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well control (1)

Bullheading is a common non-circulating method for killing live wells prior to workovers. It involves pumping kill fluid into the tubing to displace produced fluids back into the formation. A bullheading schedule is generated using formation pressure, desired overbalance, fracture pressure, tubing specifications, and pump data to safely control pumping pressures within the initial and final maximum pressures. The schedule provides checkpoints to monitor pumping pressure and volume throughout the operation. Special attention should be paid to any increases in casing pressure which could indicate downhole issues.

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Well Control During Workovers and Completions 1 Bullheading Bullheading is a common method for killing live wells prior to moving a rig on to conduct a workover. It is a non-circulating technique which uses a pump and kill fluid. The method entails forcing produced fluids back into the producing formation while filling the tubing with kill. Lubrication and Bleeding In some cases bullheading is not possible or desirable. Examples of this are: severely worn tubing having low burst pressure, low formation fracture strength, and damaged or deteriorated wellhead equipment with limited working pressure. In these cases, lubrication and bleeding might be a more acceptable means of killing a well. This technique can also be used to reduce surface pressure to a point where bullheading can be conducted. The basic procedure for lubricating and bleeding requires the pumping of a measured volume of kill fluid into the well, allowing it to fall, and then bleeding gas at the surface while controlling surface pressure to predetermined limits. Circulation Methods Reversing is a common circulation method used for killing live wells before a workover. Prior to the commencement of a workover, a circulating pathway must be established between the casing and tubing. A few methods are available: tubing perforation, opening a sliding sleeve, or pulling a gas lift valve or dummy, which are commonly performed by slickline. Once surface pressures stabilize, kill fluid can be circulated throughout the well. Normal circulation can also be used to conduct a kill operation. Killing A Well Prior To A Workover – Non-Circulating Techniques
Well Control During Workovers and Completions 2 Bullheading Bullheading is a means of killing a static producing well in which produced fluids are pumped back into the producing formation and the tubing filled with kill fluid. Bullheading should not be done in a haphazard way due to the possibility of damaging wellbore tubulars, damaging the producing formation, or fracturing adjacent formations. To accomplish a successful bullheading operation the following information is required to generate a Bullheading Schedule. The bullheading schedule is generated which provides the user with a means of killing the well with the control of surface pumping pressure. Non-Circulating Techniques
Well Control During Workovers and Completions 3 The following information is required to prepare a Bullheading schedule: Formation pressure – calculated, but preferably from a recent BHP survey Desired overbalance - provided by kill fluid – while pumping balanced weight fluid will kill a well, and overbalance is required if the tubing or packer is to be pulled, or if trips are to be made into and out of the well. Common overbalances range from .3 ppg to .5 ppg above the balanced fluid welight. Perf depth - measured and vertical Fracture pressure - estimate of the formation frac strength – the decline of the producing formation pressure must be taken into account when making this estimate – as a rule of thumb: render a conservative estimate Bullheading Non-Circulating Techniques
Well Control During Workovers and Completions 4 Bullheading Non-Circulating Techniques Tubing specifics - ID, length, EOT, burst, percent wear – seriously consider running a tubing caliper survey if the well has a history of producing sand or corrosive fluids such as H2S, CO2, or a high volume of salt water Annular fluid backup - the presence or absence of fluid in the annulus – this can have a major impact on the effective burst pressure of the tubing Rathole - ID and measured length – if a rathole exists it must be filled with kill fluid Pump size - liner, stroke, and efficiency data Surface pressures - tubing and annular Wellhead working pressure
Well Control During Workovers and Completions 5 STEP 1 Formation Pressure (ppg) STEP 2 Kill Fluid (ppg) STEP 3 Fracture Pressurepsi - requires knowledge or estimate of frac in ppg STEP 4 Pumping Volume STEP 5 Pump Outputbbl/stk - pump efficiency must be input in decimal form ( ) Formation Vertical PSI PPG DepthPerf Formation =      × 23.19 PPGPPGPPG FluidKillOverbalaceDesiredFormation =+ PSIVerticalPPG FracDepthPerfFrac =×× 052. BBLRathole Rathole Tbg Tbg VolumePumpingLength ID Length ID =        ×      +         ×         4.10294.1029 22 STKBBLPercentageInches OutputEfficiencyPumpLengthStrokeIDLiner / 2 000243. =××× Bullheading Non-Circulating Techniques
Well Control During Workovers and Completions 6 STEP 6 Pump Strokes - if the pump has a stroke counter STEP 7 Working Burst Pressure of the Tubing Assuming the industry standard of downgrading the tubing specifications to 80%. If the tubing is known to be worn more than 20%, insert the appropriate value rather than the given . STEP 8 Maximum Initial Tubing Pressure – Tubing Burst (assuming no backup) STEP 9 Maximum Final Tubing Pressure – Tubing Burst (assuming no backup) STEPS 8 & 9 are to be done if the assumption is made to disregard tubing backup supplied by the presence of fluid in the tubing/casing annulus - in older wells it may be prudent to make this assumption. StrokesPump OutputPump VolumePumping STKBBL BBL =      / PSIPSI BurstWorkingBurstPublished =× 8. ( ) PSIPSIPSI InitialMaxSITPFormationBurstWorking =+− PSIVerticalPPGPSI FinalMaxDepthPerfFluidKillBurstWorking =××− )052(. Bullheading Non-Circulating Techniques
Well Control During Workovers and Completions 7 TEP 10 Maximum Initial Tubing Pressure – Frac (assuming no backup) TEP 11 Maximum Final Tubing Pressure – Frac (assuming no backup) PSI Pump Strokes or BBL Pumped Tbg & Rathole Displaced SITP Line Frac Line (based on no backup Tbg Burst Line (based on no backup) Max Initial Pressures Max Final Pressures Safe PumpingRange The following is a graphical representation of calculated Initial and Final pressure along with Pumping Volume. ( ) PSIPSIPSI InitalMaxSITPFormationFrac =−− ( ) PSIVerticalPPGPPG FinalMaxDepthPerfFluidKillFrac =××− 052. Bullheading Non-Circulating Techniques
Well Control During Workovers and Completions 8 If tubing back up is to be considered the following calculations will take the place of the Maximum Initial and Maximum Final pressures for burst used previously. Maximum Initial Tubing Pressure (tbg burst consideration) - back up assumed Maximum Final Tubing Pressure (tbg burst consideration) - back up assumed The above calculations will result in higher values due to the inclusion of the annular hydrostatic pressure as a back up. In some cases, the maximum initial and maximum final pressure could be higher than the rated burst pressure. Naturally in these cases, the working burst pressure would be used as the maximum pressure. On the following page is a graph depicting the changes that would take place when annular hydrostatic pressure is considered in calculating maximum initial and final pressures for tubing burst. ( ) ( ) PSIVerticalPPGPSIPSI InitialMaxLengthFluidFluidAnnularFormationBurstWorking =××+− 052. ( )( ) ( ) PSIVerticalPPG VerticalPPGPSI FinalMaxLengthFluidAnnular LengthFluidKillBurstWorking =×× +××− 052. 052. Bullheading Non-Circulating Techniques
Well Control During Workovers and Completions 9 Tbg & Rathole Displaced Pump Strokes or BBL Pumped SITP Line Frac Line Tbg Burst Line (based on fluid backup) Max Final Pressures Safe PumpingRange Max Initial Pressures Working Burst Pressure From the graph it can be seen that the tubing burst pressures may be greater than calculated working tubing burst pressure and possibly greater than the working pressure of the tree. PSI Bullheading Non-Circulating Techniques
Well Control During Workovers and Completions 10 From previous diagrams and based on the “safe pumping range,” it is clear that as hydrostatic pressure in the tubing increases, due to the introduction of kill fluid, maximum surface pressures decrease. The drawing indicates the safe range to be bordered by the SITP and the Frac Line. This is the most desirable situation but is not always the case. If the tubing is severely corroded or pitted due to corrosive fluid production or sand production, the Tubing Burst Line could be the first ‘limit line’ above the SITP line. In either case, the safe pumping range is between the SITP Line and the first limit line above it. There are two ways the pressure can be monitored while the operation is in progress. A schedule could be generated based on an observed maximum initial pumping pressure, a selected maximum final pumping pressure, and the total volume or total strokes to pump. Naturally, the Maximum Initial Pressure would have to be within the safe pumping range. The mathematics to accomplish this is as such: STEP 2 Average Pressure Drop STEP 1 Pressure Drop M a x im u m I n itia l M a x im u m F in a l− p r e s s u r e d r o p in c r e m e n ts1 0 10 increments have been selected here only as an example - 15, or even 20 increments could be selected depending on how often one would want to check pump pressure during the operation STEP 3 Average Volume or Pump Stroke T o t a l P u m p S t r o k e s i n c r e m e n t s1 0 or T o ta l P u m p in g V o lu m e in c r e m e n ts1 0 Bullheading Non-Circulating Techniques
Well Control During Workovers and Completions 11 21 Based on the calculated average pressure drop and average pump strokes or volume pumped, a schedule can be generated and recorded. The procedure for the schedule is as: STEP 4 Pump Pressure i n i t i a l p u m p p r e s s u r e a v e r a g e p r e s s u r e d r o p− The first calculation renders a pump pressure corresponding to a ‘check point’ on the schedule. Additional similar calculations complete the schedule. STEP 5 Pump Strokes 0 s t r o k e s a v e r a g e s t r o k e s+ This calculation provides the first checkpoint once the operation has started. Additional similar calculations complete the schedule. As an example, let’s use the information below to illustrate the creation of a schedule: Initial Pump Pressure 2200 psi Final Pump Pressure 800 psi (arbitrarily selected) Total Strokes 4500 strokes Checkpoints 10 Bullheading Non-Circulating Techniques
Well Control During Workovers and Completions 12 Pressure Drop (Initial Circulating Pressure to Final Circulating Pressure) 2 2 0 0 8 0 0 1 4 0 0p s i p s i p s i− = Average Pressure Drop (Base on 10 Checkpoints) 1 4 0 0 1 0 1 4 0 p s i p s i c h e c k p o i n c r e m e n t s = / i n t Having performed these two calculations the pressure decline portion of the schedule can be completed. The Initial Pressure of 2200 would be the 1st entry. The average pressure drop of 140 psi is subtracted from the initial to obtain the 2nd checkpoint. Repeating this process completes the pressure side of the schedule. 2200 2060 1920 1780 1640 1500 1360 1220 1080 940 800 2200 - 140 = 2060 2060 - 140 = 1920 Additional iterations complete the schedule Bullheading Non-Circulating Techniques
Well Control During Workovers and Completions 13 A similar same thing can be done where the strokes or bbls to pump is concerned. In the case where 4500 strokes is required to displace the tubing and rathole, the incremental strokes increase of the schedule is generated as seen below. 0 450 900 1350 1800 2250 2700 3150 3600 4050 4500 Average Stroke Count 4 5 0 0 1 0 4 5 0 to ta l s tr o k e s in c r e m e n ts s tr o k e s= 0 strokes + 450 = 450 strokes 450 strokes + 450 strokes = 900 strokes ……and so on…... 2200 2060 1920 1780 1640 1500 1360 1220 1080 940 800 0 450 900 1350 1800 2250 2700 3150 3600 4050 4500 PSI STK S The completed schedule appears a right. The pump pressure is controlled by adjusting the pump throttle to achieve the desired decreasing pump pressures. Bullheading Non-Circulating Techniques
Well Control During Workovers and Completions 14 Below is an example graphical representation of a bullheading operation. The shaded area indicates a “safe pumping range” based on calculated pump pressures. The center line in the shaded area indicates a “midpoint” or desired pump pressure line to follow. The red lines indicate how pressures can be monitored at anytime during the operation. Checking the pressure at 750 strokes would yield a pressure of about 2200 psi. Checking the pressure at 2600 strokes would yield a pressure of about 1100 psi. Pump Strokes or BBL Pumped Pump Pressure Formation Taking Fluid Stabilized Initial Pump Pressure 500 1000 1500 2000 2500 3000 3500 3750 0 1000 2000 3000 4000 5000 5000 4000 3000 2000 1000 Desired Pump Pressure Bullheading Non-Circulating Techniques
Well Control During Workovers and Completions 15 While bullheading the casing pressure should be monitored closely. Any increase in the casing pressure should be reported to the job supervisor and closely monitored for change. Casing pressure increases can be from thermal expansion caused by pumping liquids down the tubing, or may indicate leaking tools or seals such as sliding sleeves, gas lift equipment, safety valves, packer seals, etc. The presence of, or an increase in casing pressure while bullheading can have dire consequences. Excess pressure applied to the cross-sectional area of the packer creates a great deal of force, so much so that the packer can be forced down the hole and the tubing parted. Additionally, the excess pressure in the annulus creates a situation where casing burst pressure can be approached - not necessarily at the surface but downhole. Casing Pressure Increase While Bullheading Bullheading Non-Circulating Techniques
Well Control During Workovers and Completions 16 Gas Channeling Gas channeling can occur during a bullheading operation, especially so if the kill fluid lacks appreciable viscosity and the pump rate is somewhat slow. In that case, gas may migrate up the tubing faster than it is being forced down the tubing through pumping. According to the previous graphs, once the tubing and rathole volume are pumped, the tubing pressure should be 0 psi and the well dead. Oftentimes this is not the case. Even though the SITP is 0 psi and the well ‘seems’ to be dead, wait for a while, 30 minutes or more, and monitor the SITP. If it starts to increase then gas channeling is usually the problem. It is particularly troublesome in highly deviated wells. A possible remedy to this situation is to pump a viscous pill ahead of the kill fluid to minimize the gas channeling. This could be followed, if so desired by a solids-laden pill, such as calcium carbonate, which can be acidized out when desired, and then that followed by the kill fluid. Of course, formation permeability and sensitivity must be considered before using a viscous or solids- Gas Channeling Kill Fluid Bullheading Non-Circulating Techniques
Well Control During Workovers and Completions 17 Gas lubrication is the process of pumping fluid into the tubing, allowing it to fall, and then bleeding gas; all the while maintaining a constant bottomhole pressure. The procedure is sometimes known as pump and bleed. Lubrication can be used to either entirely kill a well prior to a workover or to reduce the SITP prior to bullheading. Preceding a bullheading operation is usually done if the tubing is known or suspected to be in poor condition and may not withstand the pressures encountered during bullheading There are two approaches to this procedure, but regardless of the method used, the objective is to introduce hydrostatic pressure into the tubing by the means of a kill fluid. Lubrication and Bleeding Non-Circulating Techniques
Well Control During Workovers and Completions 18 STEP 1 Select an overbalance (Working Range) such as 50 to 100psi STEP 2 Calculate the hydrostatic increase base on the volume pumped, the wellbore geometry, and the density of the fluid being pumped. This is accomplished using the following: IncreasecHydrostati WtFluid ID RangeWorking BBL PPG Tbg Pumped =                         ××         × .052. 4.1029 2 STEP 3 Pump kill fluid into the well until the observed pump pressure is equal to the Working Range. Stop the pump and take note of the volume pumped. Use this volume in performing the above calculation. STEP 4 Allow time (at least 30 to 45 minutes – be patient) for the fluid to fall or “lubricate” through the produced fluids in the tubing. STEP 5 Bleed dry gas through the production choke while monitoring the SITP. The “target” SITP is determined as follows: Bleed SITP back to original SITP as this is compression. Subtract from the SITP the hydrostatic added by kill fluid. Lubrication and Bleeding - Volume Method Non-Circulating Techniques
Well Control During Workovers and Completions 19 BBL Pumped PSI Trend of declining SITP Working Range Pressure decline after pump is shut down Pressure stabilization Bleeding gas (bleed back to original SITP and additional hydrostatic added) Resulting SITP Below is an idealized plot of the Volume Method as described on the previous page. Lubrication and Bleeding - Volume Method Non-Circulating Techniques
Well Control During Workovers and Completions 20 The Volume Method of lubrication is not without its shortcomings: While pumping into the well as per the selected Working Range, produced fluids can be forced back into the perfs equal to the hydrostatic pressure added by kill fluid. When gas is bled at the surface the SITP will decline but could re-build and stabilize near the original SITP. This would make the operation appear to be accomplishing nothing. Patience is needed in this case. Eventually enough kill fluid hydrostatic will be added to the tubing to start to make a difference and the SITP will begin to shows signs of decline. This occurrence is especially like when the producing formation is quite permeable. Due to this, the Volume Method is more applicable to drilling operations where mud solids build open hole wall cake against permeable formations and limit fluid invasion Lubrication and Bleeding - Volume Method Non-Circulating Techniques
Well Control During Workovers and Completions 21 A better method of lubrication to use during workovers is the Pressure Method. The volume of fluid pumped does not have to be monitored as it does in the Volume Method. The Pressure Method uses three pressures: Pressure 1 P1: initial SITP Pressure 2 P2: stabilized SITP after pumping Pressure 3 P3: desired SITP after bleeding gas from the well To determine P2 and P3 perform the following: 3 2 2 1 P P P = Lubrication and Bleeding - Pressure Method Non-Circulating Techniques
Well Control During Workovers and Completions 22 Pressure Method Procedure: STEP 1 Pump kill fluid into well to increase SITP to desired pressure considering a working range. STEP 2 Allow the tubing pressure to stabilize. Use the stabilized tubing pressure as the value for P2. STEP 3 Calculate P3 and bleed tubing to the calculated value. Repeat steps 1 through 3 until all the gas is out of the well or until another procedure implemented based on having achieved a desired SITP. Lubrication and Bleeding - Pressure Method Non-Circulating Techniques
Well Control During Workovers and Completions 23 Lubrication and Bleeding - Pressure Method Non-Circulating Techniques BBL Pumped PSI Trend of declining SITP Working Range Pressure decline after pump is shut down Pressure stabilization Bleeding gas (bleed to target pressure) Resulting SITP Plot of Pressure Method
Well Control During Workovers and Completions 24 Lubrication and Bleeding The Casing Non-Circulating Techniques Without Packer Lubrication and bleeding can be performed on the casing but consideration must be made with respect to the presence or absence of a packer. If the well has been completed without a packer then either the Volume Method or Pressure Method can be used. Selecting the working range would have the same criteria used when performing Lube and Bleeding on the tubing.
Well Control During Workovers and Completions 25 Kill fluid pumped in and produced fluids bled Kill fluid would be pumped into and produced fluids would be bled from the production casing wing. Regardless of the method selected, a worksheet should be completed to track the progress of the operation. Lubrication and Bleeding The Casing Non-Circulating Techniques Without Packer
Well Control During Workovers and Completions 26 Lubrication and Bleeding The Casing Non-Circulating Techniques With Packer Conducting a Lube and Bleed operation on the casing side of a well with a packer in the hole is another matter entirely. The main “danger” is the possibility of parting the tubing or pumping the packer down hole – neither of which are very desirable. Information should be gathered about the following in order to determine the feasibility of attempting a Lube and Bleed on a well with a packer in place: When the packer was initially set was it set in tension or compression? The OD of the tubing. Tubing tensile strength. Collapse pressure of the tubing. The OD of the packer. The burst pressure of the casing. The density of the pack fluid left in place when the well was completed or last worked over.
Well Control During Workovers and Completions 27 Lubrication and Bleeding The Casing Non-Circulating Techniques With Packer Forces A few things come into play that create forces on the cross- sectional area of the packer: Hydrostatic pressure of the packer fluid SICP Applied surface pressure from the Lube and Bleed operation FORCE (lbs) is pressure exposed to a cross-sectional area 2 inchesPSI APForce ×= The “area of interest”, in this case is the exposed area of the packer, or as illustrated at right and for all practical purposes, the area between the OD of the tubing and the ID of the casing.
Well Control During Workovers and Completions 28 Lubrication and Bleeding The Casing Non-Circulating Techniques With Packer The force created across the exposed area of the packer is calculated as such: ( ) LBSPSIODID ForcePTbgCsg =××− 7854.22 This calculation would have to be done for everything that exerts pressure on the packer: SICP Applied surface pressure of the Lube and Bleed operation Packer fluid hydrostatic pressure. Once total force is calculated (a sum of all the forces) it is compared to estimated tubing tensile strength. From that comparison a decision is made as to the feasibility of performing a Lube and Bleed operation on the annulus housing a seated packer.
Well Control During Workovers and Completions 29 Lubrication and Bleeding The Casing Non-Circulating Techniques With Packer Tubing Tensile Strength The tensile strength of a steel tubular is determined by the grade of steel and the square inches of steel of which the tubular is comprised. Tubing grades are annotated as such: N-80, C-75 P-110 The numerical values indicating the minimum yield strength of the steel in thousands of pounds per square inch of steel. N-80 pipe = steel with a minimum yield of 80,000 psi C-75 pipe = steel with a minimum yield of 75,000 psi P-110 pipe = steel with a minimum yield of 110,000 psi The tensile strength can be determined by multiplying the area of steel in square inches by the minimum yield of the steel.
Well Control During Workovers and Completions 30 Lubrication and Bleeding The Casing Non-Circulating Techniques With Packer Tubing Tensile Strength Tubing tensile strength is calculated using the following: ( ) PSIODOD YieldMinimumTbgTbg ××− 7854.22 The above formula will render tensile strength of new pipe. It is strongly advised that some safety factor be applied to the calculated tensile strength. A common practice is to downgrade the calculated tensile strength to 80% or even 70% if the tubing is known to be worn to some degree. Another means of gaining useful knowledge of the tubing tensile strength is to consult any one of a number of tubing tables that are commercially available. In most cases, the specifics are for new pipe and the user must make adjustments as to his/her knowledge of the pipe condition.
Well Control During Workovers and Completions 31 Lubrication and Bleeding The Casing Non-Circulating Techniques With Packer Kill fluid pumped in and produced fluids bled Kill fluid would be pumped into and produced fluids would be bled from the production casing wing. Regardless of the method selected, a worksheet should be completed to track the progress of the operation.
