedure consists of circulating and weighting up the mud at its maximum density, while maintaining the maximum allowable casing pressure on the choke. The influx will continue to flow into the well until the mud has been sufficiently weighted and this may take several circulations. The required kill mud density will not be known as the drillpipe pressure is not allowed to stabilize upon initial closure. After some heavier fluid has been circulated, the well may be shut-in and an estimate of the required kill mud density can be made.
When using the Low Choke method, the weight material should be added to the mud system as rapidly as possible, while applying the maximum allowable casing pressure, because the annular pressure drop will aid this method. The highest possible circulation rates possible should be used (except in the case of subsea BOP stacks where the choke line friction will be excessive. In these cases, the returns should be circulated up both the choke and kill lines, and circulation carried out at the maximum rate that will not cause shoe breakdown due to the imposed choke and kill line friction pressures).
Low Choke Pressure Procedure:
1. Circulate using the maximum pump rate.
2. Start weighting up the mud to the “estimated” kill mud density.
3. Begin circulating, while holding the maximum allowable casing pressure by adjusting the choke. Care must be taken, and observe for lost circulation.
4. Circulate out the kick fluid until it reduces the choke opening in order to maintain the maximum allowable casing pressure.
5. Shut-in the well and record the shut-in drill pipe and shut-in casing pressures.
The wait and weight (engineers) method or the concurrent kill method can now be used. To obtain the initial circulating pressure, multiply the prerecorded kill rate pressure by the ratio of the present fluid density to the drilling fluid density used to obtain the kill rate and add it to the shut-in drill pipe pressure.
6. If the casing pressure cannot be reduced sufficiently for the well to be safely shut-in, or the well cannot be killed, preparations must be made for either a barite or cement plug to seal the kicking formation.
Kick Occurs While Running Casing or Liner
Running liner: Kicks that occur while running liner can be handled in a similar manner to a kick that occurs while drilling. If the liner is near bottom, an attempt should be made to strip into the hole. The kick can then be circulated out, the hole conditioned and the liner cemented in place. In some cases it may be necessary to strip the liner back into the casing shoe to prevent the liner from sticking. The annular pressure can be reduced by bullheading heavy drilling fluid into the well to overbalance the kick pressure, but when running of more liner into the hole, it may displace some of the heavy fluid and may start the well flowing again. In addition, pumping high density fluid into the annulus may result in lost circulation problems. Once the kick is killed, the liner should be tripped out and the hole conditioned for rerunning the liner. If the liner has not been run to the shoe, an attempt should be made to strip to the shoe, but not into the open hole.
Running casing: A kick that occurs while running casing can lead to extreme problems. Stripping the casing to bottom should only be attempted if the guide shoe is within a few joints of bottom. If only a short section of casing is in the hole, the annular pressure will tend to force it upwards, in which case the casing will need to be tied down and filled with drilling fluid immediately. With a long section of casing, it becomes more likely that the combination of tensional forces, the annulus pressure, and the pressure exerted by the BOP’s (in subsea wells) will collapse the casing. If it is possible, annular preventers should be closed slowly with the choke wide open. Due to the small annulus around the relatively large casing, pump rates will tend to be slower and the fill up of the casing with kill fluid will take much longer. Gas entering the bore hole and casing can continue migrating and may complicate pressure calculations. The dangers of lost circulation and an underground blowout are increased due to the small annulus. As a last resort to gain control, a barite plug may be used or the casing cemented (if not at bottom) at the present depth.
Parted or Washed-Out Drillstring
If the drill string develops a washout, every consideration should be given to preventing washout-hole enlargement. Circulation, rotation and pipe movement should be performed carefully to minimize the chances of the string parting. The procedures are the same for a parted string, a washed out string, or with the bit off bottom that cannot be stripped back to bottom.
The following procedures are recommended:
- Locate the point where the string is parted or washed out.
2. Observe the SIDP and SICP. If the SIDP is not significantly lower than the SICP the influx is still below the washout or bit (if the bit is off bottom).
3. If the influx is below the washout (or bit) it must be allowed to percolate upwards. Circulating above the influx serves no purpose in removal of the influx. As the gas percolates upwards it will expand and the excess pressure must be bled off carefully to prevent further influx.
