What is well 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 causes fluids to flow from the formation into the wellbore. This forced fluid flow is called a kick. 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 then the hydrostatic pressure then a kick will occur. If the flow is successfully controlled, the kick is considered to have been killed. An uncontrolled kick that increases in severity may result a situation that is known as a blowout.The Most Common Cause Of Well Kick or Influx Are: 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. Swabbing during pipe movement:Pulling the drill string 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 The effect of balled equipment 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.An obvious solution to kicks caused by insufficient mud weights seems to be drilling with high mud weights; however, this is not always available 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. Abnormal pressure formations: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. Shallow gas sands: 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. Improper hole fill-up during trips:Improperly filling up of the hole during trips is another prominent cause of kicks. As the drill pipe 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 acceptableunder any conditionto 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 holethe pump-stroke measurement methodis to periodically fill up the hole with a positive-displacement pump. A flow line 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. Special situations: Drill stem testing. Drilling into an adjacent well. Excessive drilling rate through a gas sand.Surveys in the past have shown that the major portion of well control problemshave occurred during trips. The potential exists for the reduction of bottom holepressure due to: Loss of ECD with pumps off. Reduction in fluid levels when pulling pipe and not filling the hole. Swabbing.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 has greater permeability and greater porosity than shale.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 Carbon dioxideWarning 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 weightEach 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 the rate of mud returning from the well above thenormalpumping rate indicatesa possible influx of fluid into the wellbore or gas expanding in the annulus. Flow rate indicatorslike the FloSho measure small increases in rate of flow and can give warning of kicks beforepit level gains can be detected. Therefore, an observed increase in flow rate is usually one ofthe first indicators of a kick. This is a positive indicator of a kick, and the well should be shut inimmediately any time an increase in flow rate is detected.Positive readings of a shut-in drill pipe pressure indicate that the well will have to be circulatedusing the Drillers or Engineers Kill Procedure. If the increase in flow was due to gas expansionin the annulus, the shut-in drill pipe pressure will read zero because no drill pipe under balanceexists.Pit volume increase (primary indicator)A gain in the total pit volume at the surface, when there are no mud materials being added atthe surface, indicates either an influx of formation fluids into the wellbore or the expansion ofgas in the annulus. Fluid influx at the bottom of the hole shows an immediate gain of surfacevolume due to the incompressibility of a fluid, (i.e. abarrelin at the bottom pushes out an extrabarrel at the surface). The influx of a barrel of gas will also push out a barrel of mud at the surface,but as the gas approaches the surface, an additional increase in pit level will occur due to gasexpansion. This is a positive indicator of a kick, and the well should be shut-in immediately anytime an increase in pit volume is detected.All additions to the mud system should be done with the Drillers knowledge. Each change inaddition rate, particularly of water orbarite, should be reported. Any change in valve settingsthat could affect fluid into or out of the system should be noted and relayed to the Driller. Thisis the only way to prevent unnecessary shut-ins of the well. Again, the Driller should always shutthe well in first, and then determine the reasons for a 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 drill pipe 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 heavierdrilling 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 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 OR Gradual Increase in Drilling Rate (secondary indicator):An unexpected increase in bit-penetration rate, called a drilling break, is a warning sign of a potential kick. When the rate suddenly increases, it is assumed that the rock type has been changed. It is assumed that the new rock type has been the potential to kick. While drilling in the normally pressured shales of a well, there will be a uniform decrease in thedrilling rate. Assuming that bit weight, RPM, bit types, hydraulics and mud weight remain fairlyconstant, the decrease will be due to the increase in shale density. Whenabnormalpressureis encountered, the density of the shale is decreased and so is the porosity. Higher porosityshales are softer and can be drilled faster. Therefore, the drilling rate will almost always increaseas the bit enters an abnormally pressured shale. This increase will not be rapid but gradual. Apenetration rate recorder simplifies detecting such changes. In development drilling, thisrecorder can be used with offset well electric logs to pinpoint the top of anabnormalpressurezone before any other indicators appears.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 cuttingConnection airAerated mud circulated from the pits and down the drillpipeFortunately, 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 3shows that gas cutting has a very small effect on bottomhole hydrostatic pressure. Effect of Gas-Cut Mud On The Bottomhole Hydrostatic PressureAn 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.

