Kick Control Methods: All kill procedures require data concerning drillstring geometry, hole geometry, mud density, pump rates, pressure losses, and fracture pressure. Important data that is required prior to initiating kill procedures include:
1. Circulating pressure at kill rate
2. Surface to bit time at kill rate (in strokes and minutes)
3. Bit to surface time at kill rate (in strokes and minutes)
4. Maximum allowable annular pressure
5. Formula for calculating the kill mud density
6. Formula for calculating the change in circulating pressure due to the effect of the heavier mud
7. The clients policies on safety factors and trip margins
For a well to be killed successfully, the pressure in the formation must be kept under control during the entire kill operation. The only exception is in cases when the maximum allowable annular pressure will be exceeded. The simplest method of doing this is to control the drillpipe pressure by running the kill pump at a constant rate and controlling the pressure by regulating the choke on the choke line.
The three main kill methods are:
1. The Driller’s Method (two circulations)
2. The Wait and Weight (Engineers) method (one circulation)
3. The Concurrent Method
The Driller’s Method
When a kick occurs, the normal procedures is as follows:
1. Pick up the kelly and note the position of tool joints in relation to the drilling spools.
2. Stop the pumps.
3. Open the choke line.
4. Close the annular preventer or ram preventers.
5. Close the choke.
6. Record the pit gain.
7. Record the SIDP and SICP when they stabilize.
Once the well is shut-in, it is necessary to calculate the kill mud density, initial and final circulating pressures, and the kick fluid gradient. If the kick fluid is gas, the bubble may start to percolate up the annulus. (this will cause a slow rise in the pressures on both drillpipe and casing). If the pressures begin to rise, a small amount of fluid can be bled from the choke, to release this “trapped pressure”. This process should be repeated until the drillpipe pressure has stabilized.
The first circulation of the Driller’s Method is performed using the original mud. The choke is opened slightly, at the same time the pumps are started up to the kill rate. When the pumps have reached kill rate, the choke is manipulated to maintain the Initial Circulating Pressure (ICP) on the drillpipe. As the kick fluids approach the surface, the annular pressure will rise drastically if the kick is gas. If the kick is saltwater the annular pressure will drop slightly.
When the influx has been circulated out, the pumps are stopped and the choke closed. At this time, the two surface pressures (SIDP & SICP) should be the same.
During the first circulation, the mud density in the pits is raised to the kill mud density. When the kill mud volume has been achieved, the kill mud is circulated. As with the first circulation, the choke is opened and the pump speed increased to the kill rate (with the annulus pressure kept constant). The annular pressure is kept constant by manipulating the choke until the kill mud has reached the bit. As kill mud begins to fill the system, the drillpipe pressure will decrease from the initial circulating pressure to the final circulating pressure (see Figure below).
When kill mud reaches the bit, it is good practice to shut-in the well. The drillpipe pressure should fall to zero; if it doesn’t, a few more barrels should be pumped to ensure that the kill mud has reached the bit. If the drillpipe pressure is still greater than zero when the pump is stopped and the choke closed, the kick control figures should be rechecked. When satisfied, pumping is restarted, but now the drillpipe pressure is kept constant as the kill mud displaces the mud in the annulus. When the kick fluids and original mud have been displaced, the choke should be wide open. The pump should be shut down and both SIDP & SICP should read zero. If so, the well should then be observed for flow. The kick is now killed and mud should be circulated to condition the hole, and at the same time the trip margin (if any) should be added.
Illustrate how the pressures behavior as the first and second circulations are performed
The Engineer’s Method
This is usually a more effective method of killing a kick than the driller’s method, if time is not a prime concern (Figure). Kill mud is pumped into the drillpipe as soon as it is ready, which tends to reduce the high annular pressures associated with gas kicks. The same shut-in procedures are used as outlined in the previous section.
When all the calculations have been performed, the mud density is raised immediately to the calculated kill mud density. When the kill mud volume is ready, the pumps are started and the choke slowly opened, while keeping the annular pressure constant until the pump has reached kill rate. The choke is then regulated in such a way as to decrease the drillpipe pressure until the kill mud reaches the bit, at which point the final circulating pressure is reached.