Well Control During Workovers and Completions 32 In some cases a circulating kill technique is preferred over a non-circulating one necessitating communication between the tubing and the casing. If this is the case, a means of communication between the two strings must be established. This is commonly done by one of the three following methods which can be accomplished via wireline or coiled tubing-conveyed wireline tools : Shifting a sliding sleeve Pulling a gas lift dummy from a side-pocket mandrel Perforating the tubing Anytime communication is established between the tubing and casing there exists the possibility of a differential pressure at the point where communication is established. This can be a problem. If there is a negative differential (more pressure in the casing than the tubing at the point of communication), a wireline tool string could get blown up the hole creating the very real possibility of a fishing job before the well is killed. Sliding sleeves incorporate equalizing features to minimize this. The same is true for some gas lift valves/dummies, but not in all cases. Therefore, it’s imperative that the gas lift equipment be identified as to the presence or absence of this feature. Regardless, it highly recommended that calculations be made as to the possible differential existing at the desired point of communication and steps taken to minimize the differential Gaining Tubing-to-Casing Communication
Well Control During Workovers and Completions 33 Calculating Differential Pressure Surface Pressures 1150 psi SITP 0 psi SICP Wellbore Fluids Tubing: 0’-2188’ gas – average density of .115 psi/ft 2188’-11235’ – oil – measured API gravity of 31.5o @ 120o F Casing: 0’ – 11235’ – filled with 11.4 calcium chloride The task at hand is to open the sliding sleeve @ 11235’ in order to circulate kill fluid around and kill the well before the workover starts. Even though sliding sleeves have an equalizing feature, it’s a good idea to determine if there is a differential across the sleeve and then decide how to negate the effects of the differential. The differential, if present, is based on the total pressure in the casing at the depth of interest compared to the total pressure in the tubing at the depth of interest. The total pressure is a combination of any surface pressure plus hydrostatic pressure. This is to be applied to both sides of the well. The information below will be used in the example: Gaining Tubing-to-Casing Communication
Well Control During Workovers and Completions 34 Oil Hydrostatic Pressure STEP 1 Calculate API Gravity Corrected For Temperature ( ) CorrectedAPI TempObserved TempObserved =      − − 10 60 STEP 2 Oil Hydrostatic Pressure ( ) PSIColumnOilftpsi Corrected HPLength API =×      + /433. 5.131 5.141 Gas Hydrostatic Pressure PSIColumnGasFTPSI cHydrostatiGasLengthVerticalGradientGasAverage =×/ Brine Hydrostatic Pressure cHydrostatiBrineLengthWtFluid ColumnFluidPPG =×× .052. NOTE: Calculating oil hydrostatic pressure is a two step process. Oil density is measured in API degrees. The API hydrometer is calibrated to be accurate at 60 degrees F. Therefore it is necessary to correct the observed density to the observed temperature. Calculating Differential Pressure Gaining Tubing-to-Casing Communication
Well Control During Workovers and Completions 35 Total Casing Pressure @ Depth of Interest Brine Hydrostatic Pressure psiPPG 6660112354.11052. =×× Since there is no surface casing pressure the calculated brine hydrostatic pressure is the total pressure in the casing at the depth of interest. Total Tubing Pressure @ Depth of Interest Gas Hydrostatic Pressure STEP 1 Corrected API Gravity PSIFtPSI 2526.251'2188115. / ≈=× Oil Hydrostatic Pressure ( ) API5.25 10 60120 5.31 =      − − STEP 2 Oil Hydrostatic Pressure ( ) ( ) PSIFTPSI 35316.3530218811235433. 5.255.131 5.141 / ≈=−××      + Calculating Differential Pressure Gaining Tubing-to-Casing Communication
Well Control During Workovers and Completions 36 Total Tubing Pressure PSI cHydroststiOil PSI cHydroststiGas PSI SITP PSI 493335312521150 =++ Differential Pressure PSI TbgTotal PSI CsgTotal PSI 172749336660 =− Obviously the differential is from Casing to Tubing. To negate the existing differential 1727 psi must be added to the tubing string since it would be virtually impossible to decrease the hydrostatic pressure in the casing. There are two options available: Pump into the tubing to increase the surface pressure by the differential pressure – provided this can be done without damaging the producing formation Set a plug in the tubing below the sliding sleeve and then pressure up on the tubing by the calculated differential Calculating Differential Pressure Gaining Tubing-to-Casing Communication
Well Control During Workovers and Completions 37 Gaining Tubing-to-Casing Communication Shifting a Sliding Sleeve OpenClosed Sliding Sleeve Port A shifting/positioning tool is conveyed by wireline or coiled tubing and the sleeve is shifted to the open position. Shifting Tool
Well Control During Workovers and Completions 38 Gas Lift Equipment Gaining Tubing-to-Casing Communication Gas lift equipment is installed in an oil well in anticipation of formation pressure declining before all recoverable reserves are produced. In the case of the side pocket equipment, numerous side pocket mandrels are run in the tubing string. As the illustration shows, the mandrel contains a profile for the gas lift dummies or valves. If the mandrels are run in the initial completion, dummies are installed which can be removed at a later date and replaced with valves . With the valves in place, gas is injected in the casing and enters the mandrel via the gas ports. The ports align with a port on the gas lift valve which then conveys the gas into the oil in the tubing string. The gas entering the oil lightens the column hydrostatically, thus allowing the remaining formation pressure to produce the oil. A kickover tool, orients the pulling or running tool to the side pocket for valve or dummy installation or extraction. Once the valve or dummy is out of the pocket, the pocket can then be used as a means of casing-to-tubing communication. Courtesy of Halliburton
Well Control During Workovers and Completions 39 Three commonly used and very reliable kickover tools are from left to right: the Camco AK Kickover Tool, the Camco L Kickover Tool, and the Camco L-2D Kickover Tool. The appropriate pulling or running tool for the gas lift valve would be installed below the kickover tool. Camco Kickover Tools Gas Lift Equipment Gaining Tubing-to-Casing Communication
Well Control During Workovers and Completions 40 Gas Lift – Pulling A Dummy Or Valve STEP 1 The tool string is run below the desired gas lift mandrel. STEP 2 The tool string is raised above the mandrel. As this happens the tool string rotates and begins to orient to the side pocket. STEP3 The kickover tool kicks the pulling tool into the side pocket to engage the gas lift valve.
Well Control During Workovers and Completions 41 Gas Lift STEP4 The pulling tool engages and latches the fishing neck of the gas lift valve STEP5 Upward manipulation of the tool string pulls the lift valve from the side pocket.
Well Control During Workovers and Completions 42 Tubing Perforation Tubing perforated just above the packer Gaining Tubing-to-Casing Communication A perforator, be it mechanical or shot charge, is lowered to the desired depth which is usually as close to the packer as possible. The perforator is activated and communication with the annulus is established. Although an explosive E-line conveyed explosive charge is more efficient, it may be more desirable to use a mechanical perforator to prevent any possible damage or unwanted perforation of the production casing.
Well Control During Workovers and Completions 43Otis Type A Mechanical Perforator Slip Stop Collar Stop Tubing Perforation Gaining Tubing-to-Casing Communication The mechanical perforator does not offer the accurate depth control of an E-line perforator but can still get the job done. Either the slip stop or collar stop can be used as a perforating platform for the mechanical perforator.
Well Control During Workovers and Completions 44 Tubing Perforation Gaining Tubing-to-Casing Communication To perforate the tubing using a mechanical perforator, a tubing stop must first be set at a desired depth. Next the perforator is run and activated. After communication is established between the tubing and the casing, the perforator is pulled from the hole followed by the tubing stop. Wireline Tool String Perforator Tubing Stop
Well Control During Workovers and Completions 45 Surface Pressure Stabilization After successful communication between the tubing and casing has been established, time should be given for surface pressure to stabilize, even though exhaustive calculations have been performed in the effort to predict the surface pressures based on “known” or anticipated fluids in place versus formation pressure. In some cases, it’s a “best guess” of the actual stabilized surface pressures. Factors affecting this can be, but are not limited to, unknown fluid density in both the tubing and casing, especially so in a workover. Over time, the brine in the packer fluid can crystallize and find its way to the packer. This can make it initially impossible to gain string-to-string communication, even though a “communication window” has been opened via sliding sleeve, gas lift equipment, or perforation. The brine can settle and pack making it impossible for fluid to flow through it. This also makes the density of the liquid in the annulus an unknown.
Well Control During Workovers and Completions 46 Another problem that can exist is that the exact density of the fluids in the tubing may not be unknown. Additionally, there may exist a differential between the casing and the tubing. If this is the case, the possibility of u-tubing of these fluids exists and would occur until a pressure equilibrium is established. Therefore, prior to any kill method being attempted, be it circulating or non- circulating, surface pressures must be allowed to stabilize. Following the stabilization of surface pressure, a circulating kill procedure can be implemented which will be discussed later in the chapter. Surface Pressure Stabilization
Well Control During Workovers and Completions 47 Friction Pressure Friction pressure is the pressure created by circulating a fluid through a circulating system at a given rate. Factors affecting the magnitude of friction pressure include: Fluid properties Circulating system geometry Pump rate Knowledge of friction pressure has two uses: Provides information regarding circulating pump pressure when killing a well Provides information about annular friction while circulating which adds to wellbore stress After the well is initially dead and circulated entirely with kill fluid, it is advised that a few slow pump rates be taken. Rate 1 Normal average operating speed of the pump Rate 2 Half the normal average operating speed of the pump Rate 3 As slow as the pump can pump for an extended duration Record corresponding pressure with each rate.
Well Control During Workovers and Completions 48 Friction Pressure Annular friction, which is created in the casing when fluid is pumped, adds to bottom hole pressure. In drilling environments, annular friction makes up a small portion of the total friction pressure created, but in workovers, this is not the case due to the reduced diameters involved, especially the production casing. Even when using solids-free fluid, appreciable friction pressure can be created in the somewhat “tight” confines of a producing well annulus. To that end, it is prudent to calculate an estimate of the annular friction pressure created by each slow pump rate for both normal and reverse circulation, since reverse circulation is used so frequently in workovers. The following set of formulas can be used to generate reasonable estimates of workstring and annular friction pressure as well as the equivalent stress created at the bottom of the hole.
Well Control During Workovers and Completions 49 Friction Pressure WORKSTRING FRICTION PRESSURE STEP 1 Workstring Fluid Velocity ft/sec ( ) ( ) SecFT Tbg BBLGalBPM Velocity ID Flowrate /2 / 45.2 42 = × × STEP 2 Reynolds Number ( ) R CP TbgSecFtPPG N ityVisFluid IDVelocityFluidWtFluid = ××× cos .928 / If the Reynolds Number ≥ 2100 the flow is Turbulent – Go to STEP 3 If the Reynolds Number ≤ 2100 the flow is Laminar – Go to STEP 4 STEP 3 Turbulent Friction Pressure ( ) ( ) PSI Tbg MDFluid Friction ID DepthityVisVelocityWtFluid = × ××× 2 25.75.175. 1000 cos
Well Control During Workovers and Completions 50 Friction Pressure STEP 4 Laminar Friction Pressure ( ) ( ) PSI Tbg MDFluidCP Friction ID DepthVelocityityVis = × ×× 2 1500 cos ANNULAR FRICTION PRESSURE STEP 1 Annular Fluid Velocity ft/sec ( ) ( )( ) SecFt TbgCsg BBLGalBPM Velocity ODID Flowrate /22 / 45.2 42 = −× × STEP 2 Reynolds Number ( )( ) R CP TbgCsgFluidPPG N ityVis ODIDVelocityWtFluid = −××× cos .928 If the Reynolds Number ≥ 2100 the flow is Turbulent – Go to STEP 3 If the Reynolds Number ≤ 2100 the flow is Laminar – Go to STEP 4
Well Control During Workovers and Completions 51 STEP 3 Turbulent Friction Pressure Friction Pressure ( ) ( )( ) PSI TbgCsg MDCPFluidPPG Friction ODID DepthityVisVelocityWtFluid = −× ××× 22 75.175. 1369 cos STEP 4 Laminar Friction Pressure ( ) ( )( ) PSI TbgCsg MDSecFtCP Friction ODID DepthVelocityityVis = −× ×× 22 / 1000 cos Equivalent Circulating Density (ECD) Normal Circulation ( ) PPG Vertical PSI WtFluid Depth FricAnnular . 23.19 +      × Equivalent Circulating Density (ECD) Reverse Circulation ( ) PPG Vertical PSI WtFluid Depth FricWorkstring . 23.19 +      ×
Well Control During Workovers and Completions 52 During the course of a workover, a kick can occur for a variety of reasons. A kick can be defined as any unwanted intrusion of formation fluids into the wellbore, and if not detected early on, and handled properly, most assuredly can result in a surface blowout. The main causes of kicks during workovers are: • Failure to keep the hole full during trips • Swabbing • Insufficient fluid weight • Loss of circulation Failure to Keep Hole Full During Trips As a workstring is pulled from the hole, the fluid level in the well drops due to the displacement of the workstring. As the fluid level drops hydrostatic pressure decreases, and if the hydrostatic pressure of the workover fluid decreases below formation pressure, formation fluids will flow into the well. Kicks During WorkoversTripping
Well Control During Workovers and Completions 53 Prior to Tripping Circulate the hole clean prior to the trip. Calculate the volume required for a slug if one is to be pumped. Calculate workstring displacement and faithfully record hole fill/displacement data on trip sheets. Limit pipe speed to minimize surge/swab pressures – especially when running or pulling tools with large OD’s such as packers, mills, etc.. Line up and use a trip tank. Discuss with driller/operator the purpose of trip. Prepare the rig floor. Kicks During WorkoversTripping Statistics indicate that the most serious well control incidents during completions and workovers occur while the workstring is being tripped!!
Well Control During Workovers and Completions 54 As a rule of thumb, the slug should be mixed to maintain a minimum of 2 to 3 stands of dry pipe. Tripping Kicks During Workovers If a slug is to be pumped consult with the driller or unit operator as to his knowledge of how well or how poorly the workstring drains. This information can be used in determining how far down the fluid level should be after the slug has been pumped and the wellbore is once again stable. The procedure on the following page will provide information as to the volume of slug to pump based on the desired dry pipe and the desired slug weight. Additional information provided is the anticipated displacement created by the slug. Tripping should NEVER begin until the well is stabilized after pumping a slug – otherwise the driller or unit operator has no way of accurately monitoring the displacement of the workstring. Slugging
Well Control During Workovers and Completions 55 STEP 1 SLUG LENGTH (ft) STEP 2 SLUG VOLUME BBL STEP 3 SLUG DISPLACEMENT BBL ( ) ( ) FT PPGPPG PPGFt LengthSlug WtFluidWtFluidSlug WtFluidPipeDryDesired =      − × .. . BBL Workstring Ft VolumeSlug ID LengthSlug =         × 4.1029 2 BBL Workstring FT ntDisplacemeSlug ID PipeDryDesired =         × 4.1029 2 Sluggin g
Well Control During Workovers and Completions 56 Workstring Displacement – Pulling Dry STEP 1 Workstring Displacement (Per 5 Stands) DisplacedFTFt BBLWtPipe =×× 450.0003638. /# The formula above will provide a reasonably accurate displacement volume for both upset and non upset pipe, including hevi-weight drill pipe and drill collars. If the workstring is tapered and contains pipe of varying weight, the calculation above should be performed for each weight category. The workstring displacement is generally monitored as such: Workstring or Drill Pipe: 5-stand groups Hevi-Weight Drill Pipe: 3-stand groups Drill Collars: 1-stand groups Total workstring displacement should also be calculated and compared to the observed displacement on every trip. Anytime the observed hole fill (when tripping out) or hole flow (when tripping in) becomes noticeably different from calculated values the trip should be stopped, the well monitored for flow or loss of fluid, and a reasonable determination made as to why the well is behaving the way it is. NEVER should a trip proceed with well experiencing excessive flow or fluid loss.
Well Control During Workovers and Completions 57 Workstring Displacement Per Stand Workstring Displacement – Pulling Wet If the workstring becomes plugged and will not drain, then it must be pulled wet. The following will provide an accurate value for wet displacement. Usually when pulling wet, the workstring displacement is monitored on a “per stand” basis regardless of the weight of the pipe or whether the string is tapered or not. ( ) Ft WorkstringPipe ft Length ID Wt ×                 +× 4.1029 0003638. 2 /#
Well Control During Workovers and Completions 58 Trip sheets should be used to record hole fill volumes for all trips. The trip sheet allows for comparison of actual vs. calculated fluid volumes so that any discrepancies can be easily detected. A trip tank should also be used during all trips to assist with accurate hole fill requirements. A trip sheet need not be a complicated document. Below is an example of a simple trip sheet that provides the required information to monitor hole fill. Stand Group Calculated Displacement Observed Displacement Discrepancy Cumulative Displacement Cumulative Discrepancy Remarks Tripping Kicks During Workovers
Well Control During Workovers and Completions 59 Trip tanks are the most reliable means of monitoring pipe displacement while tripping, however many smaller workover rigs are not equipped with trip tanks. An alternative to this will be discussed later. If a trip tank is present on the rig it should be calibrated based on its volume and dimensions so that volume changes can be readily detected and accurately monitored. Seen below is an example of a trip tank. The tank volume should be at least equal to the total displacement of the workstring. Use of a Trip Tank Tripping Kicks During Workovers
Well Control During Workovers and Completions 60 If a trip tank is not calibrated there are easy ways of measuring the change in trip tank level. Measurements of the tank need to be taken for HEIGHT, WIDTH, and DEPTH (all in feet). With these measurements the tank volume can be determined as well as inches per bbl and bbl per inch. H e i g h t W i d th D e p thF e e t F e e t F e e t× × × .1 7 8 1 T a n k V o l u m e T a n k H e i g h t B B L I n c h e s T a n k H e i g h t T a n k V o l u m e I n c h e s B B L Tripping Kicks During Workovers Tank Volume in BBL BBL Per Inch Inches Per BBL Determining Trip Tank Volume
Well Control During Workovers and Completions 61 Occasionally a vertical cylindrical tank (frac tank) is used as a trip tank. Calculating the volume in this situation is different from the vertical rectangular tank, but not difficult. The two dimensions required are the DIAMETER in inches and the HEIGHT in feet. Tank Volume in BBL Tripping Kicks During Workovers Ft inches Height IDTank ×      4.1029 2 T a n k V o l u m e T a n k H e i g h t B B L I n c h e s T a n k H e i g h t T a n k V o l u m e I n c h e s B B L BBL Per Inch Inches Per BBL Determining Trip Tank Volume
Well Control During Workovers and Completions 62 Tripping Kicks During Workovers What If You Don’t Have A trip Tank If a trip tank is unavailable on can easily be fashioned from just about anything that will retain liquid: a 55 gallon drum, a large plastic trash can, etc. The volume and calibration of these containers can be calculated as explained on the preceding pages and a trip can be conducted successfully and safely. And remember, if need be, 8.4 or roughly 8 ½ 5 gallon buckets is a BBL. There’s really no reason why workstring displacement can not accurately be monitored during the course of a workover, no matter how ill-equipped the rig.
Well Control During Workovers and Completions 63 Tripping Kicks During Workovers Swabbing Swab Pressure is a negative pressure created anytime the workstring is moved in an upward direction. The magnitude of the swab pressure created is based on: Speed of the upward pipe movement Clearance between the workstring and casing Workover fluid properties Excessive swab pressure can cause a dead well to kick, and if not handled properly can lead to a surface blowout.