Decrease in Circulating Pressure:Invading formation fluid will usually reduce the average density of the mud in the annulus. If thedensity of mud in the drill pipe remains greater than in the annulus, the fluids will U-tube. At thesurface, this causes a decrease in the pump pressure and an increase in the pump speed.The same surface indications can be caused from a washout in the drill string. Toverifythecause, the pump should be shut down and the flow from the well should be checked. If the flowcontinues, the well should be shut-in and checked for drill pipe pressure to determine whetheran underbalanced condition exists.Other SecondaryIndicators of a Kick:1. Increase in Gas Cutting2. Increase in Water Cutting orChlorideIndicators ofAbnormal Pressure:1. Decrease in Shale Density2. Change in Cuttings Size and Shape3. Increasing Fill on Bottom After a Trip4. Increase in Flow Line Temperature5. Increase in Rotary Torque6. Increasing Tight Hole on Connections

Kick detection and monitoring with MWD tools:During circulation and drilling operations,measurement while drilling (MWD)systems monitor: Mud properties Formation parameters Drillstring parametersThe 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 systems 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.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 later shown that it is safer to use the exact required mud weight without variationBecause the drillpipe pressure has been defined as a bottomhole pressure gauge, thepsidpcan be used to calculate the mud weight necessary to kill the well.

The kill mud formula follows:

Where kw= kill-mud weight, lbm/gal 19.23 = conversion constantDtv= true vertical-bit depth, fto= original mud weight, lbm/gal.

Example 1What will the kill-weight mud density be for the kick data given below?Dtv= 11,550 fto= 12.1 lbm/galpsidp= 240 psipsic= 1,790 psiPit gain = 85 bblSolution.kw=psidp 19.23/Dtv+o= 240 psi 19.23/11,550 ft + 12.1 lbm/gal = 0.4 lbm/gal + 12.1 lbm/gal = 12.5 lbm/gal

Nomenclature:

Dtv= true vertical depth, bit depth,ft

gi= influx gradient, psi/ft

gmdp= mud gradient in drill pipe, psi/ft

hi= influx height, ft

kw= kill mud weight, lbm/gal

o= original mud weight, lbm/gal

psic= shut-in casing pressure, psi

psidp= shut-in drill pipe pressure, psi

Why Do We Need To Minimize Influx (Kick)?

As you know, weve always been trained or told to minimize influx (kick). Nowadays, there are several tools and procedures guiding us to prevent large influx; however, interestingly there are quite a lot of people who dont understand why we need to do this. In this topic, we will demonstrate how kick volume will affect wellbore and surface casing pressure.

Main concept of minimizing kick coming into the wellbore is to minimize surface casing pressure when shut in. If you have excessive surface casing pressure, you will have a chance to fracture the weakest formation in the wellbore such as formation at casing shoe. You need to remember that more influx equals to more surface pressure. We will do basic calculation to see the effect of kick volume and surface pressure.

Example:Use the following information and compare the result of 2 cases.Well Information (figure 1)

Figure 1 Well Information

9-5/8 casing shoe was set at 5,000MD/5,000TVD. The well is drilled to 10,000MD/10,000TVD with 8.5 bit. The well is assumed to be a gauge hole. Current mud weight is 9.2 ppg water based mud. Leak off test performed at 9-5/8 casing shoe is 13.5 ppg equivalent. Reservoir pressure at 10,000 TVD is 10.5 ppg equivalent. Average gas gradient is 0.1 psi/ft. 5 DP is used to drill this section and 6-1/2 DC is used as BHA for 1,000 ft.

What will happen if the wellbore influx is10bbl and50bbl?

First of all, we need to determine influx height of 10 bbl and 50 bbl.Influx Height = Kick Volume Annular CapacityAnnular Capacity between 8-1/2 hole and 5 DP = (8.52 52) 1029.4 = 0.04590 bbl/ftAnnular Capacity between 8-1/2 hole and 6.5 DC = (8.52 6.52) 1029.4 = 0.02194 bbl/ftHeight of 10 bblInflux Height @ 10 bbl = 10 0.02194 = 343 ft.