4. When the influx rises above the washout (or bit) the SICP will be higher than the SIDP. The influx may then be circulated out conventionally and the density of the kill fluid can be calculated using the following equation:
KMD (ppg) = SIDP / TVD (of washout/bit/end of string) x 0.0519
The well will not have been successfully killed until the drillstring is run back to bottom and all influx fluids are displaced and replaced with a suitable drilling fluid to maintain control.
Underground Blowout
This is an uncontrolled flow of formation fluids from a high pressure zone into a lower pressure zone. The loss of drill pipe pressure with changes in annular pressure, the loss of large volumes of drilling fluid, or the total loss of drilling fluid returns, characterizes underground blowouts. A common cause is the fracturing of formations below the casing shoe by excessive annular pressures. If the flow is not too severe, it may be possible to pump LCM in a light fluid, or a “gunk squeeze” down the annulus while killing the high pressure zone down the drillpipe with heavy mud.
The direction of fluid flow is an important concern when choosing a control procedure. The cause of the blowout will often indicate the direction of flow. If the cause is thought to be the fracturing of a formation due to shutting in a kick, the direction of fluid flow will generally be upward (assuming that shallow zones are more likely to fracture than deeper zones and that the initial kick zone is the primary source of formation fluid).
If, however, a zone of lost circulation is encountered at the bit, the flow may be from a shallower zone to a deeper zone. The loss of hydrostatic head may induce an upper zone to kick. While the flow will generally be to the zone of lost returns, this is not always the case. One method of killing an underground blowout is:
1. As soon as the symptoms are recognized;
a. Request or rig up a logging unit for a temperature log and noise log
b. Start increasing the mud density in the pits
c. Kill the drill pipe side with the heavy mud
d. Continue to pump a few barrels of mud every 30 minutes to keep the bit from plugging
e. If the drillpipe sticks, pull and stretch the pipe to prevent buckling above the free point.
2. Rig up the wireline logging unit and run the temperature log going down the drillpipe and the noise log while pulling out.
a. Determine the point of fluid entry and fluid exit
b. Calculate the mud density required to kill the well between the point of entry and the point of exit. The calculated mud density may exceed 20 ppg. In this case, use the highest mud density that can be mixed and pumped.
- Mix a minimum of 3 times the hole volume of either the required mud density or the maximum pumpable density.
Simultaneously;
a. Ensure pumps are in good condition
b. Obtain high volume mixing equipment
c. Blow the jets out of the bit and/or perforate above the bit to maximize the flow through the drill string
4. Pump the mud at a high rate until all the mud has been pumped.
DO NOT STOP UNTIL 3 TIMES THE ESTIMATED HOLE VOLUME OF HEAVY MUD HAS BEEN PUMPED.
5. Run the temperature/noise logs to determine if the well is dead. If it is dead, bleed off any casing pressure and rerun the logs.
This procedure is known as a “running kill”. Even though the pumped mud will be cut, the annular density will increase as more mud is pumped. As the annular density increases, so will the back pressure on the formation, resulting in a decreased kick flow rate. A kill can be accomplished with a limited volume of mud if the mud is MUCH heavier, and pumping is fast and continuous. A running kill of an underground blowout cannot be accomplished if the mud weight is only 1 to 2 ppg heavier than the estimated bottomhole pressure.
Lost Circulation
Loss of fluid returns will lower the hydrostatic head of the drilling fluid in the wellbore, thereby inducing a kick. The influx fluid will then flow to the surface or into the zone of lower pressure. Lost circulation can occur in naturally occurring fractured, vuggy, cavernous, sub-normally pressured or pressure depleted formations. Induced losses can occur from mechanical fracturing due to pressure surges while breaking circulation. In all cases of lost circulation, attempts should be made to keep the hole full. The hole can be filled with either light drilling fluid or water. A record of the amount of fluid pumped should be made.
Loss of returns while trying to kill a kick can develop in underground blowouts. If a kick is impending or an underground blowout has started, a barite plug may be effective in isolating the thief zone from the kick. In addition, fine sealing material may be used to control slow losses (coarse material that may plug the bit, choke valve or choke line should not be used). Occasionally, a coarse sealing fluid may be used when bullheading down the annulus. Normally, the lost circulation zone should be sealed once the loss zone has been isolated from the influx zone.