Well Control During Workovers and Completions 64 STEP 1 FORCE AROUND THE WORKSTRING STEP 3 FORCE AROUND THE DRILL COLLARS W o r k s t r i n g O D S u r f a c e P S I2 7 8 5 4× ×. D r i l l C o l l a r O D S u r f a c e P S I2 7 8 5 4× ×. STEP 2 MINIMUM ALLOWABLE WORKSTRING LENGTH F o r c e o n W o r k s t r i n g A d j u s t e d W o r k s t r i n g W e i g h t F e e t F T# / = STEP 4 MINIMUM ALLOWABLE COLLAR LENGTH F o r c e o n D r i l l C o l l a r s D r i l l C o l l a r W e i g h t F e e t F T# / = If collars are being used If collars are being used Tripping With The Well Flowing Tripping Kicks During Workovers
Well Control During Workovers and Completions 65 Estimating the weight of the workstring at any given time during the trip is a simple matter of adding the weight of the BHA to the weight of the remaining drill pipe in the hole. The following formula can be used to determine the weight of each section of the drill string, i.e., tubing and/or BHA. W e i g h t L e n g t h I n H o l e T o t a l W e i g h tF T L B S# / × = As stated above, this formula can be applied to both sections of the workstring to arrive at the weight of each individual section. By adding the total weights of the two sections one arrives at the weight of the string. T o t a l W o r k s t r i n g W e i g h t T o t a l C o l l a r W e i g h t S t r i n g W e i g h t+ = Tripping Kicks During Workovers
Well Control During Workovers and Completions 66 Unlike drilling, where mud weights generally increase as the hole is deepened, fluid weight in a completion or workover is, for the most part, fairly consistent. Should the fluid weight decrease due to dilution from produced fluids or accidental dilution on the surface, a kick is liable to occur. The fluid weights should be monitored for proper values at all times during the workover work. When using brines the pits should be covered to prevent dilution from ambient humidity. The higher the brine density the more affinity it will have for fresh water and the more prone it is to becoming “cut” by the contamination from humidity. Not only this, but a high density brine can be quite expensive and reconditioning the fluid will be an added cost to the completion or workover - one which can easily be avoided. Insufficient Fluid Weight Loss of Circulation Another source of a kick, although not as common as the preceding three, is loss of circulation. When fluid is lost to the hole it is generally assumed to be lost to the producing formation, and in many cases it is. But this is not always the case. If communication has been established to an upper zone with a pore pressure greater than the producing formation, a flow can take place from the invaded zone into the wellbore and into the producing formation. Not only would a kick be in progress with formation fluids entering the wellbore, but an underground blowout (zone-to-zone flow) as well. This type of well control situation can be difficult, at best, to contain and can oftentimes lead to severe damage to the producing formation, loss of an appreciable amount of production, if not the loss of the productive interval brought about by the required kill techniques. Kicks During WorkoversCauses of Kicks
Well Control During Workovers and Completions 67 Unseating Packers Several different types of packers may be used in a completion and more than one are generally left in the hole, especially for the nearly universal gravel-packed producing zone(s). Therefore a workover usually involves unseating or pulling the seal assembly from several packers, most of which will have some accumulation of formation fluids trapped below them. The fluids accumulate in the dead space between the bottom of the packer rubber and the topmost opening in the tubing extension below the seal nipples. If the well has not previously been completely killed on the tubing side, then the entire rat-hole below the packer may contain formation fluids. If the well makes any gas at all, the trapped volume will be full of gas because of gravity segregation. When the packer is unseated or the seals pulled above the packer bore, the trapped gas escapes into the annulus and starts migrating up the wellbore. The release of the gas above the packer does not itself threaten to make the well flow at the moment it occurs because the bottomhole pressure has not been changed significantly. However there is seldom any immediate surface indication that the trapped gas is there and the crew may be unaware of the possible danger. Kicks During WorkoversCauses of Kicks
Well Control During Workovers and Completions 68 Tripping with Fluid Losses Fluid losses to the formation are commonplace in workover/completion operations. The rate of such loss varies with formation permeability, fluid viscosity, degree of overbalance, pipe- induced pressure surges, and pressures caused by circulation of the wellbore. These losses add another dangerous dimension to tripping the pipe, already established as the most kick-prone activity in any oil/gas well operation. A wide range of viscosifiers and solids are used to control loss rates. In preparation for tripping, plans generally call for bringing the fluid loss down to a maximum that varies from 10 to 20 barrels per hour, depending on the stage of the completion, formation sensitivity, and the difficulty of achieving the desired cap without undue formation damage. If the loss rate, once brought down to an acceptable range, remains consistent while tripping, monitoring the proper fill on the way out is more straight forward. Despite the numerous differences between drilling/completion/workover work, the warning signs that indicate an actual or potential well control problem while tripping are unchanged. We still watch for a flow, a pit gain, or the hole not taking the right volume. All of these conditions are much easier to assess if the fluid loss rate is known and stable. Unfortunately the loss rate can vary with pipe movement itself and the simple passage of time. Kicks During WorkoversCauses of Kicks
Well Control During Workovers and Completions 69 Fishing Efforts to recover tools or pipe lost in the hole can add to the likelihood of a kick or the difficulty of controlling one in several ways: • More trips • Fish swabbing or interfering with circulation • Long periods with the hole uncalculated Fishing by its very nature greatly increases the number of trips. While this is true also of fishing while drilling, all of the differences described earlier combine to make that increase more risky in the workover and completion environment. The fish itself, especially if it includes a packer or a multi-way circulating port, can add greatly to in-hole pressure surges. If it is blanked off or the fishing tool cannot seal on its top, the fish becomes a barrier to full-hole circulation - the longer the fish, the greater the effect. If the fish is long, or the fishing is done by wireline, the hole may be uncirculated for extended periods, during which formation fluids may be working in the wellbore where they cannot be removed. The gas in the hole can migrate during trips and cause well flow. All of these considerations lean toward the possibility of a kick at that worst possible time - when the worksting is far off bottom or out of the hole. Finally, in a prolonged fishing job another disquieting element sneaks into the picture - the human one. Repetitive trips and concentration on the details of the fishing job itself tend to develop complacency or at least relaxation of vigilance. Kicks During WorkoversCauses of Kicks
Well Control During Workovers and Completions 70 Cleaning Out Fill Circulating to remove fill from the active wellbore occurs with frequency in completions and workovers. It is a routine operation in most cases, involving short intervals of loosely packed sand, scale, coal fill, or other debris following such operations as perforating, testing, or gravel packing. The fill is merely a temporary impediment to the next step in the program. It is most often cleaned out and without incident, generally by reversing out under a closed annular preventer or tubing stripper while lowering the pipe fitted with appropriate cleanout tools. However, sometimes the fill results from sanding up of the well while on production or from a kick that brought formation solids into the wellbore. These problems can effectively seal off the producing zone from the hole above the fill, possibly at considerable distances off bottom. Then when the fill is cleaned out, usually circulating the long way because of the extended intervals involved, any break in the continuity of the fill can expose trapped formation fluids. This can lead to repeated requirements to circulate the well clean under the choke or through a blooie line. Kicks During WorkoversCauses of Kicks
Well Control During Workovers and Completions 71 When a wash tool or muleshoe breaks completely through the fill it may turn out to be a bridge a long way off bottom. Under these conditions a long column of formation fluids can exist below the bridge, and the hydrostatic available above the bottom of the workstring may be inadequate to hold the formation pressure. The general effect is a kick off bottom with the rat-hole full of gas and oil. On the other hand, if the breakthrough occurs near enough to the perforations that the well is considerably overbalanced, the fluid level in the annulus can drop suddenly and allow the well to kick. Either way, the result is an off-bottom kick with unpredictable lost returns to complicate the kill. Cleaning Out Fill Kicks During WorkoversCauses of Kicks
Well Control During Workovers and Completions 72 • Flow increase without an increase in pump rate • Pit level increase • Well flows with the pump off Flow Increase Pit Level Increase Well Flowing With Pumps Off While Circulating Kicks During Workovers
Well Control During Workovers and Completions 73 Kicks During Workovers The three main indicators of unintentional kicks all deal with flow from the formation into the wellbore. One common workover procedure deals with the plugging and abandonment of one zone and the initiation of production from another. This is usually done by setting bridge plug above the zone to be abandoned and then placing cement on the bridge plug. In other instances merely a cement plug is placed across perforations. In either case, it’s always a good idea to check the well for flow after waiting for the cement to cure. There is a possibility for cement contamination from formation fluids which can prevent the cement from setting up properly. When this happens gas can channel its way through the cement. If this happens, another cement plug has to be placed over the failed one. Additionally, additives should be mixed with the cement to minimize or inhibit contamination.
Well Control During Workovers and Completions 74 Additional warning signs can appear prior to or in conjunction with a kick. Gas cutting of the workover fluid Kicks During Workovers Although gas cutting unto itself is not an indicative sign of a kick, it should be at least a warning to the crew that gas has invaded the wellbore. Gas can reduce the density of the workover fluid at the surface because of the expansion of the gas as it surfaces, but the overall reduction in hydrostatic pressure is usually minimal. Which is not to say that gas breaking out of the fluid at the surface should be ignored.
Well Control During Workovers and Completions 75 Oil shows in the workover fluid Oil shows in the workover fluid will, to a small degree, reduce the hydrostatic pressure of the fluid column, but only minimally so. But like gas, it is a sign of formation fluid invasion and should be checked out. Additional warning signs can appear prior to or in conjunction with a kick. Kicks During Workovers
Well Control During Workovers and Completions 76 Prior to beginning the trip, there should be at least one bottoms-up circulation. During this time the returning fluid density should be checked on a regular basis, every 5 to 10 minutes, and recorded. Along with this, there should be notes made as to any show of formation fluids. After the bottoms-up circulation is completed, the well should be allowed to remain static for a period of time to make sure it’s dead before the trip out begins. Inadequate Hole Fill During Trips The most reliable indicator of a well control problem while tripping is fill-up volumes that don’t correspond, within reason, to calculated values. Should this occur anytime during the trip, the trip should be stopped and the well monitored closely for flow. And when in doubt, don’t hesitate to shut-in the well. If fill-up trends continue to show discrepancies, stop the trip and return to bottom. Once on bottom be prepared to shut-in the well and circulate the well on a choke. Likewise when tripping in the hole, the volume being returned due to displacement should be monitored. If the volume returned is greater than calculated displacement, be prepared to shut-in. Well Flowing While The Pipe Is Stationary (Tripping In) This should be fairly obvious, but all too often, crews get so involved with the business of tripping in the hole, that the hole can go unmonitored. Flow while the pipe is stationary can go undetected for quite some time. MONITOR THE DISPLACEMENT TRIPPING IN AND OUT OF THE WELL. While Tripping Kicks During Workovers
Well Control During Workovers and Completions 77 Shut-In Procedures - On Bottom Circulating – Surface Stack 1. With the pump(s) running, pick up off bottom to pre-determined space off height to ensure a tool joint is not across the stack. 2. Stop the pump(s) and check for flow. 3. If flow exists, shut-in the top set of pipe rams. 4. Gain casing access by opening the appropriate valve on the choke line side of the stack. 5. Open the valve downstream of the choke. 6. Record SITP and SICP and estimate of pit gain. 7. At this point, the annular preventer, if one is installed, could be closed and the top pipe rams opened. Shut-In Procedures - On Bottom Circulating – Surface Stack Containing a kick and keeping the influx volume to a minimum can not be overemphasized. The shut-in, or containment procedures, can vary depending on the type of unit in use, coiled tubing, snubbing, small tubing, or conventional workover rig and the operation in progress at the time of the kick - on bottom circulating or tripping. The shut-in procedures given below will apply to a conventional workover rig and small tubing unit. Containment procedures for coiled tubing and snubbing units will be handled in their respective chapters. The shut-in procedures given below are done under the premise of the “hard shut-in.” Due to the limited wellbore volumes available in a completed well or one being worked over, it is imperative that minimal time be expended in shutting in a well. Kicks During Workovers
Well Control During Workovers and Completions 78 1. Stop the trip and position the pipe ensuring there is not a tool joint across the stack. 2. Secure the workstring by installing a full opening safety valve - close the safety valve after installation. 3. Shut-in the top pipe rams. 4. Gain casing access by opening the appropriate valve on the choke line side of the stack. 5. Open the valve downstream of the choke. 6. Record SICP and estimate of pit gain. 7. Have an inside BOP (workstring check valve) available in case stripping is required. 8. At this point, the annular preventer, if one is installed, could be closed and the top pipe rams opened. Shut-In Procedures While Tripping – Surface Stack Kicks During Workovers
Well Control During Workovers and Completions 79 Additional Considerations: Have crossovers on the floor so that the full opening safety valve and inside BOP can be installed onto any component of the workstring. Be familiar with the closing volumes of the preventers to be used. Visually inspect the BOP stack and choke manifold for leaks shortly after shut-in. Have someone continuously monitoring and recording shut-in pressures every minute. Kicks During Workovers
Well Control During Workovers and Completions 80 Immediately following shut-in, the casing pressure should be monitored and pressure recorded on a regular basis. Thirty-second intervals would not be unrealistic, especially if the workover fluid lacks viscosifying agents. Untreated workover fluids characteristically have little to no static surface tension and therefore gas migration is certain to occur. Unless the pressure is continually monitored during the first few minutes after shut-in, it may be impossible to ascertain a stable shut-in casing pressure which would be the casing pressure to maintain during pump start-up assuring bottomhole pressure maintenance. With gas migration in progress, a highly possible outcome could be a bottomhole pressure substantially greater than formation pressure which could cause a loss of fluid to the perfs, possible damage to the producing formation, or formation fracture. PSI Time Hypothetical stabilization point may not be of long duration Continual pressure increase due to gas migration Kicks During Workovers
Well Control During Workovers and Completions 81 The illustration at left describes the pressures at work in a stabilized shut-in situation. The total hydrostatic on either side of the well is imposed upon by formation pressure. Any difference, or differential, appears on the surface and indicates the amount of hydrostatic that must be replaced to at least balance formation pressure. Often times in a completion or workover, there is no SITP, provided the shut-in took place properly. The lack of pressure on the tubing indicates the fluid density in the tubing at least balances formation pressure. A presence of tubing pressure could be due to trapped pressure. Hydrostatic of Workover Fluid Hydrostatic of Influx SITP SICP + + + Formation Pressure Total PressureTotal Pressure Kicks During Workovers Hydrostatic of Workover Fluid
Well Control During Workovers and Completions 82 As seen from the previous page, the combination of shut-in pressure and hydrostatic pressure on either side of the well creates a total pressure equal to formation pressure. Or in essence, bottomhole pressure equaling formation pressure. Any pressure in the wellbore which creates a bottomhole pressure in excess of formation pressure would show up at the surface. Sources of trapped pressure are: • The pump inadvertently left running after shut-in • Pumping into a shut-in well • Surface pressure increase caused by migrating gas unable to expand When shut in pressures are initially recorded following stabilization, it’s a good idea to determine if these pressures are accurate, i.e., representative of just the differential between formation pressure and wellbore hydrostatics. The following procedure can be used to detect the presence of trapped pressure and to remedy the situation if any is found. Perform this only after surface pressures have stabilized. STEP 1 Bleed a small amount of fluid through the choke (1/4 to 1/2 bbl) - surface pressures will initially decrease, build, and then stabilize. STEP 2 Observe SITP - if the SITP stabilized at a value less than the previously observed stable pressure, trapped pressure was detected and at least, partially bled off. STEP 3 Bleed another small amount of fluid through the choke and once again observe the stabilized SITP. STEP 4 True, or accurate, SITP is realized when consecutive and identical values appear on the tubing gauge - in most cases in completions and workovers, the SITP should bleed to 0 psi. Kicks During Workovers
Well Control During Workovers and Completions 83 Kicks During Workovers SHUT IN SURFACE PRESSURES In both cases, the SITP and SICP are measuring the same thing: Differential pressure between the total hydrostatic pressure on either side of the well with respect to formation pressure. In most cases, the casing pressure is greater than the tubing pressure due to the reduced annular hydrostatic pressure caused by the presence of influx fluid/s which are of lesser density than the workover fluid. And as previously stated, in most cases during a workover, the SITP will be 0 psi because Kill Weight Fluid is already in the wellbore. If the SITP does not bleed to 0 psi (check the pressure with more than one pressure gauge), then check the density of the workover fluid – it may have become inadvertently light because of contamination of excessive formation fluid or by accidental dillution.
Well Control During Workovers and Completions 84  Shut-in Tubing Pressure is the difference between hydrostatic and formation pressure.  Kill weight fluid is calculated using the Shut-in Tubing Pressure.  Always round up to next highest tenth ppg. The following two formulas can be used to calculate Kill Weight Fluid: Kill Weight Fluid should be the exact fluid weight required to balance formation pressure (no overbalance margin or safety factor). Kicks During Workovers ( ) Pits Vertical PSI WtFluid DepthPerf SITP +      ×052. ( ) Pits Vertical WtFluid DepthPerf SITP . 23.19 +      × Either formula will render the same results
Well Control During Workovers and Completions 85 Kicks During Workovers Wellbore Volume In any well control operation it is necessary to know the wellbore volume. The following two formulas are used to accomplish this: BBLMeasured Tbg VolumeLength ID =×         4.1029 2 Tubing Volume Annular Volume ( ) BBLMeasured TbgCsg VolumeLength ODID =×         − 4.1029 22
Well Control During Workovers and Completions 86 Gas Migration After a well is shut-in the gaseous phase of the kick can start migrating up the hole. This is especially true during workovers and completions due to the lack of viscosity in the workover fluid. Migrating rates can vary from a few hundred feet per minute upwards to as high as several thousand feet per minute. If pumping can start soon after the well is shut in and stabilized, gas migration is not an issue. But if pumping is delayed, for what ever reason, gas will begin to migrate up the hole. Evidence of migration is steadily increasing surface pressures. Gas behaves according to a “pressure-to-volume” relationship: If exerted pressure increases the volume decreases. If exerted pressure decreases the volume increases. If the volume is not allowed to expand, the pressure within the gas remain unchanged.
Well Control During Workovers and Completions 87 Gas Migration The following information will be used to illustrate what can happen to migrating gas in a well: Formation Pressure: 5500 psi Annular Hydrostatic: 5000 psi Tubing Hydrostatic: 5500 psi SITP: 0 psi SICP: 500 psi 0 PSI 500 psi
Well Control During Workovers and Completions 88 Gas Migration The gas has migrated halfway up the hole but no fluid has been bled from the well. Since the gas volume has not changed it still contains its original pressure, in this case, 5500 psi. 5500 psi 2500 psi hydrostatic above the gas 2500 psi hydrostatic below the gas 3000 psi 2500 psi Bottom hole pressure = 8000 psi 5500 2500 HP 2500 HP 8000 psi 3000 psi Annulus 5500 HP 8000 psi 2500 psi Tubing
Well Control During Workovers and Completions 89 Gas Migration The gas has migrated to the surface- no fluid has been bled from the well. Since the gas volume has not changed it still contains its original pressure, in this case, 5500 psi. 5500 psi 5000 psi hydrostatic below the gas 5500 psi 5000 psi Bottom hole pressure = 10500 psi 5500 5000 HP 10500 psi 5500 psi Annulus 5500 HP 10500 psi 5000 psi Tubing
Well Control During Workovers and Completions 90 Gas Migration It should be obvious from the preceding two pages that if gas migrates up the hole in an unexpanded state, bottom hole and surface pressure can increase dramatically which can lead to excessive fluid loss to the formation and undue stress on surface pressure control equipment and the casing. There are two methods available to handle this situation which will maintain bottom hole pressure equal to, or slightly greater than formation pressure, and keep surface pressures to a minimum. The first method involves using the choke to maintain a constant pressure on the workstring while migration is in progress. The second method, again, involves using the choke to bleed off measured amounts of fluid along a prescribed schedule. Neither method is difficult and requires a minimum of equipment. It should be understood that these methods are to be employed only if pumping is not possible at the time migration starts, and the methods should be used until pumping is possible, and at that time, the well put on choke and circulated. It should also be understood that neither of these two methods will kill the well. They are simply used to prevent excessive increases in bottom hole and surface pressures.
Well Control During Workovers and Completions 91 0 psi 500 psi We’ll use the earlier example to illustrate this method. The SITP is 0 psi indicating that the hydrostatic pressure of the fluid in the hole at least balances the formation pressure. There is pressure on the casing due to the presence of gas in the annulus which has decreed the annular hydrostatic. Gas Migration Constant Tubing Pressure
Well Control During Workovers and Completions 92 200 psi 700 psi Gas Migration Constant Tubing Pressure MethodShortly after the well is shut in the gas begins to migrate in an unexpanded state. Evidence of the migration is seen at the surface by increasing surface pressures. Since the surface pressure have increase by 100 psi, bottom hole pressure has also increased by 100 psi. It’s a good idea to incorporate a small overbalance and this initial increase in surface pressure can be used for that. Keep monitoring the tubing pressure as migration continues. Allow a second pressure increase to take place. This second increase will be used for bleeding fluid. Bottom hole pressure has increased by 200 psi above formation pressure PSI TIME Casing Tubing 200 psi increase 100 psi for overbalance 100 psi for fluid bleeding 0 100 200 300 400 500 600 700 800
Well Control During Workovers and Completions 93 Gas Migration Constant Tubing Pressure Method 200 psi 700 psi Bottom hole pressure has increased by 200 psi above formation pressure PSI TIME Casing Tubing 200 psi increase 100 psi for overbalance 100 psi for fluid bleeding 0 100 200 300 400 500 600 700 800 Following the initial increase of 200 psi, bleeding can take place. Fluid is to be bled through a choke from the annulus side only. Monitor the casing pressure while bleeding decreasing the casing pressure by, in this case, 100 psi, then close the choke. Monitor the tubing pressure. If the bleeding was performed correctly, the tubing pressure will decrease by 100 psi and stabilize. Because of the annular bleeding, annular hydrostatic is now decreased. This may cause a slight increase in casing pressure. Fluid bled and pressures stabilize
Well Control During Workovers and Completions 94 Gas Migration Constant Tubing Pressure Method 100 psi 620 psi Bottom hole pressure has increased by 100 psi above formation pressure PSI TIME Casing Tubing 0 100 200 300 400 500 600 700 800 100 psi increase Migration continues after the first bleeding cycle and surface pressures have increased by another 100 psi. Perform another bleeding cycle. Fluid bled and pressures stabilize
Well Control During Workovers and Completions 95 Gas Migration Constant Tubing Pressure Method PSI TIME Casing Tubing 0 100 200 300 400 500 600 700 800 Continued bleeding cycles would result in what is seen plotted below. Casing pressure would increase due to the constant decrease in hydrostatic pressure but tubing pressure would remain essentially constant. This means that bottom hole pressure is maintained constant at a level just above formation pressure resulting in minimal fluid loss to the formation. Gradually increasing casing pressure Constant tubing pressure
Well Control During Workovers and Completions 96 Gas Migration Volumetric Method 0 psi 500 psi Obstruction in tubing In this situation a kick has been taken but due to an obstruction in the tubing, circulation is impossible. Shortly following shut in the gas begins to migrate. Because of the obstruction there is no tubing pressure to monitor, and the Constant Tubing Pressure Method can not be used on the annulus because of its ever- changing hydrostatic pressure caused by the required bleeding. The method used to handle this situation is called the Volumetric Method.
Well Control During Workovers and Completions 97 Gas Migration Volumetric Method The Volumetric Method is used when pumping is impossible due to an obstruction in the workstring. In this situation the casing pressure would increase but the tubing pressure would remain at 0 psi. Similar to the Constant Tubing Pressure Method, the annular surface pressure is allowed to increase by an overbalance and an amount used for bleeding. However, in this case, the volume to bleed from the annulus is calculated based on the surface pressure increase, the wellbore geometry at the point where fluid is leaving the annulus, and the density of the fluid in the hole. The following is used to calculate this volume. ( ) BleedtoBBL WtFluidODID IncreasePSI TbgCsg =                       ××− .052. 4.1029 22
Well Control During Workovers and Completions 98 Gas Migration 0 psi 700 psi PSI TIME 200 psi increase 100 psi for overbalance 100 psi for fluid bleeding 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 Similar to the Constant Tubing Pressure Method, surface pressure is allowed to increase for an overbalance and an amount used for bleeding. In this case, 100 psi increments will be used again. Information for an example calculation is as follows: Csg ID: 5.125” Tbg OD: 2.875” Fluid Wt. 10.4 ppg Volumetric Method
Well Control During Workovers and Completions 99 Gas Migration ( ) BBL psi 323.3 4.10052.875.2125.5 5.1029 100 22 ≈=                     ××− Volumetric Method The calculated volume is rounded off to accommodate rig equipment and volumes that can be realistically measured. PSI TIME/BBL BLED 200 psi increase 100 psi for overbalance 100 psi for fluid bleeding 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 During the first cycle three bbl of fluid is to be bled from the annulus through the choke while maintaining a constant casing pressure. The length of time required for this depends on the migration rate of the gas. After bleeding the calculated volume the choke is closed and casing pressure is monitored while migration progresses. Another 100 psi increase would signal the beginning of the second cycle. First bleeding cycle
Well Control During Workovers and Completions 100 Gas Migration Volumetric Method PSI 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 The second cycle take place with the bleeding of 3 bbl of fluid from the annulus while holding the casing pressure constant. The procedure continues until gas reaches the surface or when pumping is possible. If gas reaches the surface the casing pressure should be monitored. As long as casing pressure increases continue the bleeding procedures. Casing pressure will finally peak when all the gas reaches the surface when migration stops. TIME/BBL BLED Second bleeding cycle Once gas reaches the surface, it should be either circulated out or removed by lubrication and bleeding. The gas should not be bled without replacing it with fluid. Doing so would create a serious well control situation that could lead to a surface blowout.
Well Control During Workovers and Completions 101 Example: A 100 psi surface pressure increase has taken place in 45 minutes. The fluid in the hole is 8.5 ppg water. Based on this the migration rate can be calculated as such: Gas Migration Gas Migration Rate ( ) HrFt Hours RateMigration TimeWtFluid IncreasePSI / .052. = ×× ( ) FeetMigrated WtFluid IncreasePSI = ×052. ( ) HrFt Hoursppg psi /30265.301 75.5.8052. 100 ≈= ×× ( ) Feet ppg psi 22624.226 5.8052. 100 ≈= × If the tubing is obstructed it may be desired to find the depth of the obstruction with wireline and possibly remove it or perforate above the obstruction in order to kill the well by circulation. The following two formulas can be used to determine the depth of the bottom of the gas and how fast or slow the gas is moving up the hole. If it is decided to perforate the tubing, make sure the perforation occurs below the kick to prevent contamination of the workstring fluid.