Figure 2 Height of 10 bbl kick

Height of 50 bblFor this case, we need to check see if 50 bbl will be more than annular volume between hole and drill collar.Volume between hole and 6.5 DC = Annular Capacity x DC LengthVolume between hole and 6.5 DC = 0.02914 x 1,000 = 29.14 bblAs you can see from the figure, it tells us that there is kick volume in the annulus between hole and 5 DP.Kick Volume between Hole and 6.5 DC = Total Kick Volume Volume between hole and 6.5 DCKick Volume between Hole and 6.5 DC = 50 29.14 = 20.86 bblWe know that we will have 20.86 bbl of kick between hole and 5 DP and then we need to calculate height of that volume.Influx Height @ 20.86 bbl = 20.86 0.04590 = 454 ftTotal Influx Height = Influx Height between DC and Hole + Influx Height between DP and Hole.Total Influx Height = 1000 + 454 = 1454 ft

Figure 3 Height of 50 bbl kickWhat is formation pressure at 10,000MD/10,000TVD ?Formation pressure = 0.052 x 10.5 x 10,000 = 5,460 psiWhat is Maximum Initial Shut-in Casing Pressure (MISICP) ?Maximum Initial Shut-in Casing Pressure (MISICP) = (LOT Current MW) x 0.052 x Shoe TVDMaximum Initial Shut-in Casing Pressure (MISICP) = (13.5 9.2) x 0.052 x 5,000 = 1,118 psiThen we need to apply the hydrostatic pressure concept to determine casing pressure as per the relationship below.Formation Pressure = Hydrostatic Pressure + Casing PressureRe-write to the equation belowCasing Pressure = Formation Pressure Hydrostatic PressureHydrostatic Pressure with 10 bbl of Kick in The WellHydrostatic Pressure = Hydrostatic from Gas + Hydrostatic from MudHydrostatic Pressure = (Gas Gradient x Height of Gas) + (0.052 x MW X Height of Mud)Hydrostatic Pressure = (0.1 x 343) + (0.052 x 9.2 x (10,000 343)) = 4,654 psi

Casing Pressure with 10 bbl of Kick in The Well

Casing Pressure = 5,460 4,654 = 806 psi (Figure 4)

Figure 4 Casing Pressure with 10 bbl gas kick

Hydrostatic Pressure with 50 bbl of Kick in The Well

Hydrostatic Pressure = Hydrostatic from Gas + Hydrostatic from MudHydrostatic Pressure = (Gas Gradient x Height of Gas) + (0.052 x MW X Height of Mud)Hydrostatic Pressure = (0.1 x 1454) + (0.052 x 9.2 x (10,000 1545)) = 4,233 psi

Casing Pressure = 5,460 4,233 = 1,227 psi (Figure 5)

Figure 5 Casing Pressure with 50 bbl gas kick

Based on the same assumption, we will get the surface pressure as listed belowCasing Pressure with 10 bbl kick = 806 psiCasing Pressure with 50 bbl kick = 1,227 psi

If we compare with MISICP of 1,118 psi from the calculation above, we will see that 50 bbl kick will break the casing shoe (Figure 6).

Figure 6 Shoe Fracture

Conclusion

More Kick = More Surface Pressure = Less SafeLess Kick = Less Surface Pressure = Safer

Kick Tolerance Concept and Calculation for Well Design:

Kick tolerance is the maximum gas volume for a given degree of underbalance which the circulation can be performed without exceeding the weakest formation in the wellbore. This article is the extended version ofKick Tolerance Calculationwhich will explain more on this topic. It is very critical that drilling personnel understand its importance to well design and drilling operation.

There are two important factors used for determining the kick tolerance

Kick Intensity It is the different between the maximum anticipated formation pressure and planned mud weight. For example, the planned mud weight is 13.0 ppg and the possible kick pressure is 13.5 ppg. Therefore, the kick intensity is 0.5 ppg (13.5 13.0).A zero kick intensity (swabbed kick scenario) should be used for a know area where you have less uncertainty about an overpressure zone. Kick Volume It is a gas influx entering into the wellbore from the formation. Gas kick is always used for well control calculation because it is the worst case scenario. The kick volume should be realistic figure which personal can detect the influx on the rig. In a larger hole, it allows bigger influx volume than a small hole.