Weighted Plugs
In the case of an underground blowout, lost circulation, or situations requiring the low choke pressure control, it may become necessary to attempt well control using a weighted settling plug. These are deflocculated slurries of weight material in water or oil, weighing between 18 and 26 ppg, which bridge the hole as a result of high water loss and the rapid settling of the weight material once circulation is stopped. Hematite is recommended if slurry densities over 22 ppg are required and/or if the influx contains H2S, because hematite can act as a secondary scavenger (removing the gas by absorption).
If circulation has not been lost, the weight plug must be run under a back pressure and the influx must be held by casing pressure or hydrostatic pressure to allow the plug time to settle.
Bullheading
This is defined as pumping fluid into the well without circulation back to the surface. The fluid can be pumped down the drillpipe, down the annulus, or both. In most instances this will result in formation fracturing. This will occur at the weakest point, which is usually the formation near the last casing shoe. Obviously, in underground blowouts or wells with lost circulation, bullheading can prove useful since the fracture or loss zone already exists.
Wells with short open hole sections and zones of high permeability respond better to bullheading than wells with long open hole sections and low permeability zones.
The quicker the flow can be reversed, the less amount of drilling fluid has to be pumped to force the influx back into the formation. Any gas in the kick will migrate up the hole at a rate dependent upon the drilling fluid’s density and viscosity.
There are no specific rates at which bullheading should be performed. At slow rates (the pressures are within the boundaries of casing burst pressure) the pump rate can be increased until the higher pressure will become detrimental to the operation. The higher pump rates are desirable to pump the influx away as soon as possible, and to overcome any gas migration. Once the influx has been pumped away, normal circulation should be resumed to establish a balanced fluid column. The circulation of kill fluid should be at a rate that does not break down the formation any further. If, during bullheading a formation is fractured, it may heal with time. If not, further steps will have to be taken to heal the zone. In areas where H2S is present as a possible kick component, bullheading provides a useful means of limiting the amount of gas that has to be dealt with at the surface.
Bullheading has many advantages, but also many disadvantages that must be considered:
Advantages
1. Prevents Hydrogen Sulfide from reaching the surface
2. Keeps formation gas away from rig floor
3. Lower surface pressures are commonly used
4. Useful when underground blowouts occur
5. Can be used with or without pipe in the hole
6. Can be used to kill liner-top leaks
Disadvantages
1. Fractures formations
2. Can burst the casing
3. May break liner top
4. Can plug drillpipe
5. Will lose mud to formations (may therefore be expensive)
6. May pressure up formations, causing a back-flow when circulation is stopped
Well Control Equipment
The flow of fluid from the well caused by a kick is stopped by using the Blowout Preventers. Multiple blowout preventers used in a series is referred to as the BOP Stack. BOP stacks should be capable of terminating flow under all conditions.
A BOP stack comprises various types of preventer elements, including ram preventers, spools, and an annular preventer.
Annular preventer:
Commonly referred to as a bag type or spherical preventer, it is designed to stop flow from the well using a steel-ribbed packing element that contracts around the drill pipe. The packer will conform to the shape of the pipe that is in the bore hole. It is operated hydraulically, utilizing a piston acting on the packer. Once closed they utilize the upward well pressure to maintain their closed position. These preventers are available for a variety of working pressures, ranging from 2,000 to 10,000 psi. While these preventers can be used without pipe in the hole, the life of the packing element will be reduced by the stress of closing upon itself.
The initial recommended hydraulic pressure for closing most types of annular preventers is 1,500 psi. Once the packer is closed, the pressure should be reduced slightly to reduce damage to the rubber portion of the packer. One special feature of the annular preventer is that it will allow stripping operations to be carried out while maintaining pressure as the tool joints pass through the preventer. When stripping-in, the tool joints should be moved slowly through the preventer to avoid damage to the packing element.
Ram Preventers:
Ram type preventers have two opposing packing elements that are closed by moving them together. Rubber packing elements again, form the seal. A major difference between these and the annular preventer is that they are designed for specific applications. Rams are designed for a certain size of pipe and will only work on that type of pipe. Also, most ram type preventers are designed to seal in only one direction. They will only hold a pressure exerted from the lower side.