Drillpipe and annular pressure curves during the engineer’s kill method
Pumping is continued, holding the drillpipe pressure constant by adjusting the choke. When the kick fluids have been displaced, and further volume has been displaced equal to the pipe volume, the SIDP should be zero. The kick should be killed and the well checked for flow. Further circulations can be performed to condition the hole and to add any trip margin. Figure below shows the variations in drillpipe and casing pressures as the kill procedure is implemented.
The Concurrent Method
This is the most complicated and unpredictable method of the three. Its main value lies in the fact that it combines the driller’s and engineer’s methods, so that kill operation may be initiated immediately upon receipt of the shut-in pressures. Instead of waiting until all the surface mud has been weighted up, pumping begins immediately at the kill rate and the mud is pumped down as the density is increased. The rate at which the mud density is raised is dependent upon the mixing facilities available and the capability of the crew. The main complication of this method is that the drillpipe can be filled with muds of different densities, making calculation of the bottomhole hydrostatic pressure (and drillpipe pressure) difficult.
Provided there is adequate supervision and communication, and the method is completely understood, this can be a very effective way of killing a kick. Figure 8-7 illustrates the irregularities in drillpipe pressure with kill mud volume, caused by the different densities of the mud. The shut-in procedure is the same as that outlined previously. When all the kick information has been recorded the pumps are activated slowly until the initial circulating pressure has been reached at the designated kill rate.
The mud should be weighted up as fast as possible, and, as the mud density changes in the suction pit, the choke operator is informed. The total pump strokes are checked on the drillpipe pressure chart when the new density is pumped and the choke is adjusted to suit the new drillpipe conditions. When the final kill mud reaches the bit, the final circulating pressure will be reached and from this point on the drillpipe pressure should be kept constant until the operation is completed.
Within the oil industry, there are three recognized kick control procedures.
2) Weight, and
The selection of which to use will depend upon the amount and type of kick fluids that have entered the well, the rig’s equipment capabilities, the minimum fracture pressure in the open hole, and the drilling and operating companies well control policies. Determination of the most suitable and safest method (assuming their company policy allows flexibility of procedures determined by the demands of the situation) involves several important considerations:
• The time required to execute any complex kill procedures
• Surface pressures that will arise from circulating out the kick fluids
• Downhole stresses are applied to formations during kill operation
• The complexity of the procedure itself relative to the implementation, rig capability and rig crew experience
It is the responsibility of the tool pusher or operator’s representative to decide which method will be used to kill the well. Each of the previous points must be assessed and their relative importance to the kick situation evaluated before implementing the selected kill method. In the following paragraphs, elaboration of these points will illustrate the reasoning behind the importance of individual situations.
The Time Factor
The total amount of time taken to implement and complete kill procedures is important, especially if the kick is gas. This is because the “gas bubble” will percolate up the annulus, increasing annular pressures. There may also be a danger of the pipe sticking, especially if a fresh water mud system is in use. Invading saline pore water may cause the mud cake to flocculate, so the bit, stabilizers and collars would be in danger of sticking.
Considerable time is involved in weighting up the mud, but more importantly is the time for the kill operation to be completed. The strains and pressures on the well, surface equipment and personnel should be minimized in the interests of safety and cost. Therefore, depending on the kick situation, the decision as to which method to use must be based on these priorities.
The kill procedures that involve the least amount of initial waiting time are the two circulation method (or driller’s method) and the concurrent method. In both of these procedures, pumping begins immediately after the shut-in pressures are recorded. However, if the time taken to weight-up the mud is less than one circulation then the engineers, or one circulation, method may be preferred. In certain situations the extra time required for the two circulation method may be seriously detrimental to hole stability or may cause excessive BOP wear.
If a gas kick is taken, annular pressures may become alarmingly high during the course of the kill operation. This is due to gas expansion as it nears the surface. This is normal. If expansion is not allowed to occur, severe pressures will be placed on the annulus and surface equipment. For this reason, the most reliable well killing procedures utilize a constant drillpipe pressure and a variable annular pressure (through a variable choke) during circulation.
The kill procedure that involves the least surface pressures must be used if the kick tolerance is minimal. Figure below shows the different surface pressure requirements for the two different kick situations, using the one and two circulation methods.
The first difference is noted immediately after the drillpipe is displaced with kill mud. When keeping the drillpipe pressure constant (with the constant pump rate) the casing pressure begins to decrease as a result of the kill mud hydrostatic pressure in the one circulation procedure.