Maximum Allowable Annular Surface Pressure (MAASP) and Kick Tolerance:Weakest formation point in the open hole is assumed to be at the shoe depth of the previous casing. The well bore will be fractured if a summation of hydrostatic and surface pressure exceeds the weakest pressure (Leak Off Test pressure). The maximum surface pressure before breaking the formation is called Maximum Allowable Shut In Casing Pressure (MASICP).Make it simpler for your understanding. MASICP is the total of kick tolerance budget. It consists of pressure from kick intensity and hydrostatic pressure loss due to gas.Kick Tolerance Example CalculationPrevious casing shoe (9-5/8 casing) at 6,000 MD/ 6,000 TVDPredicted formation pressure at TD (10,000MD/10,000TVD) = 14.0 ppgPore pressure uncertainty = 1.0 ppgPlanned mud weight = 14.5 ppg (0.754 psi/ft)Gas gradient = 0.1 psi/ftLOT = 16.0 ppgHole size = 8-1/2Drill Pipe = 5BHA + Drill Collar = 7Length of BHA+Drill Collar = 400 ftAnnular capacity between open hole and BHA = 0.0226 bbl/ftAnnular capacity between open hole and 5 DP = 0.0459 bbl/ft

Calculation Steps

Maximum anticipated pressure = 14.0 + 1 = 15.0 ppgMaximum Allowable Shut In Casing Pressure (MASICP) = (LOT MW) x 0.052 x Shoe TVDMaximum Allowable Shut In Casing Pressure (MASICP) = (16 14.5) x 0.052 x 6,000 = 468 psiKick Intensity = 15.0 14.5 = 0.5 ppgUnderbalanced due to kick intensity = 0.5 x 0.052 x 10,000 = 260 psiAs you can see, when the well is in underbalance condition (260 psi), the shoe will not be broken because the MASICP is more than underbalance pressure (468 > 260).We know that 0.5 ppg kick intensity we will have 208 psi (468 260 = 208 psi) before shoe broken.It means that gas bubble can replace mud in equivalent to 208 psi before fracturing the shoe. With this relationship, we can determine height of gas kick by the following equation.Height of gas kick = remaining pressure, psi (mud gradient, psi/ft gas gradient, psi/ft)Height of gas kick = 208 (0.754 0.1) = 318 ft.Determine gas kick volume base on height of gas kickWe need to separate into two cases and compare the smallest volume.1st case Gas at the bottom

Volume of gas kick = Annular capacity between open hole and BHA x Height of gas kickVolume of gas kick (bbl) = 0.0226 bbl/ft x 318 ft = 7.2 bbl2nd case Gas right below casing shoe

For this case, we need to convert gas at the shoe to the bottom condition by applying Boyles Laws.Volume of gas kick = Annular capacity between open hole and 5 DP x Height of gas kickVolume of gas kick (bbl) = 0.0459 bbl/ft x 318 ft = 14.6 bbl.

Convert to the bottom hole condition

Volume at the bottom = (volume of gas kick at shoe x Leak off test) formation pressure

Leak off test = 0.052 x 16 x 6,000 = 4,992 psiFormation pressure (gas kick condition) = 0.052 x 15 x 10,000 = 7,800 psiVolume at the bottom = (14.6 x 4992) 7800 = 9.3 bblWe can compare the kick volume from two cases like this.1 st case : kick volume = 7.2 bbl2nd case : kick volume = 9.3 bblThe smallest number must be selected to represent maximum kick volume therefore kick volume is 7.2 bbl.We wish this article could help you get more understanding about Kick Tolerance.