Well Control During Workovers and Completions 102 Gas Migration Uncontrolled Gas Expansion All kick management methods, circulating and non-circulating, deal with controlling gas expansion in a wellbore, and for good reason - uncontrolled gas expansion can be catastrophic which is why there should be constant and consistent monitoring of pit levels, return flow rates, and fluid density. Gas expansion is affected by the following: Pressure exerted on the gas Gas volume Temperature For simplicity temperature will be ignored in this example of uncontrolled gas expansion. Gas expansion can be described by the following relationship: 2 1 P P P1 - initial pressure exerted on the gas P2 - new pressure exerted on the gas
Well Control During Workovers and Completions 103 Gas Migration Uncontrolled Gas Expansion The following information will be used to illustrate the potential for uncontrolled gas expansion: Well Depth: 10000 feet Fluid Weight: 9.5 ppg Kick Volume: 10 bbl Casing ID: 5 ¼”
Well Control During Workovers and Completions 104 Gas Migration Uncontrolled Gas Expansion The initial pressure exerted on the gas is a combination of wellbore hydrostatic pressure and surface pressure. Length of the Gas '373'47.37310 25.5 4.1029 2 ≈=×      KickBBL Length & Hydrostatic Pressure of Fluid Above the Gas FeetGasofFtFT 962737310000 =− PSIFeetPPG 47567.475596275.9052. ≈=×× P1 = 4756PSI As the gas moves up the hole the hydrostatic pressure above the gas decreases thus allowing the gas to expand.
Well Control During Workovers and Completions 105 Gas Migration Uncontrolled Gas Expansion The gas has migrated up the hole to the depth of 5000’. The expanded gas volume is calculated as follows: ( ) BBLBBL FeetPPG PSI 25.1910 50005.9052. 4756 =× ×× BBLVolumeKickInitial P P ×      2 1 The gas moved halfway up the hole and almost doubled in volume.
Well Control During Workovers and Completions 106 Gas Migration Uncontrolled Gas Expansion The gas is now at a depth of 2500 feet. The expanded gas volume is calculated based on the initial pressure versus the new pressure exerted on the gas. ( ) BBLBBLBBL FeetPPG PSI 3951.3810 25005.9052. 4756 ≈=× ×× Based on the reduction in hydrostatic pressure above the gas it has expanded almost 4 times its initial volume.
Well Control During Workovers and Completions 107 Gas Migration Uncontrolled Gas Expansion The gas is now at the surface where the only pressure exerted on the gas is atmospheric pressure. The expanded volume of the gas is: BBLBBL PSI PSI 3245.32310 7.14 4756 ≈=× In thus case the uncontrolled gas expansion exceeds the wellbore volume. Hopefully, if gas enters a wellbore and starts to migrate or is circulated up the hole and expands, the displacement of fluid caused by this expansion will be noticed by someone on location and appropriate actions taken. Otherwise the well will surely blowout.
Well Control During Workovers and Completions 108 A method of killing a well should allow for regaining control of the well without doing harm to the producing formation, and should also exert a bottom hole pressure that is at least equal to, or slightly greater than formation pressure. As previously stated, the SITP is used as a bottom hole pressure gauge and is indicative of any existing differential between formation pressure and the fluid hydrostatic in the workstring. A pressure existing on the tubing gauge indicates the required additional hydrostatic pressure needed to balance formation pressure, and this additional hydrostatic is converted into its equivalent in mud weight via the kill weight mud formula. SITP > 0 psi means the fluid weight must be increased (with the tubing at or very near bottom) There are two methods available to use if the condition exists dictating a fluid weight increase: Wait & Weight Method This method is, in theory, a one-circulation kill method. The crew “waits” until the fluid is at the proper kill “weight” and then pumps kill weight fluid only with no additional safety factors in the form of additional weight. The overbalance at the bottom of the hole is provided by annular friction once circulation is under way. In most cases this method creates the least amount of wellbore stress and the lowest ultimate annular surface pressure. Constant Pump Pressure The Driller’s Method is designed to be a two-circulation kill operation. During the first bottoms-up circulation the kick is pumped from the well. Fluid weight is increased during this time and is pumped into the well on the second circulation. Like the Wait & Weight, an overbalance is provided for at the bottom of the hole in the form of annular friction pressure. This method usually creates higher wellbore stresses and higher ultimate annular surface pressure than the Wait & Weight. One advantage of the method is that circulation can begin shortly after shut-in pressures have stabilized. Circulating Kill Techniques
Well Control During Workovers and Completions 109 If there is no pressure on the tubing with the bit at or near bottom, no differential exists and no fluid weight increase is needed. SITP = 0 psi means no fluid weight increase In this instance, with no SITP, the Constant Pump Pressure method is used, which is exactly what needs to take place. The pump pressure is held constant while the well is circulated at a steady rate. After bottoms-up is achieved, the well should be dead. Prudence however, dictates that the well be circulated for a while longer just to make sure the annulus is completely free of influx. SITP > 0 psi Wait & Weight Method Concerns about ultimate annular surface pressure (gas kick) Driller’s Method Desire to begin killing shortly after surface pressure stabilization SITP = 0 psi Constant Pump Pressure Kill the well at a constant pump pressure and pump rate Circulating Kill Techniques
Well Control During Workovers and Completions 110 Circulating Kill Techniques Constant Pump Pressure By far the most commonly used circulation method is Constant Pump Pressure. Its name implies exactly what is to be done – maintain a constant pump pressure, at a constant pump rate, once the well is successfully brought on choke. To bring the well on choke perform the following: STEP 1 Observe and record the SICP STEP 2 Crack the choke and bring the pump online. STEP 3 While bringing the pump up to the selected kill rate, manipulate the choke to maintain a constant casing pressure. STEP 4 After the pump is at the kill rate, manipulate the choke to maintain a constant pump pressure until the well is dead.
Well Control During Workovers and Completions 111 The Wait and Weight Method gets it’s name from the fact that there is a “waiting” time while the mud weight is increased or “weighted” up prior to circulating the influx from the hole. The W & W Method is only required for killing a kick that requires a heavier fluid weight (called the kill weight fluid). Generally the well can be killed in one complete circulation. But, since it is only recommended to use a balancing kill fluid weight, additional circulation will be required to increase the fluid weight by a suitable safety factor after the well is dead. Advantages Include  Pressures exerted on the wellbore and on control equipment will generally be lower than when using the Driller’s Method. The difference is most significant if the influx is gas, and/or large volume kicks.  The maximum pressure exerted on the wellbore is the lowest is can be  The maximum annular surface pressure is as low as possible given the situation  The well will be under pressure for less time. Circulating Kill Techniques Wait & Weight Method
Well Control During Workovers and Completions 112 1. Determine a suitable circulation rate. The upper limit for the circulation rate is generally set by the maximum allowable annular friction pressure such that extreme ECD’s are not created. 2. Kill Weight Fluid (KWF). The kill weight fluid, which is a known value. The fluid in the pits must be weighted-up to the Kill Weight. 3. Calculate the workstring and annulus volumes and Surface to Bit and bottoms up pump strokes. The workstring and annular volumes need be known to determine where the influx and kill weight fluid is within the circulation path during the well kill. This data is usually obtained from the completed kill sheet. Vertical and Low Angle Wells Circulating Kill Techniques StrokesTotal OutputPump VolumeWellbore STKBBL BBL = /
Well Control During Workovers and Completions 113 4. Calculate the anticipated Initial Circulating Pressure (ICP). The ICP should be calculated in order to estimate the circulating pressure that will be required to maintain constant BHP at the start of the well kill. 5. Calculate the Final Circulating Pressure (FCP). As the workstring is displaced with kill weight fluid, the circulating standpipe pressure must be reduced to take into account the increased hydrostatic pressure of the mud in the pipe. The standpipe pressure must also compensate for the increase in friction pressure due to pumping a heavier weight fluid. Once the workstring is completely displaced with KWM, the static workstring pressure should be zero. The required circulating standpipe pressure at this point is just the SCR pressure adjusted for the KWF. 6. Construct a circulating drillpipe pressure schedule vs. pump strokes. The choke operator needs to manipulate the control choke to follow the schedule of circulating drillpipe pressure (required to maintain constant BHP) verses the accumulated pump strokes during the well kill. This will ensure the well kill is going smoothly and help identify any potential problems that may occur. Vertical and Low Angle Wells Circulating Kill Techniques
Well Control During Workovers and Completions 114 1. Bring pump on line as per Pump Start-up procedure. 2. Compare the actual Initial Circulating Pressure to that shown (calculated) on the Tbg. Pressure Schedule. Re-construct the Tbg. Circulating Schedule if necessary. 3. Adjust the choke as necessary to control the drillpipe pressure according to the schedule. Continue until kill weight fluid returns to the surface.  Always be alert to potential problems. If ANY problem is suspected, STOP the pump and CLOSE the well in. 4. Stop the pump and close the choke. SITP and the SICP should be equal or nearly equal to zero. If so, open choke and check for flow. If not, bring pump back on line and circulate through the choke to further condition the mud. Pump Strokes Circ. Pressure (psi) 0 ICP (psi) FCP (psi) Strokes To Bit (1) (2) (3) (4) (5) (6) (7) (8) (10) (9) Circulating Pressure Schedule Vertical and Low Angle Wells Circulating Kill Techniques
Well Control During Workovers and Completions 115 Choke and Standpipe Pressure WELL DATA: Well depth 11,480 ft BHA 6 ½”, 591 ft Shoe depth 6,560 ft Pipe 5” OD DP MW 14.2 ppg Method Driller’s Kick EMW 15.2 ppg Influx 20 bbls gas SIDPP 600 psi SCR 500 psi @ 30 spm Volume Pumped (bbls) SurfacePressure(ps drillpipe Volume 800600400200 SCR SIDPP Annulus Volume 200 400 600 800 1000 1200 1600 1400 1800 Choke Pressure (W and M Method) Choke Pressure (Driller’s Method) SCR (FCP) Stand Pipe Pressure A B C D E Circulating Kill Techniques
Well Control During Workovers and Completions 116 1. Bring pump on line as per Pump Start-up. 2. Compare the actual Initial Circulating Pressure to the pre-calculated ICP. If the actual measured ICP is greater that the pre-calculated ICP, correct the kill sheet and use the actual ICP.  If the actual ICP is less than the calculated ICP, stop the pump and close the well in. Determine if there are any problems in the circulating system. 3. Adjust the choke as necessary to control drillpipe pressure constant until all influx is circulated from well.  Always be alert to potential problems. If ANY problem is suspected, STOP the pump and CLOSE the well in. 4. Stop the pump and close the choke. SITP and SICP should be equal or near equal. If so (and necessary), then kill the well using the W & W method. If not, bring the pump back on line and circulate through choke to condition wellbore fluids. Circulating Kill Techniques
Well Control During Workovers and Completions 117Volume Pumped (bbls) Pressure(psi) 1800 1600 1400 1200 1000 800 600 400 200 200 400 600 800 Stand Pipe Pressure Choke Pressure A B C D E First Circulation - Choke and Standpipe Pressure WELL DATA: Well depth 11,480 ft BHA 6 ½”, 591 ft Shoe depth 6,560 ft Pipe 5” OD DP MW 14.2 ppg Method Driller’s Kick EMW 15.2 ppg Influx 20 bbls gas SIDPP 600 psi SCR 500 psi @ 30 spm Circulating Kill Techniques
Well Control During Workovers and Completions 118 Second Circulation - Choke and Standpipe Pressure Volume Pumped (bbls) SurfacePumped(psi) SCR SIDPP drillpipe Volume Annulus Volume 800600400200 200 400 600 800 1000 1200 1600 1400 1800 SCR2 Stand Pipe Pressure Choke Pressure WELL DATA: Well depth 11,480 ft BHA 6 ½”, 591 ft Shoe depth 6,560 ft Pipe 5” OD DP MW 14.2 ppg Method Driller’s Kick EMW 15.2 ppg Influx 20 bbls gas SIDPP 600 psi SCR 500 psi @ 30 spm Circulating Kill Techniques
Well Control During Workovers and Completions 119 Pump Operator 1. Begin slow and easy; it should take at least a full minute to bring the pump up to the planned kill rate. 2. Monitor the pump rate increase and drillpipe and casing pressures. Communicate these values to the Choke Operator. 3. Pump pressure should rise steadily and casing pressure should remain relatively constant. If any unusual pressure behavior is seen - stop pumping and communicate to the Choke Operator to close-in the well. Choke Operator's Responsibilities 1. Upon word from the Pump Operator that the pump has started, crack open the choke slightly and monitor the drillpipe and casing pressures. 2. As the pump comes up to kill rate, adjust choke as necessary to control casing pressure constant at the shut-in value until the pump is up to desired kill rate. 3. Be aware of unusual pressure behavior and communicate to the Pump Operator the drillpipe and casing pressures. Be prepared to instruct the Pump Operator to shut down the pump if unusual pressures are seen. 4. When the pump has reached the proper kill rate, continue to control casing pressure constant until the casing and drillpipe pressures have stabilized. 5. Record drillpipe pressure as the correct Initial Circulating Pressure (ICP). Compare it to the pre-calculated ICP value. Note: If actual ICP is greater than the calculated ICP, use the actual ICP and correct same on the Kill Sheet. If the actual ICP is less than the calculated ICP, stop the pumps, close in the well and determine if a problem exists in the circulating system. Then retry bringing the pump on line. Circulating Kill Techniques
Well Control During Workovers and Completions 120 WELL DATA: Well depth 11,480 ft BHA 6 ½”, 591 ft Shoe depth 6,560 ft Pipe 5” OD DP MW 14.2 ppg Method Driller’s Kick EMW 15.2 ppg Influx 20, 30, 40, 50 bbls gas 200 400 600 800 1000 1200 1600 1400 1800 Volume Pumped (bbls) ChokePressure(psi) 800600400200 20 BBLS 30 BBLS 40 BBLS 50 BBLS Driller’s Method for Various Influx Volumes Circulating Kill Techniques
Well Control During Workovers and Completions 121 Wait and Weight Method for Various Influx Volumes WELL DATA: Well depth 11,480 ft BHA 6 ½”, 591 ft Shoe depth 6,560 ft Pipe 5” OD DP MW 14.2 ppg Method Wait and Weight ChokePressure(psi) 20 BBLS 30 BBLS 40 BBLS 50 BBLS 200 400 600 800 1000 1200 1600 1400 1800 Volume Pumped (bbls) 800600400200 Circulating Kill Techniques
Well Control During Workovers and Completions 122 Precautions When ReversingAlthough reversing out is a common procedure in some operations, considerable forethought should be given to reversing out a kick, especially a gas kick. The choke pressure profiles seen on pages 18 and 19 reflect the required surface pressure supplied by the choke to make up for the lack of hydrostatic pressure in the annulus. And as seen in the illustrations, the trend is for back pressure to increase. This is expected given the expansion of the gas that has to be allowed. With gas expansion comes a decrease in overall annular hydrostatic pressure thus the required increase in back pressure. 20 BBLS 30 BBLS 40 BBLS 50 BBLS Volume Pumped (bbls) Required choke pressure is increasing due to gas expansion which causes a decrease in annular hydrostatic pressure Required Back Pressure Circulating Kill Techniques
Well Control During Workovers and Completions 123 Occasionally the decision is made to reverse out a kick - reasons being: To minimize contamination of expensive workover fluid Limit or minimize ultimate pressure on the casing due to a large influx Save time As long as the kick fluid is liquid, or primarily liquid, risks are minimal, but if the kick is predominantly gas, there are specific items to consider, namely the potentially rapid change in surface pressures and the equipment used when the reverse procedure is implemented. The well diagram on the following page will be used as an example to illustrate the differences between normal and reverse circulation where a gas kick is concerned. Reversing Out Kicks Circulating Kill Techniques
Well Control During Workovers and Completions 124 0 psi 407 psi WELL DATA 10000’ 2 7/8” TBG - 58 BBL Vol. 10000’ 5.5” ID Csg - 214 BBL Form Press EMW: 10 ppg = 5200 psi Kick Volume: 20 bbl Kick Length: 936’ Kick Hydrostatic Pressure: 94 psi Fluid Weight: 10.3 ppg SITP: 0 psi SICP: 407 psi Reversing Out Kicks Circulating Kill Techniques The information below will be used as baseline data for the example of comparing normal and reverse circulation of a gas kick in a workover environment. Stabilized Shut-in Conditions
Well Control During Workovers and Completions 125 58 bbl pumped - normal circulation 6001’ of fluid above gas 2714’ of fluid below gas 1285’ of gas 27.4 bbl 594 psi A volume pumped equal to the tubing volume (58 bbl) has been pumped. The influx has expanded based on the reduction in hydrostatic pressure above the gas. With this expansion comes a reduction in the annular hydrostatic pressure resulting in an increase in casing pressure. 20 bbl pumped - reverse 6001’ of fluid above gas 3454’ of gas 20 bbl 1756 psi The influx has been removed from the casing and now resides in the tubing. Static casing pressure is now 0 psi. The static tubing pressure reflects the vast change in tubing hydrostatic pressure due to the considerable vertical length occupied by the gas. Reversing Out Kicks
Well Control During Workovers and Completions 126 75 bbl pumped - normal circulation 5049’ of fluid above gas 3510’ of fluid below gas 1441’ of gas 30.8 bbl 679 psi A total volume of 75 bbl has been pumped. The influx has further expanded, and the decreased annular hydrostatic pressure has resulted in a casing pressure of 679 psi. Reversing Out Kicks 1270’ of fluid above gas 3454’ of fluid below gas 5276’ of gas 30.6 bbl 2732 psi 40 bbl pumped - reverse Considerable gas expansion has taken place in a relatively short period of time requiring extensive choke adjustments. Take note of the change in tubing pressure between this drawing and the previous one.
Well Control During Workovers and Completions 127 100 bbl pumped - normal circulation 3561’ of fluid above gas 4680’ of fluid below gas 1759’ of gas 37.6 bbl 848 psi A total volume of 100 bbl has been pumped. The expanded influx and decreased annular hydrostatic pressure has resulted in a casing pressure of 848 psi. 43.5 bbl pumped - reverse 153’ of fluid above gas 4050’ of fluid below gas 5796’ of gas 33.6 bbl 3010 psi Clearly seen in this diagram is the rapid expansion of the gas as it approaches the surface. And along with this expansion and reduction in annular hydrostatic pressure is a rapid increase in required back pressure in a relatively short period of time. Reversing Out Kicks
Well Control During Workovers and Completions 128 125 bbl pumped - normal circulation 5850’ of fluid below gas 2255’ of gas 48.2 bbl 1141 psi 75 bbl pumped - reverse 0 psi 1895’ of fluid above gas A total volume of 125 bbl has been pumped. The expanded influx and decreased annular hydrostatic pressure has resulted in a casing pressure of 1114 psi. Reversing Out Kicks Both the tubing and annulus are now full of fluid and the well is dead.
Well Control During Workovers and Completions 129 148 bbl pumped - normal circulation 6926’ of fluid below gas 3046’ of gas 65.1 bbl 1537 psi 28’ of fluid above gas Reversing Out Kicks A total volume of 148 bbl has been pumped. The influx has expanded from its initial volume of 20 bbl to now occupying 65.1 bbl of space in the annulus. The casing pressure of 1537 psi is the result of the decrease in annular hydrostatic pressure due to this expansion.
Well Control During Workovers and Completions 130 BBL Pumped PSI 300100 200 1000 2000 3000 4000 Tbg Displaced Annulus Displaced Tubing pressure response reverse circulation. Take note of the sharp changes that take place in a relatively short period of time. Casing pressure during response normal circulation Reversing Out Kicks Circulating Kill Techniques Comparison of Normal Circulation To Reverse Circulation
Well Control During Workovers and Completions 131 What is to be gained from the graph on the previous page? Take particular note of the relatively small amount of time it takes for surface pressure to increase significantly when reversing out. And, by comparison, the gradual increase in surface pressure while circulating in a normal fashion. Although somewhat simplified, the examples are representative of a constant bottom hole pressure method of killing a well while circulating - a well-known and widely accepted well killing concept. The danger lies not so much in the mathematical possibility of reversing out a kick as it does in its realistic implementation. The main requirements to successfully reversing out a gas kick: The proper equipment, installed properly, tested and in excellent working order Experienced and knowledgeable people with a good understanding of the U-tube Reversing Out Kicks Circulating Kill Techniques
Well Control During Workovers and Completions 132 Reversing Out Kicks There are ‘weak links’ in the chain, so-to-speak. The first occurs at the connection between the tubing and whatever kind of line will be used to connect the tubing to the choke manifold. Normally a full-opening safety valve is installed, and wisely so, but there should also be a back-up safety valve in case the full opening valve fails or the line between the tubing and choke manifold develops a leak. Either a low-torque valve or a pneumatic actuator are excellent choices. Consider this: Gas is flowing through the chicksan and into the choke manifold. A leak develops in the chicksan line. The normal reaction is to stop pumping and close the choke. But in this case, closing the choke would not stop the flow because the leak is upstream of the choke. The logical alternative would be to close the full-opening safety valve through which there is now a strong flow of gas. If the flow is strong enough, the valve will not be able to be fully closed - the well is now out of control and the chicksan, in all probability, will wash and fail in a short period of time.