Thus they will not function if installed upside down and will not pressure test from above. Ram pistons are universal in that they may accept any of the following types of ram elements.
Pipe rams: These have semi-circular openings that match the diameter of the pipe being used. A drillstring comprising different pipe sizes, such as 3-inch and 5-inch drill pipe, would require two sets of pipe rams to accommodate both sizes of pipe. These are also operated hydraulically, and close around the tubing portion of drill pipe when used.
Blind rams: These are designed to close off the hole when no pipe is in the hole. If they are shut on drill pipe, they will flatten the pipe, but not necessarily stem the flow.
Shear rams: These are a form of blind rams that are designed to cut drill pipe when closed. This will result in the dropping of the drillstring below the BOP stack unless the stack is designed in such a way as to have a set of pipe rams below the shear rams on which a tool joint can be supported. They will stop the flow from the well. Shear rams are usually only used as a last resort when all other rams and the annular preventer have failed.
The ram preventers will have a manual screw-type locking device that can be used in the event of a hydraulic failure.
Other Components:
In addition to the annular and ram type components, the BOP stack must contain some mud access line, and a drilling spool will be inserted into the stack to allow for the connection of these choke and kill lines. The BOP stack will be attached to the casing string via a “casing head”. This casing/BOP connection will have a pressure rating similar to the rest of the BOP components.
In certain cases, it may be necessary to allow the well to blowout in a controlled manner rather than be shut-in. This is common in shallow sections due to insufficient casing to contain a kick. In these circumstances, adiverter system will be used. This is a relatively low pressure system, often using the annular preventer to seal off the annulus below the flow line. The diverter line will then be opened below the annular preventer to allow the flow to be directed away from the rig.
The BOP stack can only be used to stop the flow of fluids from the annulus. Additional valves are used to stop the flow within the drillstring. These valves include kelly cock valves and internal blowout preventers. Kelly cocks are generally placed at the top and bottom of the kelly. These valves may be installed as a permanent part of the drillstring or just when a kick occurs. They can be automatic or manually controlled and they consist of subs with valves that may be of a spring loaded ball type, a flapper valve type, or dart type. The dart acts as a one way valve, with pressure from below closing the valve, and pressure from above, opening it. The drawback of these valves is that while preventing a blowout up the string they prevent the shut-in drillpipe pressure from being monitored.
A manual valve, more commonly referred to as a “full opening safety valve”, is usually installed onto the drillpipe after a kick occurs. They usually contain a movable ball and when in one position allows flow through a hole in the ball, but after turning 90o, shuts off flow completely.
Rotating the ball is performed with a wrench. These have the advantage that wireline tools can be passed through them.
Control of the kick and kill fluids during kill operations is accomplished using a choke manifold. This manifold must be able to work under a variety of conditions, such as high pressure, with oil, gas, mud and water, and be capable of withstanding the effects of abrasive solids (sand and shale) in the kick fluids. The manifold should be capable of controlling the well using one of several chokes and be able to divert flow to one of several areas, such as reserve pits, burn pits, or degassers. Since vibrations occur during kill operations, the manifold must be securely anchored down, with as few bends as possible to prevent washouts under high pressure flow conditions.
The system used for closing the BOP’s is a high pressure hydraulic fluid accumulator. Hydraulic fluid is stored under pressure, the pressure being provided by stored nitrogen. When hydraulic oil is forced into the accumulator by a small volume, high pressure pump, the nitrogen is compressed, storing potential energy. When the BOP’s are activated the pressured oil is released, either opening or closing the BOP’s. Hydraulic pumps replenish the accumulator with the same amount of fluid that was used to operate the BOP. The accumulator must also be equipped to allow varying pressures. When stripping pipe through an annular preventer, a constant pressure must be maintained as the tool joints pass through the packing element. Accumulators commonly have minimum working pressures of 1200 psi and maximum working pressures of between 1500 and 3000 psi.
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Tangshan Aojie Petroleum Machinery Equipment Make Co., Ltd (Short for: OGEM Solids Control)
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Email: ogem2@ogemsolidscontrol.com
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