Kill Well Method ComparisonKill Well Method Comparison Both theDrillersand Engineers orWait and Weight Methodshave advantages and disadvantages, cause of this we will share aboutkill well comparisondepending on thegeneral conditions of the area of operation or the specific conditions in a well. The correct kill methodis determined through discussions between theDrillingRepresentative on location and the DrillingSupervisor.Figures E.3 and E.4 illustrate a gas kick being circulated to the surface using both the Drillers andthe Engineers Method. Observing both figures, note that when the gas bubble reaches the casingshoe, the Drillers method produces a surface casing pressure which is higher than the initial casingpressure, whereas the Engineers Method is less. In the Drillers Method, the hydrostatic pressurein the annulus is reduced as the gas bubble expands while being circulated out of the well. Since thebottomhole pressure is held constant, the surface casing pressure must increase. The hydrostaticpressure above the shoe is the same as it was when the well was initially shut-in, as long as the bubbleis below the shoe. The pressure at the shoe will increase an amount equal to the increase in thesurface casing pressure plus any circulating friction generated in the annulus above the shoe. Thisincrease in pressure could be sufficient to cause a formation breakdown at the shoe. Consequently,the maximum pressure at the casing shoe occurs when the top of the bubble reaches the shoe if theDrillers Method is used.Conversely, when the Engineers Method is used, the maximum pressure at the shoe will generallyoccur when the kill mud reaches the bit. Exceptions to this take place when the kick volume entersthe well filling it above the shoe, or when a small kick volume does not increase the casing pressureas it rises into a larger annular area at the top of the collars by the time kill mud reaches the bit, orat any time the top of the bubble reaches the shoe before the kill mud reaches the bit. The introductionof kill mud into the annulus through the bit increases the hydrostatic pressure. In order to maintainconstant bottom hole pressure, the surface pressure must be reduced and the pressure at the shoeis reduced.