Well Control During Workovers and Completions 133 Low-Torque Valve Full Opening Safety Valve Crossover Workstring Full Opening Safety Valve Crossover Workstring Pneumatic Actuator The illustrations are two means of “backing-up” the full opening safety valve. Should the chicksan lines develop a leak while circulating gas, either the low-torque valve or the pneumatic actuator could be closed, pressure bled from the lines via the choke and the leak repaired. When using the low- torque valve, an operating handle must be on hand. And when using the actuator, always have the fuseable cap in place. Reversing Out Kicks
Well Control During Workovers and Completions 134 Another ‘sore spot’ is the line connecting the tubing to the choke manifold. Normally this is chicksan. And very often this line is of a smaller ID than the tubing to which it will be connected. This means the velocity of whatever is flowing through it accelerates and presents more of an opportunity to wash or cut out. Reduced ID accelerates the velocity of the flow and increases the potential for pipe washing and cutting. Reversing Out Kicks
Well Control During Workovers and Completions 135 In every joint of chicksan there are two points where leaks can occur - the hammer unions located at either end of each joint. Another point of concern is in the elbow joints. A better system would be made up of flanged connections but, unfortunately, that is rarely available, so we’ll deal with what we are most likely to have to work with. The hammer unions need to be made up tightly and tested, paying special attention not only to the unions during the test but the elbow joints as well. Additionally, the chicksan must be securely anchored to minimize any movement that may occur while gas is being circulated through it. Reversing Out Kicks
Well Control During Workovers and Completions 136 Another point of concern are the chokes - both manual and remotely controlled. Remotely controlled, pneumatic or hydraulic, are not known for operating at very fast rates. And manual chokes, which can be somewhat difficult to operate with no pressure on them, can be extremely slow and arduous to operate while under pressure. Referring back to the graph of the reverse circulation, it should be clear, that a fast-acting choke is a must. If the choke can not be manipulated in a timely fashion, the results can be either over-pressuring the wellbore or allowing more influx into the well, prolonging the kill operation, and making an already uncomfortable situation all the more serious. As the gas surfaces and is being bled from the well, the tubing hydrostatic pressure begins to increase at a rapid rate. Because of this, the required back pressure must decrease relative to the increasing hydrostatic pressure. If the choke can not be opened fast enough, the bottom hole pressure will begin to increase - maybe to dangerous levels. Choke Concerns Reversing Out Kicks
Well Control During Workovers and Completions 137 100 200 1000 2000 3000 4000 Rapid choke adjustments required to provide the needed back pressure. If the choke opening can not be reduced fast enough BHP will decrease and another kick can enter the wellbore. Relatively rapid choke adjustments must take place to relieve back pressure due to the increase in tubing hydrostatic pressure. If the choke opening can not be increased fast enough BHP will increase which could result in loss of circulation or forcing fluids and unwanted solids into the producing formation. PSI BBL Pumped Choke Concerns Reversing Out Kicks
Well Control During Workovers and Completions 138 Liquid Kicks By comparison, if the kick is a liquid, oil or water, or a mix of the two, much of what has been described in the previous several pages will not take place. There will be no severe loss of hydrostatic - liquids don’t expand as gas does. And instead of constantly increasing tubing pressure, the tubing pressure would be on a steady decline. To be realistic about things though, it is rare to have a liquid hydrocarbon influx enter the well and not have some associated gas. So in “the real world” there would be some increase in surface pressure but not nearly so as compared to a “full blown” gas influx. Reversing Out Kicks
Well Control During Workovers and Completions 139 Potential Problems During the course of a well control operation problems could arise in some part, or parts of the circulating system that can have a direct impact on the circulating surface pressures or the effectiveness of the choke to alter pressures. Complications include:  Float or check valve in the workstring  Plugged workstring  Choke plugged  Workstring washout  Choke washout Excessive surface pressures while circulating Circulating Kill Techniques
Well Control During Workovers and Completions 140 Float or Check Valve in Workstring Circulating Kill Techniques Potential Problems Circulating Kill Techniques The presence of a check valve in the workstring prohibits the reading and monitoring of SITP. This can be alleviated with the following procedure: STEP 1 Record the stabilized SICP STEP 2 Start pumping on the tubing with a very slow rate – as slow as the pump will pump – do this while closely monitoring the SICP STEP 3 Record the pump pressure when the SICP first begins to increase. Record this pressure and immediately stop the pump. STEP 4 Subtract any observed casing pressure increase from th recorded pump pressure. The result is the SITP. Theoretically the check valve would open and there would be a slight decrease in pump pressure, the decrease indicating when the check valve opens. At this point the pump is stopped and the pressure recorded as the SITP. However, it’s virtually impossible to stop a pump that quickly and not add pressure to the casing after the check valve opens.
Well Control During Workovers and Completions 141 Plugging or Plugged Workstring Potential Problems Circulating Kill Techniques While circulating out a kick, anytime circulating pressures change suddenly, observe what’s happening on the other side of the well before taking action. If the Tubing pressure changes see what’s happening to casing pressure If the Casing pressure changes see what’s happening to tubing pressure If the workstring begins to plug there will be a noticeable increase in pump pressure without a corresponding increase in casing pressure. Additionally, there may be a noticeable decrease in flow from the well. Monitor the tubing pressure for stabilization If the tubing pressure continues to rise, stop the pump and close the choke Try, (once or twice) suddenly opening the choke for short durations to free the obstruction from the workstring – if this is unsuccessful, allow the casing pressure to stabilize, begin a volumetric procedure, and make preparations to perforate the workstring
Well Control During Workovers and Completions 142 Plugging or Plugged Choke Potential Problems Circulating Kill Techniques Evidence of a plugging or plugged choke will initially be an increase in casing pressure, decrease in flow, followed by an increase in tubing pressure. This is a serious problem because the circulating system is now closed and fluid being pumped will be pumped into the producing formation. Corrective actions must be taken rather quickly. STEP 1 Stop the pump and close the choke STEP 2 Try (once or twice) suddenly opening the choke to clear the debris STEP 3 If this proves to be unsuccessful, isolate the choke with valves on the choke manifold, line up to another choke and continue with the kill – bleed any excess pressure that ay have been exerted on the casing After the well is dead, the plugged choke must be cleared. Extreme caution should be exercised as pressure can be trapped in the choke and when relieved, can eject the debris at extreme velocities.
Well Control During Workovers and Completions 143 Washed-Out Workstring Potential Problems Circulating Kill Techniques A washout in the workstring comes on slowly and may be hard to detect. Decreases in pump pressure, and seemingly, frequent choke adjustments to maintain tubing pressure can be indicators of the problem. Possible remedies: Continue the kill operation and then attempt to locate the washout after the well is dead Shut down the kill operation and locate and pack-off the washout with wireline. If this option is selected, a volumetric procedure must be implemented until circulation can be restored. This procedure can take some time. After the well is dead, the decision can be made as to the need to locate the washout before tripping out.
Well Control During Workovers and Completions 144 Choke Washout Potential Problems Circulating Kill Techniques Like the washing out workstring, a choke that’s washing out can be, at first, hard to detect. There will be a gradual decrease in circulating pressure necessitating more frequent than normal choke adjustments. Also, if the well is brought of choke and the choke closed, it will not provide a positive seal. Solutions to the problem are easy. If it is suspected that the choke is washing, line up another choke and gradually open the second choke while closing the first choke. Isolate the defective choke with valves on the choke manifold. After the well is dead, repair and pressure test the faulty choke.
Well Control During Workovers and Completions 145 Potential Problems Circulating Kill Techniques Excessive Surface Pressure Excessive surface pressure can be a relative term. In terms of workovers, excessive surface pressure can be with respect to formation pressure or can be with regard to casing burst pressure. In either case, if excessive casing pressure exists, two options are available: Continue to circulate in hopes that the pressure will decrease Begin bleeding pressure to relieve the excess while risking the possibility of taking more influx There is no clear cut answer to the problem of excessive casing pressure. If it is decided to relieve pressure, the pump rate should be reduced. To accomplish this and maintain a constant BHP, hold the casing constant while reducing the pump rate. Allow the pump pressure to stabilize and record the stabilized pump pressure of the new rate. Begin reducing the annular pressure in small increments. Manipulate the choke to increase the pump pressure to the reduced pump rate pressure as soon as possible.
Well Control During Workovers and Completions 146 Wells with very low bottom hole pressures require a somewhat more delicate approach to killing, if it’s desired the well be worked over dead. To prevent possible formation damage and pumping excessive quantities of water into a formation, it may be necessary, and wise, to work the well over with only enough hydrostatic placed in the tubing to slightly overbalance the formation pressure. This is accomplished by placing a partial column of fluid on the formation. The volume to pump can be calculated using the following procedure: ( ) D e s i r e d P S I F l u i d W e i g h t F e e t o f F l u i d P P G.0 5 2 × = F e e t o f F l u i d T b g I D B B L×       = 2 1 0 2 9 Control With a Partial Column of Fluid Kicks During Workovers STEP 1 Length of Fluid Column STEP 2 Pumping Volume
Well Control During Workovers and Completions 147 The “delicacy” which must be employed comes into effect when the fluid is pumped into the well. Lubrication and bleeding (previously discussed) is the best approach. And in this instance, the volume method suffices. Stage the fluid into the hole while periodically bleeding gas and pressure from the tubing through a hand adjustable choke. The pressure to bleed is based on added hydrostatic. Using the data from the previous page the fluid can be staged into the well in six increments, in this case, a BBL at a time. The hydrostatic pressure added per BBL pumped can be determined using the following: 1 0 2 9 0 5 22 T b g I D F l u i d W e i g h t A d d e d H y d r o s t a t i cP P G       × × =. After the fluid is pumped into the well, time should be given for the fluid to fall; 15-20 minutes should be adequate. Following this, pressure from the tubing is bled equal to the hydrostatic pressure added. While this is “technically” correct, it’s somewhat difficult to bleed exactly 76 psi from a well, even with a good gauge, so practicality should come into play. In this case, bleed 70 psi from the tubing and then close the choke. Perform this operation as many times as needed to achieve the desired hydrostatic pressure in the well – in this example, 6 pumping “cycles” would be used. Control With a Partial Column of Fluid Kicks During Workovers After all the fluid is pumped into the well, pressure at the surface should be zero or near zero. Should any residual pressure remain, attempt to bleed this pressure. If it bleeds to zero, the well is dead and can be entered. If surface pressure increases, calculate the volume required to equal this pressure and perform another pumping cycle.
Well Control During Workovers and Completions 148 At left the diagrams illustrate the “before” and “after” of this procedure. It’s quite possible to have the surface reduced to zero or near zero before the entire volume of kill fluid is pumped. Should this be the case, continue to pump as per the cycles and make sure the complete volume is pumped. After the last cycle is completed (pumping and bleeding) monitor the surface pressure for about 20- 30 minutes to ensure the well is dead. If surface pressure appears, calculate the volume to equal this pressure using the formulas on the previous two pages. Control With a Partial Column of Fluid Kicks During Workovers Kill Fluid
Well Control During Workovers and Completions 149 Once the well is initially killed, consideration must be given to maintaining the hydrostatic pressure. If the next operation calls for the removal of a string of rods or tubing, the displacement of the “wet” part of the string must be calculated and an equal volume pumped into the well. Once the rods are completely removed, the well should be shut- in and routed to a blooie line where it can be closely monitored for flow. When the rods or tubing are re-run the displaced volume will most likely enter the formation due to the hydrostatic overbalance caused by the rod displacement. Monitor the well closely while running back to bottom and always be prepared to pump additional fluid. If a workstring is to be run in the well, the displacement must be calculated per the calculated kill fluid column length and this volume pumped into the well when the workstring is pulled from the hole. Calculate the displacement for this length Control With a Partial Column of Fluid Kicks During Workovers
Well Control During Workovers and Completions 150 Stripping is a technique for moving the string through the BOP stack when the well is shut-in under pressure. In most cases, stripping is required to return the workstring to bottom after shutting in on a kick with the pipe is off bottom. Stripping requires a high level of coordination among crew members. There are two annular stripping techniques; Short Term and Long Term. Points of Concern: • Moving the tool joint through the annular • Annular element wear • Redundancy in BOP control system • Excessive surface pressures • Accurately measuring fluids on the surface • Crew coordination • Gas migrating • Manufacturer’s info regarding BOP equipment Factors affecting well pressures when stripping: Compression - fluids are compressed as pipe is lowered. Under-bleeding - not bleeding correct volume equal to steel displacement removed. Influx penetration - pipe penetrating the influx causes the influx to elongate, resulting in additional hydrostatic pressure loss. Gas migration - must be controlled properly. Artificial migration - once pipe has penetrated the influx, additional pipe stripped will “pump” the influx up the hole. Restored overbalance - occurs when last few stands are stripped to bottom and the hole is filled. Kicks During WorkoversStripping
Well Control During Workovers and Completions 151 Procedure 1. Strip first stand without bleeding fluid to allow casing pressure to increase by a desired 100 – 200 psi “safety margin” 2. Continue to strip bleeding a fluid volume equivalent to closed end displacement of pipe stripped • Lower pipe slowly • Pipe burrs should be removed from tool joints and slip area on pipe • Pipe should be filled from the inside BOP to surface for each stand 3. Monitor casing pressure for gas migration - be prepared for volumetric or long term stripping if indicated 4. Once on bottom, implement a circulating technique to kill the well Applications:  When stripping approximately 20 stands or less  There is no gas migration Kicks During WorkoversShort Term Stripping
Well Control During Workovers and Completions 152 Since the type of influx is not usually know, it is prudent to plan a stripping procedure around a “worst case” scenario; a gas kick having the potential to migrate. Well fluids can be accurately accounted for by bleeding from the choke into a calibrated trip tank and then bleeding volume from the trip tank into a calibrated stripping tank used to account for the closed end displacement. Fluid accumulation in the trip tank is assumed to be from gas expansion as it migrates and can then be accounted for accurately. The life of the annular preventer can be extended significantly by use of a surge bottle. Kicks During WorkoversStripping
Well Control During Workovers and Completions 153 Opening Line Closing Line Surge Bottle Manual Choke Calibrated Trip Tank Recommended Equipment Layout for Short Term Stripping Collect and measure volumes for pipe displacement Partially charged accumulator bottle compensates for tool joint passage through the annular
Well Control During Workovers and Completions 154 Strip and Bleed Worksheet MASP 1366 psi 80 % MASP 1250 psi Closed end Displacement 2.3 bbls/std Safety Factor 200 psi Stand Number SICP (Before Stripping) SICP (After Stripping) Barrels Bled SICP (After Bleeding) 0 400 1 400 716 0.6 600 2 600 1000 2.3 625 3 625 975 2.3 650 4 650 975 2.3 625 5 625 975 2.3 625 6 625 950 2.3 625 7 625 975 2.3 625 8 625 975 2.3 625 9 625 960 2.3 625 10 625 950 2.3 600 11 600 920 2.3 600 12 600 920 2.3 590 13 590 890 2.3 600 14 600 900 2.3 680 15 680 1000 2.3 750 16 750 1100 2.3 800 17 800 1120 2.3 820 18 800 1120 2.3 820 19 820 1140 2.3 820 20 820 1140 2.3 850 21 22 Sample Data Sheet Short Term Stripping Pictured at right is a sample of a stripping data sheet that should be completed with any stripping operation. The benefit of using a document such as this is the ability to monitor fill and pressure trends making much easier to detect the onset of gas migration. Kicks During Workovers
Well Control During Workovers and Completions 155 Long Term Stripping Kicks During Workovers Long term stripping takes place when gas begins to migrate during a stripping operation. In this case, volumes must be accurately measured to account for pipe displacement as well as the required controlled gas expansion. The equipment requirements are a little different as an additional tank is needed to measure the volume bled for gas expansion. The general procedure combines both stripping and volumetric procedures: Strip in workstring without bleeding so that surface pressure increases by a pre-determined safety factor (100-200 psi) Continue stripping while bleeding off the calculated displacement – monitor gradually increasing surface pressure created by migration After surface pressure has increased by a selected working margin for volumetric procedure begin bleeding the calculated volume while holding surface pressure constant, all the while continue stripping and bleeding the volume for displacement Displacement volume is to be bled into the trip tank and volumes for migration are to be bled into the migration tank
Well Control During Workovers and Completions 156 Pw = V1 = V2 = Ps = Pchoke1 = Pchoke2 = Pchoke3 = 1. Select a working pressure range to control BHP, Pw. For Example: Pw = 100psi 2. Calculate the hydrostatic pressure per bbl of mud in the upper annulus. 3. Calculate the length of influx when penetrated by BHA, Lp. 4. Calculate the length of influx in open hole, Loh. 5. Calculate the pressure increase due to influx penetration, Ps 6. Calculate the strip and trip tank volumes V1 and V2 7. Calculate Pchoke values. Hydrostatic per bbl = Fluid Gradient (psi/ft) Upper Annular Capacity (bbl/ft) L1 (ft) = Influx Volume (bbls) OH by DC Capacity (bbl/ft) L2 (ft) = Volume of Influx (bbls) Open hole capacity (bbl/ft) Working Pressure range (Pw) Upper Annular Capacity (bbl/ft) V2 (bbls) =V1 (bbls) = Closed End Pipe Disp. Per Stnd. Ps (psi) = (L1 – L2) x (Fluid Gradient) Pchoke1 = Pa + Pw + Ps Pchoke2 = Pchoke1 + Pw (etc.) Pa =
Well Control During Workovers and Completions 157 Opening Line Closing Line Surge Bottle Manual Choke Calibrated Trip Tank Recommended Equipment Layout for Short-Term Stripping Partially charged accumulator bottle compensates for tool joint passage through annular Collect and measure volumes for pipe displacement Collect and measure volumes for volumetric procedure Calibrated migration tank
Well Control During Workovers and Completions 158 Kicks During WorkoversStripping Strip first stand closed in to allow casing to increase to Pchoke1. Choke operator to bleed as needed to hold casing pressure constant at Pchoke value. After each stand, drain V1 volume (closed end displacement per stand) from trip tank into stripping tank. Lower pipe slowly Remove burs from tool joints and slip area on pipe Pipe should be filled from the inside BOP to surface for each stand Continue as in Step 2 until a net gain of V2 (volume representing gas migrating) is noted in the trip tank. Then close the choke. Repeat Steps 1 through 3. Once the workstring is back on bottom, kill the well using a circulating method. A similar worksheet can be used to track the performance of the procedure

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well control (1)

  • 1.
    Well Control DuringWorkovers and Completions 1 Bullheading Bullheading is a common method for killing live wells prior to moving a rig on to conduct a workover. It is a non-circulating technique which uses a pump and kill fluid. The method entails forcing produced fluids back into the producing formation while filling the tubing with kill. Lubrication and Bleeding In some cases bullheading is not possible or desirable. Examples of this are: severely worn tubing having low burst pressure, low formation fracture strength, and damaged or deteriorated wellhead equipment with limited working pressure. In these cases, lubrication and bleeding might be a more acceptable means of killing a well. This technique can also be used to reduce surface pressure to a point where bullheading can be conducted. The basic procedure for lubricating and bleeding requires the pumping of a measured volume of kill fluid into the well, allowing it to fall, and then bleeding gas at the surface while controlling surface pressure to predetermined limits. Circulation Methods Reversing is a common circulation method used for killing live wells before a workover. Prior to the commencement of a workover, a circulating pathway must be established between the casing and tubing. A few methods are available: tubing perforation, opening a sliding sleeve, or pulling a gas lift valve or dummy, which are commonly performed by slickline. Once surface pressures stabilize, kill fluid can be circulated throughout the well. Normal circulation can also be used to conduct a kill operation. Killing A Well Prior To A Workover – Non-Circulating Techniques
  • 2.
    Well Control DuringWorkovers and Completions 2 Bullheading Bullheading is a means of killing a static producing well in which produced fluids are pumped back into the producing formation and the tubing filled with kill fluid. Bullheading should not be done in a haphazard way due to the possibility of damaging wellbore tubulars, damaging the producing formation, or fracturing adjacent formations. To accomplish a successful bullheading operation the following information is required to generate a Bullheading Schedule. The bullheading schedule is generated which provides the user with a means of killing the well with the control of surface pumping pressure. Non-Circulating Techniques
  • 3.
    Well Control DuringWorkovers and Completions 3 The following information is required to prepare a Bullheading schedule: Formation pressure – calculated, but preferably from a recent BHP survey Desired overbalance - provided by kill fluid – while pumping balanced weight fluid will kill a well, and overbalance is required if the tubing or packer is to be pulled, or if trips are to be made into and out of the well. Common overbalances range from .3 ppg to .5 ppg above the balanced fluid welight. Perf depth - measured and vertical Fracture pressure - estimate of the formation frac strength – the decline of the producing formation pressure must be taken into account when making this estimate – as a rule of thumb: render a conservative estimate Bullheading Non-Circulating Techniques
  • 4.
    Well Control DuringWorkovers and Completions 4 Bullheading Non-Circulating Techniques Tubing specifics - ID, length, EOT, burst, percent wear – seriously consider running a tubing caliper survey if the well has a history of producing sand or corrosive fluids such as H2S, CO2, or a high volume of salt water Annular fluid backup - the presence or absence of fluid in the annulus – this can have a major impact on the effective burst pressure of the tubing Rathole - ID and measured length – if a rathole exists it must be filled with kill fluid Pump size - liner, stroke, and efficiency data Surface pressures - tubing and annular Wellhead working pressure
  • 5.
    Well Control DuringWorkovers and Completions 5 STEP 1 Formation Pressure (ppg) STEP 2 Kill Fluid (ppg) STEP 3 Fracture Pressurepsi - requires knowledge or estimate of frac in ppg STEP 4 Pumping Volume STEP 5 Pump Outputbbl/stk - pump efficiency must be input in decimal form ( ) Formation Vertical PSI PPG DepthPerf Formation =      × 23.19 PPGPPGPPG FluidKillOverbalaceDesiredFormation =+ PSIVerticalPPG FracDepthPerfFrac =×× 052. BBLRathole Rathole Tbg Tbg VolumePumpingLength ID Length ID =        ×      +         ×         4.10294.1029 22 STKBBLPercentageInches OutputEfficiencyPumpLengthStrokeIDLiner / 2 000243. =××× Bullheading Non-Circulating Techniques
  • 6.
    Well Control DuringWorkovers and Completions 6 STEP 6 Pump Strokes - if the pump has a stroke counter STEP 7 Working Burst Pressure of the Tubing Assuming the industry standard of downgrading the tubing specifications to 80%. If the tubing is known to be worn more than 20%, insert the appropriate value rather than the given . STEP 8 Maximum Initial Tubing Pressure – Tubing Burst (assuming no backup) STEP 9 Maximum Final Tubing Pressure – Tubing Burst (assuming no backup) STEPS 8 & 9 are to be done if the assumption is made to disregard tubing backup supplied by the presence of fluid in the tubing/casing annulus - in older wells it may be prudent to make this assumption. StrokesPump OutputPump VolumePumping STKBBL BBL =      / PSIPSI BurstWorkingBurstPublished =× 8. ( ) PSIPSIPSI InitialMaxSITPFormationBurstWorking =+− PSIVerticalPPGPSI FinalMaxDepthPerfFluidKillBurstWorking =××− )052(. Bullheading Non-Circulating Techniques
  • 7.
    Well Control DuringWorkovers and Completions 7 TEP 10 Maximum Initial Tubing Pressure – Frac (assuming no backup) TEP 11 Maximum Final Tubing Pressure – Frac (assuming no backup) PSI Pump Strokes or BBL Pumped Tbg & Rathole Displaced SITP Line Frac Line (based on no backup Tbg Burst Line (based on no backup) Max Initial Pressures Max Final Pressures Safe PumpingRange The following is a graphical representation of calculated Initial and Final pressure along with Pumping Volume. ( ) PSIPSIPSI InitalMaxSITPFormationFrac =−− ( ) PSIVerticalPPGPPG FinalMaxDepthPerfFluidKillFrac =××− 052. Bullheading Non-Circulating Techniques
  • 8.