This initial decrease is not seen in the two circulation method, since the mud density has not changed, and as can be seen, the casing pressure increases as the gas expansion displaces mud from the hole. The second pressure difference is noted when the gas approaches the surface. The two circulation method, again, has the higher pressures which is the result of circulating the original mud density during the first circulation.
Also, after one complete circulation has been made, the one circulation method has killed the well, resulting in zero surface pressure, whereas the two circulation method still has pressure on the casing, equal to that of the shut in drillpipe pressure (SIDP).
Downhole stresses are prime concern during kill operations. If the extra stresses imposed by the kick are greater than the minimum fracture pressure in the open hole, fracturing occurs.
Similarly, procedures which through its implementation, places high stresses on the wellbore should not be used in preference to others which impose lower stresses on the wellbore. Reference to the above points illustrates that the one circulation method places the minimum stresses on both the wellbore and surface equipment. When a kick is circulated out the maximum stresses occur very early in the circulation – particularly in deep wells with higher pressures. At any point in the borehole, the maximum stress is imposed on the formation when the top of the kick fluid reaches that point.
Generally, if fracturing and lost circulation does not occur on initial shutin, they will not occur throughout the kill process (if the correct procedure is chosen and implemented).
The suitability of any process is dependent on the ease with which it may be reliably executed. If a kill procedure is difficult to comprehend and implement, its reliability is negated. The one and two circulation methods are simple in both theory and execution. Choice between the two is dependent upon the other points (time factor, surface pressures, downhole stresses, and so forth), and any other limitations caused by the situation. The concurrent kill method is relatively complex in operation and its reliability may be reduced through its intricacy. Because of this, many operators have discontinued its use. It is important to realize that all pressures calculated on deviated wells must use vertical depth and not measured depth. Measured lengths are used for ECD calculations, so that the resultant pressure losses can be added to the hydrostatic pressure (calculated from the vertical depths).
Situations may arise when the casing pressure causes downhole stresses approaching or slightly exceeding the actual or estimated minimum fracture pressure. In this case the well cannot be shut-in, and an alternate method of kill control must be attempted. Maximum pressure at the surface are determined by three factors:
1. The maximum pressure the wellhead will hold
2. The maximum pressure the casing will hold (burst pressure)
3. The maximum pressure the formation will hold
Formulas Used In Kick and Kill Procedures
Hydrostatic Pressure (psi): MW x TVD x 0.0519
where: MW = Mud Density (lb/gal)
TVD = True Vertical Depth (ft)
Circulating Pressure (psi): (MW x TVD x 0.0519) + Pla
where: Pla = Annular Pressure Loss (psi)
Initial Circulating Pressure (psi): SPR + SIDP
where: SPR = System pressure loss at kill rate (psi)
SIDP= Shut-in Drillpipe Pressure (psi)
Final Circulating Pressure (psi): (KMW / MW) x SPR
where: KMW = Kill Mud Density (lb/gal)
Kill Mud Weight (lb/gal): MW + (SIDP / (TVD x 0.0519))
Formation Pressure (psi): SIDP + (MW x TVD x 0.0519)
Density of influx (ppg): MW – [(SICP - SIDP)/(L x 0.0519)]
where: SICP= Shut in casing pressure (psi)
L = Length of influx (ft)
Length of kick around drill collars (ft):
Pit Gain (bbls)/ Annular Volume around collars (bbls/ft)
Length of kick, drill collars and drill pipe (ft):
Collar Length + [(Pit Gain - Collar Annular Volume) / (D12 - D22 x 0.000971)]
where: D1 = hole diameter (inches)
D2 = drillpipe diameter (inches)
Gas bubble migration rate (psi/hr): DPa / (0.0519 x MW)
where: DPa = pressure change over time interval / time interval (hr)
Barite required (sk/100 bbls mud):
1490 x (KMW – MW) / (35.8 – KMW)
Volume increase caused by weighting up:
100 x (KMW – MW) / (35.8 – KMW)
The drill pipe pressure can be used as a downhole pressure gauge, while the casing pressure is affected by the type and amount of fluid influx. When the density of the kick fluid is known, the composition may be estimated;
Influx Density (psi/ft)Influx Type
0.05 – 0.2 gas
0.2 – 0.4 combination of gas/oil and or seawater
0.4 – 0.5 oil or seawater