Well Control - Driller's MethodWith this method, the well is killed in two circulations. During the first circulation: the influx is circulated out of the hole using the existing mud. Additional influx is prevented by adjusting the choke to maintain a constant bottom hole pressure slightly in excess of the pore pressure.During the second circulation: the existing mud is replaced by mud of the required density to (over)balance the pore pressure. The choke is adjusted to maintain a constant bottom hole pressure slightly greater than the pore pressure.1. Disadvantages of the driller's methodCompared with the balanced mud method, principal disadvantages of the driller's method include the following:the well must remain closed-in under pressure longer;the maximum pressure at the casing shoe and against the formation will be higher if the influx is gas (unless the top of the gas reaches the casing shoe before the drillstring would be displaced by heavy mud in the balanced mud method);the maximum choke pressure when the top of the influx reaches the surface will be higher if the influx is gas.Before employing the driller's method, it is essential to confirm that exposed formations can support the higher pressures which might be developed during the first circulation.2 Advantages of the driller's methodAdvantages of the driller's method include the following:simplicity: circulation can be started without calculations. This may be useful if expert supervision is not immediately available;pumping can begin as soon as drillpipe pressure build-up is established; there is no delay whilst mud is weighted up. This could be important in case of an H2S influx;the well can be effectively controlled (although not killed), even if the weighting material supply is inadequate.2.1 ProceduresThe following procedures concerning the driller's method are discussed:Closing in the well.Pressure and pit volume readings.First circulation: selecting the pump rate.Standpipe pressure during first circulation.Determining the height and gradient of the influx.First circulation: determining travel times (or volumes).First circulation: standpipe kill graph construction and use.Determining the pressure at the top of a gas influx at any point in the annulus.First circulation: action.Second circulation: determining the gradient of the kill mud.Second circulation: determining the amount of overbalance.Second circulation: selecting pump rate.Second circulation: travel times (or volumes).Second circulation: standpipe pressures.Second circulation: standpipe kill graph construction and use.Second circulation: action.Procedure after the well has been brought under control.3 Closing in the wellClose in the well immediately after detecting a kick condition. The procedure is as for the balanced mud method.4 Pressure and pit volume readingsPressure and pit volume readings should be taken as for the balanced mud method5 First circulation: Selecting the pump rateThe mud is not weighted up for the first circulation: therefore, the pump rate is not limited by the weighting material mixing capacity of the rig. However, the maximum pump rate is limited by other factors such as the increased initial standpipe pressure, the need for choke adjustment, and surface gas handling equipment. Also, if the choke starts blocking-off, pressure surges will be less at reduced circulating rates. Normally, the pump speed selected will not exceed 50% of the usual circulating rate applied for drilling operations.6 Standpipe pressure during first circulationThe standpipe pressure at the start is the same as with the balanced mud method. The standpipe pressure should then be approximately equal to the normal pre-kick circulation pressure at the selected pump speed, plus the closed-in drillpipe pressure, plus a small margin of 700 kPa (100 psi).Always make sure that the formation strength at the casing shoe is not exceeded during the circulating process.Since there is no change in the gradient of the mud being pumped, the initial standpipe pressure must be held constant throughout the first circulation to ensure that the bottom hole pressure is also kept constant.7 Determining the height and gradient of the influxThis information is not essential, but will give an indication of the pattern of choke pressures and pit level changes that may be expected during the first circulation. The procedure is as for the balanced mud method.8 First circulation: Determining travel times (or volumes)The bit-to-shoe and shoe-to-choke times are determined .The total pumping time for the first circulation is that required to displace the annulus, i.e. the sum of the bit-to-shoe and shoe-to-choke times, volumes, or pump strokes.9 First circulation: Standpipe kill graph construction and useThe standpipe kill graph is a horizontal line equal to the closed-in drillpipe pressure plus the circulating pressure plus the overbalance margin of 100 psi.10 Determining the pressure at the top of a gas influx at any point in the annulusWhen a gas kick is being circulated out of the hole, the influx volume will increase due to expansion and consequently results in increased pit levels.By calculating the expected annular pressures at the top of the influx at specific points along the hole together with the associated influx volumes at these points, comparisons can be made with actual values observed during circulating out the influx. This information can play an important role in the decision making process during well control operations.The pressure at the top of a gas bubble at any point in the annulus while circulating it out using the "Driller's method" can be calculated as follows:11 First circulation: ActionThe procedure for the first circulation is as follows:1.Open the choke and start pumping the existing mud at the selected pump speed.2.Adjust the choke opening until the choke pressure equals the closed-in annulus pressure plus the overbalance margin. Record the choke pressures throughout the first circulation.3.Read the standpipe pressure. It should agree with the calculated value, i.e. the normal pre-kick pump test circulation pressure at the selected pump speed plus the closed-in drillpipe pressure, plus a small margin of 700 kPa (100 psi). If the observed standpipe pressure does not agree with the calculated value, consider the observed pressure to be correct.4.Note the standpipe pressure and thereafter keep it constant whilst maintaining a constant pump rate, until the influx is circulated out.5.When all influx has been circulated out, stop the pump and close in the well to check the closed-in drillpipe and annulus pressures. At the end of the first circulation, the closed-in pressures of the annulus and drillpipe should be the same and equal to the initial closed-in drillpipe pressure. The well is controlled but not killed.During the first circulation the following should also be carried out:maintain and record the density of the mud pumped into the drillstring. Ensure that it has the correct value;measure and record the properties of the mud returns;de-gas, treat or discard any contaminated mud returns.12 Second circulation: Determining the gradient of the kill mudThe gradient of the kill mud to balance the formation pressure can be determined as soon as the closed-in standpipe pressure has stabilised. A trip margin can now be added to the kill mud gradient in order to overbalance the formation pressure and to resume normal operations.13 Second circulation: Determining the amount of overbalanceNormally the overbalance on bottom during well control (neglecting friction losses in the annulus), should not exceed 700 kPa (100 psi). However, since the influx has been displaced with r1 mud during the first circulation, large fluctuations in mud gradient and choke control operations are not expected and therefore, if possible, the density of the mud in the well is raised directly to that required to resume normal operations.14 Second circulation: Selecting pump rateThis is carried out as for the balanced mud method.A constant pump rate, approximately one half the speed used for the drilling operation, is maintained during the second circulation.15 Second circulation: Travel times (or volumes)Provided that the same pump rate is used, the surface-to-bit and bit-to-choke times are the same as for the balanced mud method Section16 Second circulation: Standpipe pressureThe initial standpipe pressure should be the same as for the first circulation.Pst =Pdp + Pc1 + marginDuring the period that the heavy mud (including the overbalance) is pumped down the drillstring, the standpipe pressure should decrease until the heavy mud reaches the bit at which time it should be:Pst = Pc1 * rho2 / rho1 = Pc2The standpipe pressure should remain constant after the heavy mud has reached the bit.17 Second circulation: Standpipe kill graph construction and useThe standpipe pressure kill graph for the second circulation is similar to that of the balanced mud methodThe procedure for constructing the standpipe kill graph is as follows:1.Plot the initial circulating pressure plus margin at the start of the second circulation.2.Plot the heavy mud circulating pressure (Pc2) at the time that the heavy mud reaches the bit.3.Whilst the heavy mud is being circulated into the annulus, the back pressure should be progressively reduced to zero at the time when the heavy mud reaches the choke. The standpipe pressure should then equal the heavy mud circulating pressure.This assumes that the heavy mud gradient includes a suitable overbalance margin.18 Second circulation: ActionIf possible, the density of the mud in the well is raised directly to that required to resume normal operations.The procedure during the second circulation is as follows:1.Open the choke and start pumping mud of the required density at the rate selected to kill the well. Maintain a constant pumping rate.2.Adjust the choke opening until the choke pressure equals the closed-in annulus pressure plus margin observed at the end of the first circulation. Choke pressures should be recorded throughout the process.3.Read the standpipe pressure. This should agree with the calculated standpipe pressure, i.e. the pre-kick pump test circulating pressure plus the closed-in drillpipe pressure at the end of the first circulation including the margin. If the standpipe pressure does not agree with the calculated value, consider the observed pressure to be correct and modify the standpipe pressure kill graph accordingly.4.When the heavy mud reaches the surface, stop pumping and check whether the well is dead.During the second circulation the following should also be carried out:maintain and record the density of the mud pumped into the drillstring; ensure that it has the correct value;measure and record the properties of the mud returns until the well is killed;de-gas, treat or discard any contaminated mud returns.19 Procedure after the well has been brought under controlAfter the well has been brought under control, the well should be flow-checked via the open choke line. The preventers can be opened and normal circulation resumed after any possible flow has ceased from the choke line for a reasonable flow-check time.Procedures for floating drilling operations are described in the Balanced mud method.