    Well Control DuringWorkovers and Completions 8 If tubing back up is to be considered the following calculations will take the place of the Maximum Initial and Maximum Final pressures for burst used previously. Maximum Initial Tubing Pressure (tbg burst consideration) - back up assumed Maximum Final Tubing Pressure (tbg burst consideration) - back up assumed The above calculations will result in higher values due to the inclusion of the annular hydrostatic pressure as a back up. In some cases, the maximum initial and maximum final pressure could be higher than the rated burst pressure. Naturally in these cases, the working burst pressure would be used as the maximum pressure. On the following page is a graph depicting the changes that would take place when annular hydrostatic pressure is considered in calculating maximum initial and final pressures for tubing burst. ( ) ( ) PSIVerticalPPGPSIPSI InitialMaxLengthFluidFluidAnnularFormationBurstWorking =××+− 052. ( )( ) ( ) PSIVerticalPPG VerticalPPGPSI FinalMaxLengthFluidAnnular LengthFluidKillBurstWorking =×× +××− 052. 052. Bullheading Non-Circulating Techniques
  • 9.
    Well Control DuringWorkovers and Completions 9 Tbg & Rathole Displaced Pump Strokes or BBL Pumped SITP Line Frac Line Tbg Burst Line (based on fluid backup) Max Final Pressures Safe PumpingRange Max Initial Pressures Working Burst Pressure From the graph it can be seen that the tubing burst pressures may be greater than calculated working tubing burst pressure and possibly greater than the working pressure of the tree. PSI Bullheading Non-Circulating Techniques
  • 10.
    Well Control DuringWorkovers and Completions 10 From previous diagrams and based on the “safe pumping range,” it is clear that as hydrostatic pressure in the tubing increases, due to the introduction of kill fluid, maximum surface pressures decrease. The drawing indicates the safe range to be bordered by the SITP and the Frac Line. This is the most desirable situation but is not always the case. If the tubing is severely corroded or pitted due to corrosive fluid production or sand production, the Tubing Burst Line could be the first ‘limit line’ above the SITP line. In either case, the safe pumping range is between the SITP Line and the first limit line above it. There are two ways the pressure can be monitored while the operation is in progress. A schedule could be generated based on an observed maximum initial pumping pressure, a selected maximum final pumping pressure, and the total volume or total strokes to pump. Naturally, the Maximum Initial Pressure would have to be within the safe pumping range. The mathematics to accomplish this is as such: STEP 2 Average Pressure Drop STEP 1 Pressure Drop M a x im u m I n itia l M a x im u m F in a l− p r e s s u r e d r o p in c r e m e n ts1 0 10 increments have been selected here only as an example - 15, or even 20 increments could be selected depending on how often one would want to check pump pressure during the operation STEP 3 Average Volume or Pump Stroke T o t a l P u m p S t r o k e s i n c r e m e n t s1 0 or T o ta l P u m p in g V o lu m e in c r e m e n ts1 0 Bullheading Non-Circulating Techniques
  • 11.
    Well Control DuringWorkovers and Completions 11 21 Based on the calculated average pressure drop and average pump strokes or volume pumped, a schedule can be generated and recorded. The procedure for the schedule is as: STEP 4 Pump Pressure i n i t i a l p u m p p r e s s u r e a v e r a g e p r e s s u r e d r o p− The first calculation renders a pump pressure corresponding to a ‘check point’ on the schedule. Additional similar calculations complete the schedule. STEP 5 Pump Strokes 0 s t r o k e s a v e r a g e s t r o k e s+ This calculation provides the first checkpoint once the operation has started. Additional similar calculations complete the schedule. As an example, let’s use the information below to illustrate the creation of a schedule: Initial Pump Pressure 2200 psi Final Pump Pressure 800 psi (arbitrarily selected) Total Strokes 4500 strokes Checkpoints 10 Bullheading Non-Circulating Techniques
  • 12.
    Well Control DuringWorkovers and Completions 12 Pressure Drop (Initial Circulating Pressure to Final Circulating Pressure) 2 2 0 0 8 0 0 1 4 0 0p s i p s i p s i− = Average Pressure Drop (Base on 10 Checkpoints) 1 4 0 0 1 0 1 4 0 p s i p s i c h e c k p o i n c r e m e n t s = / i n t Having performed these two calculations the pressure decline portion of the schedule can be completed. The Initial Pressure of 2200 would be the 1st entry. The average pressure drop of 140 psi is subtracted from the initial to obtain the 2nd checkpoint. Repeating this process completes the pressure side of the schedule. 2200 2060 1920 1780 1640 1500 1360 1220 1080 940 800 2200 - 140 = 2060 2060 - 140 = 1920 Additional iterations complete the schedule Bullheading Non-Circulating Techniques
  • 13.
    Well Control DuringWorkovers and Completions 13 A similar same thing can be done where the strokes or bbls to pump is concerned. In the case where 4500 strokes is required to displace the tubing and rathole, the incremental strokes increase of the schedule is generated as seen below. 0 450 900 1350 1800 2250 2700 3150 3600 4050 4500 Average Stroke Count 4 5 0 0 1 0 4 5 0 to ta l s tr o k e s in c r e m e n ts s tr o k e s= 0 strokes + 450 = 450 strokes 450 strokes + 450 strokes = 900 strokes ……and so on…... 2200 2060 1920 1780 1640 1500 1360 1220 1080 940 800 0 450 900 1350 1800 2250 2700 3150 3600 4050 4500 PSI STK S The completed schedule appears a right. The pump pressure is controlled by adjusting the pump throttle to achieve the desired decreasing pump pressures. Bullheading Non-Circulating Techniques
  • 14.
    Well Control DuringWorkovers and Completions 14 Below is an example graphical representation of a bullheading operation. The shaded area indicates a “safe pumping range” based on calculated pump pressures. The center line in the shaded area indicates a “midpoint” or desired pump pressure line to follow. The red lines indicate how pressures can be monitored at anytime during the operation. Checking the pressure at 750 strokes would yield a pressure of about 2200 psi. Checking the pressure at 2600 strokes would yield a pressure of about 1100 psi. Pump Strokes or BBL Pumped Pump Pressure Formation Taking Fluid Stabilized Initial Pump Pressure 500 1000 1500 2000 2500 3000 3500 3750 0 1000 2000 3000 4000 5000 5000 4000 3000 2000 1000 Desired Pump Pressure Bullheading Non-Circulating Techniques
  • 15.
    Well Control DuringWorkovers and Completions 15 While bullheading the casing pressure should be monitored closely. Any increase in the casing pressure should be reported to the job supervisor and closely monitored for change. Casing pressure increases can be from thermal expansion caused by pumping liquids down the tubing, or may indicate leaking tools or seals such as sliding sleeves, gas lift equipment, safety valves, packer seals, etc. The presence of, or an increase in casing pressure while bullheading can have dire consequences. Excess pressure applied to the cross-sectional area of the packer creates a great deal of force, so much so that the packer can be forced down the hole and the tubing parted. Additionally, the excess pressure in the annulus creates a situation where casing burst pressure can be approached - not necessarily at the surface but downhole. Casing Pressure Increase While Bullheading Bullheading Non-Circulating Techniques
  • 16.
    Well Control DuringWorkovers and Completions 16 Gas Channeling Gas channeling can occur during a bullheading operation, especially so if the kill fluid lacks appreciable viscosity and the pump rate is somewhat slow. In that case, gas may migrate up the tubing faster than it is being forced down the tubing through pumping. According to the previous graphs, once the tubing and rathole volume are pumped, the tubing pressure should be 0 psi and the well dead. Oftentimes this is not the case. Even though the SITP is 0 psi and the well ‘seems’ to be dead, wait for a while, 30 minutes or more, and monitor the SITP. If it starts to increase then gas channeling is usually the problem. It is particularly troublesome in highly deviated wells. A possible remedy to this situation is to pump a viscous pill ahead of the kill fluid to minimize the gas channeling. This could be followed, if so desired by a solids-laden pill, such as calcium carbonate, which can be acidized out when desired, and then that followed by the kill fluid. Of course, formation permeability and sensitivity must be considered before using a viscous or solids- Gas Channeling Kill Fluid Bullheading Non-Circulating Techniques
  • 17.
    Well Control DuringWorkovers and Completions 17 Gas lubrication is the process of pumping fluid into the tubing, allowing it to fall, and then bleeding gas; all the while maintaining a constant bottomhole pressure. The procedure is sometimes known as pump and bleed. Lubrication can be used to either entirely kill a well prior to a workover or to reduce the SITP prior to bullheading. Preceding a bullheading operation is usually done if the tubing is known or suspected to be in poor condition and may not withstand the pressures encountered during bullheading There are two approaches to this procedure, but regardless of the method used, the objective is to introduce hydrostatic pressure into the tubing by the means of a kill fluid. Lubrication and Bleeding Non-Circulating Techniques
  • 18.
    Well Control DuringWorkovers and Completions 18 STEP 1 Select an overbalance (Working Range) such as 50 to 100psi STEP 2 Calculate the hydrostatic increase base on the volume pumped, the wellbore geometry, and the density of the fluid being pumped. This is accomplished using the following: IncreasecHydrostati WtFluid ID RangeWorking BBL PPG Tbg Pumped =                         ××         × .052. 4.1029 2 STEP 3 Pump kill fluid into the well until the observed pump pressure is equal to the Working Range. Stop the pump and take note of the volume pumped. Use this volume in performing the above calculation. STEP 4 Allow time (at least 30 to 45 minutes – be patient) for the fluid to fall or “lubricate” through the produced fluids in the tubing. STEP 5 Bleed dry gas through the production choke while monitoring the SITP. The “target” SITP is determined as follows: Bleed SITP back to original SITP as this is compression. Subtract from the SITP the hydrostatic added by kill fluid. Lubrication and Bleeding - Volume Method Non-Circulating Techniques
  • 19.
    Well Control DuringWorkovers and Completions 19 BBL Pumped PSI Trend of declining SITP Working Range Pressure decline after pump is shut down Pressure stabilization Bleeding gas (bleed back to original SITP and additional hydrostatic added) Resulting SITP Below is an idealized plot of the Volume Method as described on the previous page. Lubrication and Bleeding - Volume Method Non-Circulating Techniques
  • 20.
    Well Control DuringWorkovers and Completions 20 The Volume Method of lubrication is not without its shortcomings: While pumping into the well as per the selected Working Range, produced fluids can be forced back into the perfs equal to the hydrostatic pressure added by kill fluid. When gas is bled at the surface the SITP will decline but could re-build and stabilize near the original SITP. This would make the operation appear to be accomplishing nothing. Patience is needed in this case. Eventually enough kill fluid hydrostatic will be added to the tubing to start to make a difference and the SITP will begin to shows signs of decline. This occurrence is especially like when the producing formation is quite permeable. Due to this, the Volume Method is more applicable to drilling operations where mud solids build open hole wall cake against permeable formations and limit fluid invasion Lubrication and Bleeding - Volume Method Non-Circulating Techniques
  • 21.
    Well Control DuringWorkovers and Completions 21 A better method of lubrication to use during workovers is the Pressure Method. The volume of fluid pumped does not have to be monitored as it does in the Volume Method. The Pressure Method uses three pressures: Pressure 1 P1: initial SITP Pressure 2 P2: stabilized SITP after pumping Pressure 3 P3: desired SITP after bleeding gas from the well To determine P2 and P3 perform the following: 3 2 2 1 P P P = Lubrication and Bleeding - Pressure Method Non-Circulating Techniques
  • 22.
    Well Control DuringWorkovers and Completions 22 Pressure Method Procedure: STEP 1 Pump kill fluid into well to increase SITP to desired pressure considering a working range. STEP 2 Allow the tubing pressure to stabilize. Use the stabilized tubing pressure as the value for P2. STEP 3 Calculate P3 and bleed tubing to the calculated value. Repeat steps 1 through 3 until all the gas is out of the well or until another procedure implemented based on having achieved a desired SITP. Lubrication and Bleeding - Pressure Method Non-Circulating Techniques
  • 23.
    Well Control DuringWorkovers and Completions 23 Lubrication and Bleeding - Pressure Method Non-Circulating Techniques BBL Pumped PSI Trend of declining SITP Working Range Pressure decline after pump is shut down Pressure stabilization Bleeding gas (bleed to target pressure) Resulting SITP Plot of Pressure Method
  • 24.
    Well Control DuringWorkovers and Completions 24 Lubrication and Bleeding The Casing Non-Circulating Techniques Without Packer Lubrication and bleeding can be performed on the casing but consideration must be made with respect to the presence or absence of a packer. If the well has been completed without a packer then either the Volume Method or Pressure Method can be used. Selecting the working range would have the same criteria used when performing Lube and Bleeding on the tubing.
  • 25.
    Well Control DuringWorkovers and Completions 25 Kill fluid pumped in and produced fluids bled Kill fluid would be pumped into and produced fluids would be bled from the production casing wing. Regardless of the method selected, a worksheet should be completed to track the progress of the operation. Lubrication and Bleeding The Casing Non-Circulating Techniques Without Packer
  • 26.
    Well Control DuringWorkovers and Completions 26 Lubrication and Bleeding The Casing Non-Circulating Techniques With Packer Conducting a Lube and Bleed operation on the casing side of a well with a packer in the hole is another matter entirely. The main “danger” is the possibility of parting the tubing or pumping the packer down hole – neither of which are very desirable. Information should be gathered about the following in order to determine the feasibility of attempting a Lube and Bleed on a well with a packer in place: When the packer was initially set was it set in tension or compression? The OD of the tubing. Tubing tensile strength. Collapse pressure of the tubing. The OD of the packer. The burst pressure of the casing. The density of the pack fluid left in place when the well was completed or last worked over.
  • 27.
    Well Control DuringWorkovers and Completions 27 Lubrication and Bleeding The Casing Non-Circulating Techniques With Packer Forces A few things come into play that create forces on the cross- sectional area of the packer: Hydrostatic pressure of the packer fluid SICP Applied surface pressure from the Lube and Bleed operation FORCE (lbs) is pressure exposed to a cross-sectional area 2 inchesPSI APForce ×= The “area of interest”, in this case is the exposed area of the packer, or as illustrated at right and for all practical purposes, the area between the OD of the tubing and the ID of the casing.
  • 28.
    Well Control DuringWorkovers and Completions 28 Lubrication and Bleeding The Casing Non-Circulating Techniques With Packer The force created across the exposed area of the packer is calculated as such: ( ) LBSPSIODID ForcePTbgCsg =××− 7854.22 This calculation would have to be done for everything that exerts pressure on the packer: SICP Applied surface pressure of the Lube and Bleed operation Packer fluid hydrostatic pressure. Once total force is calculated (a sum of all the forces) it is compared to estimated tubing tensile strength. From that comparison a decision is made as to the feasibility of performing a Lube and Bleed operation on the annulus housing a seated packer.
  • 29.
    Well Control DuringWorkovers and Completions 29 Lubrication and Bleeding The Casing Non-Circulating Techniques With Packer Tubing Tensile Strength The tensile strength of a steel tubular is determined by the grade of steel and the square inches of steel of which the tubular is comprised. Tubing grades are annotated as such: N-80, C-75 P-110 The numerical values indicating the minimum yield strength of the steel in thousands of pounds per square inch of steel. N-80 pipe = steel with a minimum yield of 80,000 psi C-75 pipe = steel with a minimum yield of 75,000 psi P-110 pipe = steel with a minimum yield of 110,000 psi The tensile strength can be determined by multiplying the area of steel in square inches by the minimum yield of the steel.
  • 30.
    Well Control DuringWorkovers and Completions 30 Lubrication and Bleeding The Casing Non-Circulating Techniques With Packer Tubing Tensile Strength Tubing tensile strength is calculated using the following: ( ) PSIODOD YieldMinimumTbgTbg ××− 7854.22 The above formula will render tensile strength of new pipe. It is strongly advised that some safety factor be applied to the calculated tensile strength. A common practice is to downgrade the calculated tensile strength to 80% or even 70% if the tubing is known to be worn to some degree. Another means of gaining useful knowledge of the tubing tensile strength is to consult any one of a number of tubing tables that are commercially available. In most cases, the specifics are for new pipe and the user must make adjustments as to his/her knowledge of the pipe condition.
  • 31.
    Well Control DuringWorkovers and Completions 31 Lubrication and Bleeding The Casing Non-Circulating Techniques With Packer Kill fluid pumped in and produced fluids bled Kill fluid would be pumped into and produced fluids would be bled from the production casing wing. Regardless of the method selected, a worksheet should be completed to track the progress of the operation.
  • 32.
    Well Control DuringWorkovers and Completions 32 In some cases a circulating kill technique is preferred over a non-circulating one necessitating communication between the tubing and the casing. If this is the case, a means of communication between the two strings must be established. This is commonly done by one of the three following methods which can be accomplished via wireline or coiled tubing-conveyed wireline tools : Shifting a sliding sleeve Pulling a gas lift dummy from a side-pocket mandrel Perforating the tubing Anytime communication is established between the tubing and casing there exists the possibility of a differential pressure at the point where communication is established. This can be a problem. If there is a negative differential (more pressure in the casing than the tubing at the point of communication), a wireline tool string could get blown up the hole creating the very real possibility of a fishing job before the well is killed. Sliding sleeves incorporate equalizing features to minimize this. The same is true for some gas lift valves/dummies, but not in all cases. Therefore, it’s imperative that the gas lift equipment be identified as to the presence or absence of this feature. Regardless, it highly recommended that calculations be made as to the possible differential existing at the desired point of communication and steps taken to minimize the differential Gaining Tubing-to-Casing Communication
  • 33.
    Well Control DuringWorkovers and Completions 33 Calculating Differential Pressure Surface Pressures 1150 psi SITP 0 psi SICP Wellbore Fluids Tubing: 0’-2188’ gas – average density of .115 psi/ft 2188’-11235’ – oil – measured API gravity of 31.5o @ 120o F Casing: 0’ – 11235’ – filled with 11.4 calcium chloride The task at hand is to open the sliding sleeve @ 11235’ in order to circulate kill fluid around and kill the well before the workover starts. Even though sliding sleeves have an equalizing feature, it’s a good idea to determine if there is a differential across the sleeve and then decide how to negate the effects of the differential. The differential, if present, is based on the total pressure in the casing at the depth of interest compared to the total pressure in the tubing at the depth of interest. The total pressure is a combination of any surface pressure plus hydrostatic pressure. This is to be applied to both sides of the well. The information below will be used in the example: Gaining Tubing-to-Casing Communication
  • 34.
    Well Control DuringWorkovers and Completions 34 Oil Hydrostatic Pressure STEP 1 Calculate API Gravity Corrected For Temperature ( ) CorrectedAPI TempObserved TempObserved =      − − 10 60 STEP 2 Oil Hydrostatic Pressure ( ) PSIColumnOilftpsi Corrected HPLength API =×      + /433. 5.131 5.141 Gas Hydrostatic Pressure PSIColumnGasFTPSI cHydrostatiGasLengthVerticalGradientGasAverage =×/ Brine Hydrostatic Pressure cHydrostatiBrineLengthWtFluid ColumnFluidPPG =×× .052. NOTE: Calculating oil hydrostatic pressure is a two step process. Oil density is measured in API degrees. The API hydrometer is calibrated to be accurate at 60 degrees F. Therefore it is necessary to correct the observed density to the observed temperature. Calculating Differential Pressure Gaining Tubing-to-Casing Communication
  • 35.
    Well Control DuringWorkovers and Completions 35 Total Casing Pressure @ Depth of Interest Brine Hydrostatic Pressure psiPPG 6660112354.11052. =×× Since there is no surface casing pressure the calculated brine hydrostatic pressure is the total pressure in the casing at the depth of interest. Total Tubing Pressure @ Depth of Interest Gas Hydrostatic Pressure STEP 1 Corrected API Gravity PSIFtPSI 2526.251'2188115. / ≈=× Oil Hydrostatic Pressure ( ) API5.25 10 60120 5.31 =      − − STEP 2 Oil Hydrostatic Pressure ( ) ( ) PSIFTPSI 35316.3530218811235433. 5.255.131 5.141 / ≈=−××      + Calculating Differential Pressure Gaining Tubing-to-Casing Communication
  • 36.
    Well Control DuringWorkovers and Completions 36 Total Tubing Pressure PSI cHydroststiOil PSI cHydroststiGas PSI SITP PSI 493335312521150 =++ Differential Pressure PSI TbgTotal PSI CsgTotal PSI 172749336660 =− Obviously the differential is from Casing to Tubing. To negate the existing differential 1727 psi must be added to the tubing string since it would be virtually impossible to decrease the hydrostatic pressure in the casing. There are two options available: Pump into the tubing to increase the surface pressure by the differential pressure – provided this can be done without damaging the producing formation Set a plug in the tubing below the sliding sleeve and then pressure up on the tubing by the calculated differential Calculating Differential Pressure Gaining Tubing-to-Casing Communication
  • 37.
    Well Control DuringWorkovers and Completions 37 Gaining Tubing-to-Casing Communication Shifting a Sliding Sleeve OpenClosed Sliding Sleeve Port A shifting/positioning tool is conveyed by wireline or coiled tubing and the sleeve is shifted to the open position. Shifting Tool
  • 38.
    Well Control DuringWorkovers and Completions 38 Gas Lift Equipment Gaining Tubing-to-Casing Communication Gas lift equipment is installed in an oil well in anticipation of formation pressure declining before all recoverable reserves are produced. In the case of the side pocket equipment, numerous side pocket mandrels are run in the tubing string. As the illustration shows, the mandrel contains a profile for the gas lift dummies or valves. If the mandrels are run in the initial completion, dummies are installed which can be removed at a later date and replaced with valves . With the valves in place, gas is injected in the casing and enters the mandrel via the gas ports. The ports align with a port on the gas lift valve which then conveys the gas into the oil in the tubing string. The gas entering the oil lightens the column hydrostatically, thus allowing the remaining formation pressure to produce the oil. A kickover tool, orients the pulling or running tool to the side pocket for valve or dummy installation or extraction. Once the valve or dummy is out of the pocket, the pocket can then be used as a means of casing-to-tubing communication. Courtesy of Halliburton
  • 39.
    Well Control DuringWorkovers and Completions 39 Three commonly used and very reliable kickover tools are from left to right: the Camco AK Kickover Tool, the Camco L Kickover Tool, and the Camco L-2D Kickover Tool. The appropriate pulling or running tool for the gas lift valve would be installed below the kickover tool. Camco Kickover Tools Gas Lift Equipment Gaining Tubing-to-Casing Communication
  • 40.