Driller Method First Circulation

Engineering Method or Weight And Wait Kill Well Method

Well Kill Using Wait and Weight Method (Balanced Method)The Wait and Weight method is the method recommended, in some circumstances, for controlling an influx taken while drilling or circulating on bottom. When drillpipe (string) volume is greater than open hole volume, the influx will already be inside the casing before heavy mud reaches the open hole.In this case the Drillers Method can be a better solution as the danger of gas expansion is removed immediately while weighing up mud can take hours.Advantages of Wait and Weight methodthe annular pressure will usually be lower and the chance of formation breakdown is therefore reduced.the hole and the wellhead equipment are subjected to high pressures for the shortest possible time since the influx is circulated out and the well is killed in one circulation.Disadvantages of Wait and Weight methodconsiderable waiting time while weighing up mud can cause gas migrationif large increases in mud weight is required, this may be possible in stages onlyThis method involves one circulation. Kill mud is prepared and is pumped from surface to bit while following a prepared drillpipe pressure drop schedule. Once the kill mud enters the annulus, a constant drillpipe pressure is maintained until the heavy mud returns to surface.ProcedureThe procedure for the Wait and Weight method is as follows:After the well has been secured and pressures have stabilised, complete kill sheet including kill graphBring pumps up to speed keeping casing pressure constant by manipulating the chokeWhen pump is up to kill speed the choke is manipulated to keep the drill pipe pressure at initial circulating pressure (ICP).Pump kill mud down drill pipe keeping casing pressure constant and allowing drill pipe pressure to fall from ICP to final circulating pressure (FCP).When kill mud reaches the bit the drill pipe pressure should be at FCP. Continue pumping kill mud keeping drill pipe pressure constant at FCP until the kick is circulated out and kill mud reaches surface.EquationsKMW = (SIDPP / (0.052 * TVD)) + OMWTrip margin may not be included in the calculation for kill mud weight. The major reason for this is to avoid any unnecessary additional wellbore pressure that could result in formation breakdown.Calculate initial circulating pressure:ICP = SCRP + SIDPP (psi)Calculate Final circulating pressure:FCP =KMWx SCRP (psi) OMWCalculate surface to bit strokes:Strokes =Drillstring volume(bbls) Pump output (bbls/stroke)Calculate time to pump surface to bit:Time (mins) =Total strokes from surface to bit) Strokes per minuteWhere: KMW = Kill mud weight (ppg) SIDPP = Shut in Drillpipe pressure (psi) TVD = True vertical depth (ft) OMW = Original Mud Weight (ppg) ICP = Initial circulating pressure (psi) SCRP = slow circulating rate pressure (psi) FCP = Final circulating pressure (psi)

Wait and Weight Method Kill WellWait and Weight MethodKilling Wellis sometimes referred to as the Engineers Method or the OneCirculation Method. It does, at least in theory, kill the well in one circulation.This is the preferred method used by most operators and recommended by many well killingexperts. Its principal advantage is that it provides the lowest annular pressures during thecirculation of the kill, making it the safest of the commonly used kill methods.Once the well is shut in and pressures stabilized, the shut in drillpipe pressure is used tocalculate the kill mudweight. Mud of the requiredweightis made up in the mud pits. Whenready, kill mud is pumped down the drillpipe. At commencement enough drillpipe pressuremust be held to circulate the mud, plus a reserve equivalent to the original shut in drillpipepressure. Thistotalsteadily decreases as the mud goes down to the bit, until with kill mud atthe bit, the required pressure is simply that needed to pump kill mud around the well.The choke is adjusted to reduce drillpipe pressure while kill mud is pumped down the string.With kill mud at the bit, the static head of mud in the drill pipebalancesformation pressure.For the remainder of the circulation, as the influx is pumped tothe surface, followed by drillpipe contents and the kill mud, the drillpipe pressure is held at thefinalcirculating value bychoke adjustment.Procedure for the wait and weight methodThe Wait andWeightmethod uses the same calculations already described for a drillpipe pressureschedule.The calculations are:Kill MudWeight=Original MudWeight+ [SIDPP TVD 0.052]At the start of the circulation, with kill mud:Initial Circulating Pressure(ICP) = Slow Circulating Pressure (SCRP) + Shut In Drillpipe Pressure (SIDPP)Once the capacity of the drill string is calculated, it is possible to draw a graph showing how drillpipe pressure varies as kill mud is pumped down to the bit. Once kill mud is ready, the start-up procedure is as previously described.The choke is cracked open, the pump started to break circulation, and then brought up slowlyto the Kill Rate.While the Driller brings the pump up to the Kill Rate, the choke operator works the choke soas to keep the casing pressure at or as near as possible to the closed in casing pressure reading.When the pump is up to the Kill Rate, the choke operator transfers to the drillpipe pressuregauge, adjusting the choke if necessary to achieve the INITIAL CIRCULATING PRESSUREon the drillpipe pressure gauge.As the kill mud proceeds down the drillpipe, the drillpipe pressure is allowed to drop steadilyfrom the Initial Circulating Pressure to the FinalCirculating Pressure, by choke adjustment.Where the kick is a small one, at or near the bottom of the hole, the drillpipe pressure tends todrop of its own accord as the kill mud moves down. Little or no choke adjustment isrequired.Only in cases of diffused gas kicks with gas far up the annulus will significant chokeadjustments be needed during this period.After kill mud has reached the bit, the drillpipe pressures is maintained at theFinal CirculatingPressure, until the kill mud returns to surface.As with the Drillers method, thisFinalCirculating pressure is held constant as long as pumprate is held constant at the selected value. If, for any reason, the pump rate is felt to be wrong,it can be changed using the same procedure described previously. However, pump ratechanges should be avoided, where possible.While the pump rate is adjusted, the casing pressure is held steady by adjusting the choke. Once the pump is stabilized at its new speed, the revised circulating pressure is read from thedrillpipe gauge. If a gas influx is very near tothe surface, adjusting pump rate by holding asteady casing pressure may significantly increase thebottom hole pressure. This is due to therapid expansion of gas nearthe surface. Alterations in pump rate are to be made early on!The following two graphs depict pressure variations during theWait andWeightmethod.

Circulating Pressure

Annular Pressure

Step Wait AndWeightProcedureAdvantages of the Wait and Weight Method Kill Well:1. LOWEST WELL BORE PRESSURES, AND LOWEST SURFACE PRESSURES this means less EQUIPMENT STRESS.2. MINIMUM ON-CHOKE CIRCULATING TIME.Disadvantages of the Wait and Weight MethodKill Well:1. CONSIDERABLE WAITING TIME (while weighting up) GASMIGRATION?2. IF LARGE INCREASES IN MUDWEIGHTREQUIRED, THIS IS DIFFICULT TO DO UNIFORMLY IN ONE STAGE.