    Well Control DuringWorkovers and Completions 40 Gas Lift – Pulling A Dummy Or Valve STEP 1 The tool string is run below the desired gas lift mandrel. STEP 2 The tool string is raised above the mandrel. As this happens the tool string rotates and begins to orient to the side pocket. STEP3 The kickover tool kicks the pulling tool into the side pocket to engage the gas lift valve.
  • 41.
    Well Control DuringWorkovers and Completions 41 Gas Lift STEP4 The pulling tool engages and latches the fishing neck of the gas lift valve STEP5 Upward manipulation of the tool string pulls the lift valve from the side pocket.
  • 42.
    Well Control DuringWorkovers and Completions 42 Tubing Perforation Tubing perforated just above the packer Gaining Tubing-to-Casing Communication A perforator, be it mechanical or shot charge, is lowered to the desired depth which is usually as close to the packer as possible. The perforator is activated and communication with the annulus is established. Although an explosive E-line conveyed explosive charge is more efficient, it may be more desirable to use a mechanical perforator to prevent any possible damage or unwanted perforation of the production casing.
  • 43.
    Well Control DuringWorkovers and Completions 43Otis Type A Mechanical Perforator Slip Stop Collar Stop Tubing Perforation Gaining Tubing-to-Casing Communication The mechanical perforator does not offer the accurate depth control of an E-line perforator but can still get the job done. Either the slip stop or collar stop can be used as a perforating platform for the mechanical perforator.
  • 44.
    Well Control DuringWorkovers and Completions 44 Tubing Perforation Gaining Tubing-to-Casing Communication To perforate the tubing using a mechanical perforator, a tubing stop must first be set at a desired depth. Next the perforator is run and activated. After communication is established between the tubing and the casing, the perforator is pulled from the hole followed by the tubing stop. Wireline Tool String Perforator Tubing Stop
  • 45.
    Well Control DuringWorkovers and Completions 45 Surface Pressure Stabilization After successful communication between the tubing and casing has been established, time should be given for surface pressure to stabilize, even though exhaustive calculations have been performed in the effort to predict the surface pressures based on “known” or anticipated fluids in place versus formation pressure. In some cases, it’s a “best guess” of the actual stabilized surface pressures. Factors affecting this can be, but are not limited to, unknown fluid density in both the tubing and casing, especially so in a workover. Over time, the brine in the packer fluid can crystallize and find its way to the packer. This can make it initially impossible to gain string-to-string communication, even though a “communication window” has been opened via sliding sleeve, gas lift equipment, or perforation. The brine can settle and pack making it impossible for fluid to flow through it. This also makes the density of the liquid in the annulus an unknown.
  • 46.
    Well Control DuringWorkovers and Completions 46 Another problem that can exist is that the exact density of the fluids in the tubing may not be unknown. Additionally, there may exist a differential between the casing and the tubing. If this is the case, the possibility of u-tubing of these fluids exists and would occur until a pressure equilibrium is established. Therefore, prior to any kill method being attempted, be it circulating or non- circulating, surface pressures must be allowed to stabilize. Following the stabilization of surface pressure, a circulating kill procedure can be implemented which will be discussed later in the chapter. Surface Pressure Stabilization
  • 47.
    Well Control DuringWorkovers and Completions 47 Friction Pressure Friction pressure is the pressure created by circulating a fluid through a circulating system at a given rate. Factors affecting the magnitude of friction pressure include: Fluid properties Circulating system geometry Pump rate Knowledge of friction pressure has two uses: Provides information regarding circulating pump pressure when killing a well Provides information about annular friction while circulating which adds to wellbore stress After the well is initially dead and circulated entirely with kill fluid, it is advised that a few slow pump rates be taken. Rate 1 Normal average operating speed of the pump Rate 2 Half the normal average operating speed of the pump Rate 3 As slow as the pump can pump for an extended duration Record corresponding pressure with each rate.
  • 48.
    Well Control DuringWorkovers and Completions 48 Friction Pressure Annular friction, which is created in the casing when fluid is pumped, adds to bottom hole pressure. In drilling environments, annular friction makes up a small portion of the total friction pressure created, but in workovers, this is not the case due to the reduced diameters involved, especially the production casing. Even when using solids-free fluid, appreciable friction pressure can be created in the somewhat “tight” confines of a producing well annulus. To that end, it is prudent to calculate an estimate of the annular friction pressure created by each slow pump rate for both normal and reverse circulation, since reverse circulation is used so frequently in workovers. The following set of formulas can be used to generate reasonable estimates of workstring and annular friction pressure as well as the equivalent stress created at the bottom of the hole.
  • 49.
    Well Control DuringWorkovers and Completions 49 Friction Pressure WORKSTRING FRICTION PRESSURE STEP 1 Workstring Fluid Velocity ft/sec ( ) ( ) SecFT Tbg BBLGalBPM Velocity ID Flowrate /2 / 45.2 42 = × × STEP 2 Reynolds Number ( ) R CP TbgSecFtPPG N ityVisFluid IDVelocityFluidWtFluid = ××× cos .928 / If the Reynolds Number ≥ 2100 the flow is Turbulent – Go to STEP 3 If the Reynolds Number ≤ 2100 the flow is Laminar – Go to STEP 4 STEP 3 Turbulent Friction Pressure ( ) ( ) PSI Tbg MDFluid Friction ID DepthityVisVelocityWtFluid = × ××× 2 25.75.175. 1000 cos
  • 50.
    Well Control DuringWorkovers and Completions 50 Friction Pressure STEP 4 Laminar Friction Pressure ( ) ( ) PSI Tbg MDFluidCP Friction ID DepthVelocityityVis = × ×× 2 1500 cos ANNULAR FRICTION PRESSURE STEP 1 Annular Fluid Velocity ft/sec ( ) ( )( ) SecFt TbgCsg BBLGalBPM Velocity ODID Flowrate /22 / 45.2 42 = −× × STEP 2 Reynolds Number ( )( ) R CP TbgCsgFluidPPG N ityVis ODIDVelocityWtFluid = −××× cos .928 If the Reynolds Number ≥ 2100 the flow is Turbulent – Go to STEP 3 If the Reynolds Number ≤ 2100 the flow is Laminar – Go to STEP 4
  • 51.
    Well Control DuringWorkovers and Completions 51 STEP 3 Turbulent Friction Pressure Friction Pressure ( ) ( )( ) PSI TbgCsg MDCPFluidPPG Friction ODID DepthityVisVelocityWtFluid = −× ××× 22 75.175. 1369 cos STEP 4 Laminar Friction Pressure ( ) ( )( ) PSI TbgCsg MDSecFtCP Friction ODID DepthVelocityityVis = −× ×× 22 / 1000 cos Equivalent Circulating Density (ECD) Normal Circulation ( ) PPG Vertical PSI WtFluid Depth FricAnnular . 23.19 +      × Equivalent Circulating Density (ECD) Reverse Circulation ( ) PPG Vertical PSI WtFluid Depth FricWorkstring . 23.19 +      ×
  • 52.
    Well Control DuringWorkovers and Completions 52 During the course of a workover, a kick can occur for a variety of reasons. A kick can be defined as any unwanted intrusion of formation fluids into the wellbore, and if not detected early on, and handled properly, most assuredly can result in a surface blowout. The main causes of kicks during workovers are: • Failure to keep the hole full during trips • Swabbing • Insufficient fluid weight • Loss of circulation Failure to Keep Hole Full During Trips As a workstring is pulled from the hole, the fluid level in the well drops due to the displacement of the workstring. As the fluid level drops hydrostatic pressure decreases, and if the hydrostatic pressure of the workover fluid decreases below formation pressure, formation fluids will flow into the well. Kicks During WorkoversTripping
  • 53.
    Well Control DuringWorkovers and Completions 53 Prior to Tripping Circulate the hole clean prior to the trip. Calculate the volume required for a slug if one is to be pumped. Calculate workstring displacement and faithfully record hole fill/displacement data on trip sheets. Limit pipe speed to minimize surge/swab pressures – especially when running or pulling tools with large OD’s such as packers, mills, etc.. Line up and use a trip tank. Discuss with driller/operator the purpose of trip. Prepare the rig floor. Kicks During WorkoversTripping Statistics indicate that the most serious well control incidents during completions and workovers occur while the workstring is being tripped!!
  • 54.
    Well Control DuringWorkovers and Completions 54 As a rule of thumb, the slug should be mixed to maintain a minimum of 2 to 3 stands of dry pipe. Tripping Kicks During Workovers If a slug is to be pumped consult with the driller or unit operator as to his knowledge of how well or how poorly the workstring drains. This information can be used in determining how far down the fluid level should be after the slug has been pumped and the wellbore is once again stable. The procedure on the following page will provide information as to the volume of slug to pump based on the desired dry pipe and the desired slug weight. Additional information provided is the anticipated displacement created by the slug. Tripping should NEVER begin until the well is stabilized after pumping a slug – otherwise the driller or unit operator has no way of accurately monitoring the displacement of the workstring. Slugging
  • 55.
    Well Control DuringWorkovers and Completions 55 STEP 1 SLUG LENGTH (ft) STEP 2 SLUG VOLUME BBL STEP 3 SLUG DISPLACEMENT BBL ( ) ( ) FT PPGPPG PPGFt LengthSlug WtFluidWtFluidSlug WtFluidPipeDryDesired =      − × .. . BBL Workstring Ft VolumeSlug ID LengthSlug =         × 4.1029 2 BBL Workstring FT ntDisplacemeSlug ID PipeDryDesired =         × 4.1029 2 Sluggin g
  • 56.
    Well Control DuringWorkovers and Completions 56 Workstring Displacement – Pulling Dry STEP 1 Workstring Displacement (Per 5 Stands) DisplacedFTFt BBLWtPipe =×× 450.0003638. /# The formula above will provide a reasonably accurate displacement volume for both upset and non upset pipe, including hevi-weight drill pipe and drill collars. If the workstring is tapered and contains pipe of varying weight, the calculation above should be performed for each weight category. The workstring displacement is generally monitored as such: Workstring or Drill Pipe: 5-stand groups Hevi-Weight Drill Pipe: 3-stand groups Drill Collars: 1-stand groups Total workstring displacement should also be calculated and compared to the observed displacement on every trip. Anytime the observed hole fill (when tripping out) or hole flow (when tripping in) becomes noticeably different from calculated values the trip should be stopped, the well monitored for flow or loss of fluid, and a reasonable determination made as to why the well is behaving the way it is. NEVER should a trip proceed with well experiencing excessive flow or fluid loss.
  • 57.
    Well Control DuringWorkovers and Completions 57 Workstring Displacement Per Stand Workstring Displacement – Pulling Wet If the workstring becomes plugged and will not drain, then it must be pulled wet. The following will provide an accurate value for wet displacement. Usually when pulling wet, the workstring displacement is monitored on a “per stand” basis regardless of the weight of the pipe or whether the string is tapered or not. ( ) Ft WorkstringPipe ft Length ID Wt ×                 +× 4.1029 0003638. 2 /#
  • 58.
    Well Control DuringWorkovers and Completions 58 Trip sheets should be used to record hole fill volumes for all trips. The trip sheet allows for comparison of actual vs. calculated fluid volumes so that any discrepancies can be easily detected. A trip tank should also be used during all trips to assist with accurate hole fill requirements. A trip sheet need not be a complicated document. Below is an example of a simple trip sheet that provides the required information to monitor hole fill. Stand Group Calculated Displacement Observed Displacement Discrepancy Cumulative Displacement Cumulative Discrepancy Remarks Tripping Kicks During Workovers
  • 59.
    Well Control DuringWorkovers and Completions 59 Trip tanks are the most reliable means of monitoring pipe displacement while tripping, however many smaller workover rigs are not equipped with trip tanks. An alternative to this will be discussed later. If a trip tank is present on the rig it should be calibrated based on its volume and dimensions so that volume changes can be readily detected and accurately monitored. Seen below is an example of a trip tank. The tank volume should be at least equal to the total displacement of the workstring. Use of a Trip Tank Tripping Kicks During Workovers
  • 60.
    Well Control DuringWorkovers and Completions 60 If a trip tank is not calibrated there are easy ways of measuring the change in trip tank level. Measurements of the tank need to be taken for HEIGHT, WIDTH, and DEPTH (all in feet). With these measurements the tank volume can be determined as well as inches per bbl and bbl per inch. H e i g h t W i d th D e p thF e e t F e e t F e e t× × × .1 7 8 1 T a n k V o l u m e T a n k H e i g h t B B L I n c h e s T a n k H e i g h t T a n k V o l u m e I n c h e s B B L Tripping Kicks During Workovers Tank Volume in BBL BBL Per Inch Inches Per BBL Determining Trip Tank Volume
  • 61.
    Well Control DuringWorkovers and Completions 61 Occasionally a vertical cylindrical tank (frac tank) is used as a trip tank. Calculating the volume in this situation is different from the vertical rectangular tank, but not difficult. The two dimensions required are the DIAMETER in inches and the HEIGHT in feet. Tank Volume in BBL Tripping Kicks During Workovers Ft inches Height IDTank ×      4.1029 2 T a n k V o l u m e T a n k H e i g h t B B L I n c h e s T a n k H e i g h t T a n k V o l u m e I n c h e s B B L BBL Per Inch Inches Per BBL Determining Trip Tank Volume
  • 62.
    Well Control DuringWorkovers and Completions 62 Tripping Kicks During Workovers What If You Don’t Have A trip Tank If a trip tank is unavailable on can easily be fashioned from just about anything that will retain liquid: a 55 gallon drum, a large plastic trash can, etc. The volume and calibration of these containers can be calculated as explained on the preceding pages and a trip can be conducted successfully and safely. And remember, if need be, 8.4 or roughly 8 ½ 5 gallon buckets is a BBL. There’s really no reason why workstring displacement can not accurately be monitored during the course of a workover, no matter how ill-equipped the rig.
  • 63.
    Well Control DuringWorkovers and Completions 63 Tripping Kicks During Workovers Swabbing Swab Pressure is a negative pressure created anytime the workstring is moved in an upward direction. The magnitude of the swab pressure created is based on: Speed of the upward pipe movement Clearance between the workstring and casing Workover fluid properties Excessive swab pressure can cause a dead well to kick, and if not handled properly can lead to a surface blowout.
  • 64.
    Well Control DuringWorkovers and Completions 64 STEP 1 FORCE AROUND THE WORKSTRING STEP 3 FORCE AROUND THE DRILL COLLARS W o r k s t r i n g O D S u r f a c e P S I2 7 8 5 4× ×. D r i l l C o l l a r O D S u r f a c e P S I2 7 8 5 4× ×. STEP 2 MINIMUM ALLOWABLE WORKSTRING LENGTH F o r c e o n W o r k s t r i n g A d j u s t e d W o r k s t r i n g W e i g h t F e e t F T# / = STEP 4 MINIMUM ALLOWABLE COLLAR LENGTH F o r c e o n D r i l l C o l l a r s D r i l l C o l l a r W e i g h t F e e t F T# / = If collars are being used If collars are being used Tripping With The Well Flowing Tripping Kicks During Workovers
  • 65.
    Well Control DuringWorkovers and Completions 65 Estimating the weight of the workstring at any given time during the trip is a simple matter of adding the weight of the BHA to the weight of the remaining drill pipe in the hole. The following formula can be used to determine the weight of each section of the drill string, i.e., tubing and/or BHA. W e i g h t L e n g t h I n H o l e T o t a l W e i g h tF T L B S# / × = As stated above, this formula can be applied to both sections of the workstring to arrive at the weight of each individual section. By adding the total weights of the two sections one arrives at the weight of the string. T o t a l W o r k s t r i n g W e i g h t T o t a l C o l l a r W e i g h t S t r i n g W e i g h t+ = Tripping Kicks During Workovers
  • 66.
    Well Control DuringWorkovers and Completions 66 Unlike drilling, where mud weights generally increase as the hole is deepened, fluid weight in a completion or workover is, for the most part, fairly consistent. Should the fluid weight decrease due to dilution from produced fluids or accidental dilution on the surface, a kick is liable to occur. The fluid weights should be monitored for proper values at all times during the workover work. When using brines the pits should be covered to prevent dilution from ambient humidity. The higher the brine density the more affinity it will have for fresh water and the more prone it is to becoming “cut” by the contamination from humidity. Not only this, but a high density brine can be quite expensive and reconditioning the fluid will be an added cost to the completion or workover - one which can easily be avoided. Insufficient Fluid Weight Loss of Circulation Another source of a kick, although not as common as the preceding three, is loss of circulation. When fluid is lost to the hole it is generally assumed to be lost to the producing formation, and in many cases it is. But this is not always the case. If communication has been established to an upper zone with a pore pressure greater than the producing formation, a flow can take place from the invaded zone into the wellbore and into the producing formation. Not only would a kick be in progress with formation fluids entering the wellbore, but an underground blowout (zone-to-zone flow) as well. This type of well control situation can be difficult, at best, to contain and can oftentimes lead to severe damage to the producing formation, loss of an appreciable amount of production, if not the loss of the productive interval brought about by the required kill techniques. Kicks During WorkoversCauses of Kicks
  • 67.
    Well Control DuringWorkovers and Completions 67 Unseating Packers Several different types of packers may be used in a completion and more than one are generally left in the hole, especially for the nearly universal gravel-packed producing zone(s). Therefore a workover usually involves unseating or pulling the seal assembly from several packers, most of which will have some accumulation of formation fluids trapped below them. The fluids accumulate in the dead space between the bottom of the packer rubber and the topmost opening in the tubing extension below the seal nipples. If the well has not previously been completely killed on the tubing side, then the entire rat-hole below the packer may contain formation fluids. If the well makes any gas at all, the trapped volume will be full of gas because of gravity segregation. When the packer is unseated or the seals pulled above the packer bore, the trapped gas escapes into the annulus and starts migrating up the wellbore. The release of the gas above the packer does not itself threaten to make the well flow at the moment it occurs because the bottomhole pressure has not been changed significantly. However there is seldom any immediate surface indication that the trapped gas is there and the crew may be unaware of the possible danger. Kicks During WorkoversCauses of Kicks
  • 68.
    Well Control DuringWorkovers and Completions 68 Tripping with Fluid Losses Fluid losses to the formation are commonplace in workover/completion operations. The rate of such loss varies with formation permeability, fluid viscosity, degree of overbalance, pipe- induced pressure surges, and pressures caused by circulation of the wellbore. These losses add another dangerous dimension to tripping the pipe, already established as the most kick-prone activity in any oil/gas well operation. A wide range of viscosifiers and solids are used to control loss rates. In preparation for tripping, plans generally call for bringing the fluid loss down to a maximum that varies from 10 to 20 barrels per hour, depending on the stage of the completion, formation sensitivity, and the difficulty of achieving the desired cap without undue formation damage. If the loss rate, once brought down to an acceptable range, remains consistent while tripping, monitoring the proper fill on the way out is more straight forward. Despite the numerous differences between drilling/completion/workover work, the warning signs that indicate an actual or potential well control problem while tripping are unchanged. We still watch for a flow, a pit gain, or the hole not taking the right volume. All of these conditions are much easier to assess if the fluid loss rate is known and stable. Unfortunately the loss rate can vary with pipe movement itself and the simple passage of time. Kicks During WorkoversCauses of Kicks
  • 69.
    Well Control DuringWorkovers and Completions 69 Fishing Efforts to recover tools or pipe lost in the hole can add to the likelihood of a kick or the difficulty of controlling one in several ways: • More trips • Fish swabbing or interfering with circulation • Long periods with the hole uncalculated Fishing by its very nature greatly increases the number of trips. While this is true also of fishing while drilling, all of the differences described earlier combine to make that increase more risky in the workover and completion environment. The fish itself, especially if it includes a packer or a multi-way circulating port, can add greatly to in-hole pressure surges. If it is blanked off or the fishing tool cannot seal on its top, the fish becomes a barrier to full-hole circulation - the longer the fish, the greater the effect. If the fish is long, or the fishing is done by wireline, the hole may be uncirculated for extended periods, during which formation fluids may be working in the wellbore where they cannot be removed. The gas in the hole can migrate during trips and cause well flow. All of these considerations lean toward the possibility of a kick at that worst possible time - when the worksting is far off bottom or out of the hole. Finally, in a prolonged fishing job another disquieting element sneaks into the picture - the human one. Repetitive trips and concentration on the details of the fishing job itself tend to develop complacency or at least relaxation of vigilance. Kicks During WorkoversCauses of Kicks
  • 70.
    Well Control DuringWorkovers and Completions 70 Cleaning Out Fill Circulating to remove fill from the active wellbore occurs with frequency in completions and workovers. It is a routine operation in most cases, involving short intervals of loosely packed sand, scale, coal fill, or other debris following such operations as perforating, testing, or gravel packing. The fill is merely a temporary impediment to the next step in the program. It is most often cleaned out and without incident, generally by reversing out under a closed annular preventer or tubing stripper while lowering the pipe fitted with appropriate cleanout tools. However, sometimes the fill results from sanding up of the well while on production or from a kick that brought formation solids into the wellbore. These problems can effectively seal off the producing zone from the hole above the fill, possibly at considerable distances off bottom. Then when the fill is cleaned out, usually circulating the long way because of the extended intervals involved, any break in the continuity of the fill can expose trapped formation fluids. This can lead to repeated requirements to circulate the well clean under the choke or through a blooie line. Kicks During WorkoversCauses of Kicks
  • 71.
    Well Control DuringWorkovers and Completions 71 When a wash tool or muleshoe breaks completely through the fill it may turn out to be a bridge a long way off bottom. Under these conditions a long column of formation fluids can exist below the bridge, and the hydrostatic available above the bottom of the workstring may be inadequate to hold the formation pressure. The general effect is a kick off bottom with the rat-hole full of gas and oil. On the other hand, if the breakthrough occurs near enough to the perforations that the well is considerably overbalanced, the fluid level in the annulus can drop suddenly and allow the well to kick. Either way, the result is an off-bottom kick with unpredictable lost returns to complicate the kill. Cleaning Out Fill Kicks During WorkoversCauses of Kicks
  • 72.
    Well Control DuringWorkovers and Completions 72 • Flow increase without an increase in pump rate • Pit level increase • Well flows with the pump off Flow Increase Pit Level Increase Well Flowing With Pumps Off While Circulating Kicks During Workovers
  • 73.
    Well Control DuringWorkovers and Completions 73 Kicks During Workovers The three main indicators of unintentional kicks all deal with flow from the formation into the wellbore. One common workover procedure deals with the plugging and abandonment of one zone and the initiation of production from another. This is usually done by setting bridge plug above the zone to be abandoned and then placing cement on the bridge plug. In other instances merely a cement plug is placed across perforations. In either case, it’s always a good idea to check the well for flow after waiting for the cement to cure. There is a possibility for cement contamination from formation fluids which can prevent the cement from setting up properly. When this happens gas can channel its way through the cement. If this happens, another cement plug has to be placed over the failed one. Additionally, additives should be mixed with the cement to minimize or inhibit contamination.
  • 74.
    Well Control DuringWorkovers and Completions 74 Additional warning signs can appear prior to or in conjunction with a kick. Gas cutting of the workover fluid Kicks During Workovers Although gas cutting unto itself is not an indicative sign of a kick, it should be at least a warning to the crew that gas has invaded the wellbore. Gas can reduce the density of the workover fluid at the surface because of the expansion of the gas as it surfaces, but the overall reduction in hydrostatic pressure is usually minimal. Which is not to say that gas breaking out of the fluid at the surface should be ignored.
  • 75.
    Well Control DuringWorkovers and Completions 75 Oil shows in the workover fluid Oil shows in the workover fluid will, to a small degree, reduce the hydrostatic pressure of the fluid column, but only minimally so. But like gas, it is a sign of formation fluid invasion and should be checked out. Additional warning signs can appear prior to or in conjunction with a kick. Kicks During Workovers
  • 76.
    Well Control DuringWorkovers and Completions 76 Prior to beginning the trip, there should be at least one bottoms-up circulation. During this time the returning fluid density should be checked on a regular basis, every 5 to 10 minutes, and recorded. Along with this, there should be notes made as to any show of formation fluids. After the bottoms-up circulation is completed, the well should be allowed to remain static for a period of time to make sure it’s dead before the trip out begins. Inadequate Hole Fill During Trips The most reliable indicator of a well control problem while tripping is fill-up volumes that don’t correspond, within reason, to calculated values. Should this occur anytime during the trip, the trip should be stopped and the well monitored closely for flow. And when in doubt, don’t hesitate to shut-in the well. If fill-up trends continue to show discrepancies, stop the trip and return to bottom. Once on bottom be prepared to shut-in the well and circulate the well on a choke. Likewise when tripping in the hole, the volume being returned due to displacement should be monitored. If the volume returned is greater than calculated displacement, be prepared to shut-in. Well Flowing While The Pipe Is Stationary (Tripping In) This should be fairly obvious, but all too often, crews get so involved with the business of tripping in the hole, that the hole can go unmonitored. Flow while the pipe is stationary can go undetected for quite some time. MONITOR THE DISPLACEMENT TRIPPING IN AND OUT OF THE WELL. While Tripping Kicks During Workovers
  • 77.
    Well Control DuringWorkovers and Completions 77 Shut-In Procedures - On Bottom Circulating – Surface Stack 1. With the pump(s) running, pick up off bottom to pre-determined space off height to ensure a tool joint is not across the stack. 2. Stop the pump(s) and check for flow. 3. If flow exists, shut-in the top set of pipe rams. 4. Gain casing access by opening the appropriate valve on the choke line side of the stack. 5. Open the valve downstream of the choke. 6. Record SITP and SICP and estimate of pit gain. 7. At this point, the annular preventer, if one is installed, could be closed and the top pipe rams opened. Shut-In Procedures - On Bottom Circulating – Surface Stack Containing a kick and keeping the influx volume to a minimum can not be overemphasized. The shut-in, or containment procedures, can vary depending on the type of unit in use, coiled tubing, snubbing, small tubing, or conventional workover rig and the operation in progress at the time of the kick - on bottom circulating or tripping. The shut-in procedures given below will apply to a conventional workover rig and small tubing unit. Containment procedures for coiled tubing and snubbing units will be handled in their respective chapters. The shut-in procedures given below are done under the premise of the “hard shut-in.” Due to the limited wellbore volumes available in a completed well or one being worked over, it is imperative that minimal time be expended in shutting in a well. Kicks During Workovers
  • 78.
    Well Control DuringWorkovers and Completions 78 1. Stop the trip and position the pipe ensuring there is not a tool joint across the stack. 2. Secure the workstring by installing a full opening safety valve - close the safety valve after installation. 3. Shut-in the top pipe rams. 4. Gain casing access by opening the appropriate valve on the choke line side of the stack. 5. Open the valve downstream of the choke. 6. Record SICP and estimate of pit gain. 7. Have an inside BOP (workstring check valve) available in case stripping is required. 8. At this point, the annular preventer, if one is installed, could be closed and the top pipe rams opened. Shut-In Procedures While Tripping – Surface Stack Kicks During Workovers
  • 79.
    Well Control DuringWorkovers and Completions 79 Additional Considerations: Have crossovers on the floor so that the full opening safety valve and inside BOP can be installed onto any component of the workstring. Be familiar with the closing volumes of the preventers to be used. Visually inspect the BOP stack and choke manifold for leaks shortly after shut-in. Have someone continuously monitoring and recording shut-in pressures every minute. Kicks During Workovers
  • 80.
    Well Control DuringWorkovers and Completions 80 Immediately following shut-in, the casing pressure should be monitored and pressure recorded on a regular basis. Thirty-second intervals would not be unrealistic, especially if the workover fluid lacks viscosifying agents. Untreated workover fluids characteristically have little to no static surface tension and therefore gas migration is certain to occur. Unless the pressure is continually monitored during the first few minutes after shut-in, it may be impossible to ascertain a stable shut-in casing pressure which would be the casing pressure to maintain during pump start-up assuring bottomhole pressure maintenance. With gas migration in progress, a highly possible outcome could be a bottomhole pressure substantially greater than formation pressure which could cause a loss of fluid to the perfs, possible damage to the producing formation, or formation fracture. PSI Time Hypothetical stabilization point may not be of long duration Continual pressure increase due to gas migration Kicks During Workovers
  • 81.
    Well Control DuringWorkovers and Completions 81 The illustration at left describes the pressures at work in a stabilized shut-in situation. The total hydrostatic on either side of the well is imposed upon by formation pressure. Any difference, or differential, appears on the surface and indicates the amount of hydrostatic that must be replaced to at least balance formation pressure. Often times in a completion or workover, there is no SITP, provided the shut-in took place properly. The lack of pressure on the tubing indicates the fluid density in the tubing at least balances formation pressure. A presence of tubing pressure could be due to trapped pressure. Hydrostatic of Workover Fluid Hydrostatic of Influx SITP SICP + + + Formation Pressure Total PressureTotal Pressure Kicks During Workovers Hydrostatic of Workover Fluid
  • 82.
    Well Control DuringWorkovers and Completions 82 As seen from the previous page, the combination of shut-in pressure and hydrostatic pressure on either side of the well creates a total pressure equal to formation pressure. Or in essence, bottomhole pressure equaling formation pressure. Any pressure in the wellbore which creates a bottomhole pressure in excess of formation pressure would show up at the surface. Sources of trapped pressure are: • The pump inadvertently left running after shut-in • Pumping into a shut-in well • Surface pressure increase caused by migrating gas unable to expand When shut in pressures are initially recorded following stabilization, it’s a good idea to determine if these pressures are accurate, i.e., representative of just the differential between formation pressure and wellbore hydrostatics. The following procedure can be used to detect the presence of trapped pressure and to remedy the situation if any is found. Perform this only after surface pressures have stabilized. STEP 1 Bleed a small amount of fluid through the choke (1/4 to 1/2 bbl) - surface pressures will initially decrease, build, and then stabilize. STEP 2 Observe SITP - if the SITP stabilized at a value less than the previously observed stable pressure, trapped pressure was detected and at least, partially bled off. STEP 3 Bleed another small amount of fluid through the choke and once again observe the stabilized SITP. STEP 4 True, or accurate, SITP is realized when consecutive and identical values appear on the tubing gauge - in most cases in completions and workovers, the SITP should bleed to 0 psi. Kicks During Workovers
  • 83.
    Well Control DuringWorkovers and Completions 83 Kicks During Workovers SHUT IN SURFACE PRESSURES In both cases, the SITP and SICP are measuring the same thing: Differential pressure between the total hydrostatic pressure on either side of the well with respect to formation pressure. In most cases, the casing pressure is greater than the tubing pressure due to the reduced annular hydrostatic pressure caused by the presence of influx fluid/s which are of lesser density than the workover fluid. And as previously stated, in most cases during a workover, the SITP will be 0 psi because Kill Weight Fluid is already in the wellbore. If the SITP does not bleed to 0 psi (check the pressure with more than one pressure gauge), then check the density of the workover fluid – it may have become inadvertently light because of contamination of excessive formation fluid or by accidental dillution.
  • 84.
    Well Control DuringWorkovers and Completions 84  Shut-in Tubing Pressure is the difference between hydrostatic and formation pressure.  Kill weight fluid is calculated using the Shut-in Tubing Pressure.  Always round up to next highest tenth ppg. The following two formulas can be used to calculate Kill Weight Fluid: Kill Weight Fluid should be the exact fluid weight required to balance formation pressure (no overbalance margin or safety factor). Kicks During Workovers ( ) Pits Vertical PSI WtFluid DepthPerf SITP +      ×052. ( ) Pits Vertical WtFluid DepthPerf SITP . 23.19 +      × Either formula will render the same results
  • 85.
    Well Control DuringWorkovers and Completions 85 Kicks During Workovers Wellbore Volume In any well control operation it is necessary to know the wellbore volume. The following two formulas are used to accomplish this: BBLMeasured Tbg VolumeLength ID =×         4.1029 2 Tubing Volume Annular Volume ( ) BBLMeasured TbgCsg VolumeLength ODID =×         − 4.1029 22
  • 86.
    Well Control DuringWorkovers and Completions 86 Gas Migration After a well is shut-in the gaseous phase of the kick can start migrating up the hole. This is especially true during workovers and completions due to the lack of viscosity in the workover fluid. Migrating rates can vary from a few hundred feet per minute upwards to as high as several thousand feet per minute. If pumping can start soon after the well is shut in and stabilized, gas migration is not an issue. But if pumping is delayed, for what ever reason, gas will begin to migrate up the hole. Evidence of migration is steadily increasing surface pressures. Gas behaves according to a “pressure-to-volume” relationship: If exerted pressure increases the volume decreases. If exerted pressure decreases the volume increases. If the volume is not allowed to expand, the pressure within the gas remain unchanged.
  • 87.
    Well Control DuringWorkovers and Completions 87 Gas Migration The following information will be used to illustrate what can happen to migrating gas in a well: Formation Pressure: 5500 psi Annular Hydrostatic: 5000 psi Tubing Hydrostatic: 5500 psi SITP: 0 psi SICP: 500 psi 0 PSI 500 psi
  • 88.
    Well Control DuringWorkovers and Completions 88 Gas Migration The gas has migrated halfway up the hole but no fluid has been bled from the well. Since the gas volume has not changed it still contains its original pressure, in this case, 5500 psi. 5500 psi 2500 psi hydrostatic above the gas 2500 psi hydrostatic below the gas 3000 psi 2500 psi Bottom hole pressure = 8000 psi 5500 2500 HP 2500 HP 8000 psi 3000 psi Annulus 5500 HP 8000 psi 2500 psi Tubing
  • 89.
    Well Control DuringWorkovers and Completions 89 Gas Migration The gas has migrated to the surface- no fluid has been bled from the well. Since the gas volume has not changed it still contains its original pressure, in this case, 5500 psi. 5500 psi 5000 psi hydrostatic below the gas 5500 psi 5000 psi Bottom hole pressure = 10500 psi 5500 5000 HP 10500 psi 5500 psi Annulus 5500 HP 10500 psi 5000 psi Tubing
  • 90.
    Well Control DuringWorkovers and Completions 90 Gas Migration It should be obvious from the preceding two pages that if gas migrates up the hole in an unexpanded state, bottom hole and surface pressure can increase dramatically which can lead to excessive fluid loss to the formation and undue stress on surface pressure control equipment and the casing. There are two methods available to handle this situation which will maintain bottom hole pressure equal to, or slightly greater than formation pressure, and keep surface pressures to a minimum. The first method involves using the choke to maintain a constant pressure on the workstring while migration is in progress. The second method, again, involves using the choke to bleed off measured amounts of fluid along a prescribed schedule. Neither method is difficult and requires a minimum of equipment. It should be understood that these methods are to be employed only if pumping is not possible at the time migration starts, and the methods should be used until pumping is possible, and at that time, the well put on choke and circulated. It should also be understood that neither of these two methods will kill the well. They are simply used to prevent excessive increases in bottom hole and surface pressures.
  • 91.
    Well Control DuringWorkovers and Completions 91 0 psi 500 psi We’ll use the earlier example to illustrate this method. The SITP is 0 psi indicating that the hydrostatic pressure of the fluid in the hole at least balances the formation pressure. There is pressure on the casing due to the presence of gas in the annulus which has decreed the annular hydrostatic. Gas Migration Constant Tubing Pressure
  • 92.
    Well Control DuringWorkovers and Completions 92 200 psi 700 psi Gas Migration Constant Tubing Pressure MethodShortly after the well is shut in the gas begins to migrate in an unexpanded state. Evidence of the migration is seen at the surface by increasing surface pressures. Since the surface pressure have increase by 100 psi, bottom hole pressure has also increased by 100 psi. It’s a good idea to incorporate a small overbalance and this initial increase in surface pressure can be used for that. Keep monitoring the tubing pressure as migration continues. Allow a second pressure increase to take place. This second increase will be used for bleeding fluid. Bottom hole pressure has increased by 200 psi above formation pressure PSI TIME Casing Tubing 200 psi increase 100 psi for overbalance 100 psi for fluid bleeding 0 100 200 300 400 500 600 700 800
  • 93.
    Well Control DuringWorkovers and Completions 93 Gas Migration Constant Tubing Pressure Method 200 psi 700 psi Bottom hole pressure has increased by 200 psi above formation pressure PSI TIME Casing Tubing 200 psi increase 100 psi for overbalance 100 psi for fluid bleeding 0 100 200 300 400 500 600 700 800 Following the initial increase of 200 psi, bleeding can take place. Fluid is to be bled through a choke from the annulus side only. Monitor the casing pressure while bleeding decreasing the casing pressure by, in this case, 100 psi, then close the choke. Monitor the tubing pressure. If the bleeding was performed correctly, the tubing pressure will decrease by 100 psi and stabilize. Because of the annular bleeding, annular hydrostatic is now decreased. This may cause a slight increase in casing pressure. Fluid bled and pressures stabilize
  • 94.
    Well Control DuringWorkovers and Completions 94 Gas Migration Constant Tubing Pressure Method 100 psi 620 psi Bottom hole pressure has increased by 100 psi above formation pressure PSI TIME Casing Tubing 0 100 200 300 400 500 600 700 800 100 psi increase Migration continues after the first bleeding cycle and surface pressures have increased by another 100 psi. Perform another bleeding cycle. Fluid bled and pressures stabilize
  • 95.
    Well Control DuringWorkovers and Completions 95 Gas Migration Constant Tubing Pressure Method PSI TIME Casing Tubing 0 100 200 300 400 500 600 700 800 Continued bleeding cycles would result in what is seen plotted below. Casing pressure would increase due to the constant decrease in hydrostatic pressure but tubing pressure would remain essentially constant. This means that bottom hole pressure is maintained constant at a level just above formation pressure resulting in minimal fluid loss to the formation. Gradually increasing casing pressure Constant tubing pressure
  • 96.
    Well Control DuringWorkovers and Completions 96 Gas Migration Volumetric Method 0 psi 500 psi Obstruction in tubing In this situation a kick has been taken but due to an obstruction in the tubing, circulation is impossible. Shortly following shut in the gas begins to migrate. Because of the obstruction there is no tubing pressure to monitor, and the Constant Tubing Pressure Method can not be used on the annulus because of its ever- changing hydrostatic pressure caused by the required bleeding. The method used to handle this situation is called the Volumetric Method.
  • 97.
    Well Control DuringWorkovers and Completions 97 Gas Migration Volumetric Method The Volumetric Method is used when pumping is impossible due to an obstruction in the workstring. In this situation the casing pressure would increase but the tubing pressure would remain at 0 psi. Similar to the Constant Tubing Pressure Method, the annular surface pressure is allowed to increase by an overbalance and an amount used for bleeding. However, in this case, the volume to bleed from the annulus is calculated based on the surface pressure increase, the wellbore geometry at the point where fluid is leaving the annulus, and the density of the fluid in the hole. The following is used to calculate this volume. ( ) BleedtoBBL WtFluidODID IncreasePSI TbgCsg =                       ××− .052. 4.1029 22
  • 98.
    Well Control DuringWorkovers and Completions 98 Gas Migration 0 psi 700 psi PSI TIME 200 psi increase 100 psi for overbalance 100 psi for fluid bleeding 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 Similar to the Constant Tubing Pressure Method, surface pressure is allowed to increase for an overbalance and an amount used for bleeding. In this case, 100 psi increments will be used again. Information for an example calculation is as follows: Csg ID: 5.125” Tbg OD: 2.875” Fluid Wt. 10.4 ppg Volumetric Method
  • 99.
    Well Control DuringWorkovers and Completions 99 Gas Migration ( ) BBL psi 323.3 4.10052.875.2125.5 5.1029 100 22 ≈=                     ××− Volumetric Method The calculated volume is rounded off to accommodate rig equipment and volumes that can be realistically measured. PSI TIME/BBL BLED 200 psi increase 100 psi for overbalance 100 psi for fluid bleeding 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 During the first cycle three bbl of fluid is to be bled from the annulus through the choke while maintaining a constant casing pressure. The length of time required for this depends on the migration rate of the gas. After bleeding the calculated volume the choke is closed and casing pressure is monitored while migration progresses. Another 100 psi increase would signal the beginning of the second cycle. First bleeding cycle
  • 100.
    Well Control DuringWorkovers and Completions 100 Gas Migration Volumetric Method PSI 0 100 200 300 400 500 600 700 800 900 1000 1100 1200 The second cycle take place with the bleeding of 3 bbl of fluid from the annulus while holding the casing pressure constant. The procedure continues until gas reaches the surface or when pumping is possible. If gas reaches the surface the casing pressure should be monitored. As long as casing pressure increases continue the bleeding procedures. Casing pressure will finally peak when all the gas reaches the surface when migration stops. TIME/BBL BLED Second bleeding cycle Once gas reaches the surface, it should be either circulated out or removed by lubrication and bleeding. The gas should not be bled without replacing it with fluid. Doing so would create a serious well control situation that could lead to a surface blowout.
  • 101.
    Well Control DuringWorkovers and Completions 101 Example: A 100 psi surface pressure increase has taken place in 45 minutes. The fluid in the hole is 8.5 ppg water. Based on this the migration rate can be calculated as such: Gas Migration Gas Migration Rate ( ) HrFt Hours RateMigration TimeWtFluid IncreasePSI / .052. = ×× ( ) FeetMigrated WtFluid IncreasePSI = ×052. ( ) HrFt Hoursppg psi /30265.301 75.5.8052. 100 ≈= ×× ( ) Feet ppg psi 22624.226 5.8052. 100 ≈= × If the tubing is obstructed it may be desired to find the depth of the obstruction with wireline and possibly remove it or perforate above the obstruction in order to kill the well by circulation. The following two formulas can be used to determine the depth of the bottom of the gas and how fast or slow the gas is moving up the hole. If it is decided to perforate the tubing, make sure the perforation occurs below the kick to prevent contamination of the workstring fluid.
  • 102.
    Well Control DuringWorkovers and Completions 102 Gas Migration Uncontrolled Gas Expansion All kick management methods, circulating and non-circulating, deal with controlling gas expansion in a wellbore, and for good reason - uncontrolled gas expansion can be catastrophic which is why there should be constant and consistent monitoring of pit levels, return flow rates, and fluid density. Gas expansion is affected by the following: Pressure exerted on the gas Gas volume Temperature For simplicity temperature will be ignored in this example of uncontrolled gas expansion. Gas expansion can be described by the following relationship: 2 1 P P P1 - initial pressure exerted on the gas P2 - new pressure exerted on the gas
  • 103.
    Well Control DuringWorkovers and Completions 103 Gas Migration Uncontrolled Gas Expansion The following information will be used to illustrate the potential for uncontrolled gas expansion: Well Depth: 10000 feet Fluid Weight: 9.5 ppg Kick Volume: 10 bbl Casing ID: 5 ¼”
  • 104.
    Well Control DuringWorkovers and Completions 104 Gas Migration Uncontrolled Gas Expansion The initial pressure exerted on the gas is a combination of wellbore hydrostatic pressure and surface pressure. Length of the Gas '373'47.37310 25.5 4.1029 2 ≈=×      KickBBL Length & Hydrostatic Pressure of Fluid Above the Gas FeetGasofFtFT 962737310000 =− PSIFeetPPG 47567.475596275.9052. ≈=×× P1 = 4756PSI As the gas moves up the hole the hydrostatic pressure above the gas decreases thus allowing the gas to expand.
  • 105.
    Well Control DuringWorkovers and Completions 105 Gas Migration Uncontrolled Gas Expansion The gas has migrated up the hole to the depth of 5000’. The expanded gas volume is calculated as follows: ( ) BBLBBL FeetPPG PSI 25.1910 50005.9052. 4756 =× ×× BBLVolumeKickInitial P P ×      2 1 The gas moved halfway up the hole and almost doubled in volume.
  • 106.
    Well Control DuringWorkovers and Completions 106 Gas Migration Uncontrolled Gas Expansion The gas is now at a depth of 2500 feet. The expanded gas volume is calculated based on the initial pressure versus the new pressure exerted on the gas. ( ) BBLBBLBBL FeetPPG PSI 3951.3810 25005.9052. 4756 ≈=× ×× Based on the reduction in hydrostatic pressure above the gas it has expanded almost 4 times its initial volume.
  • 107.
    Well Control DuringWorkovers and Completions 107 Gas Migration Uncontrolled Gas Expansion The gas is now at the surface where the only pressure exerted on the gas is atmospheric pressure. The expanded volume of the gas is: BBLBBL PSI PSI 3245.32310 7.14 4756 ≈=× In thus case the uncontrolled gas expansion exceeds the wellbore volume. Hopefully, if gas enters a wellbore and starts to migrate or is circulated up the hole and expands, the displacement of fluid caused by this expansion will be noticed by someone on location and appropriate actions taken. Otherwise the well will surely blowout.
  • 108.
    Well Control DuringWorkovers and Completions 108 A method of killing a well should allow for regaining control of the well without doing harm to the producing formation, and should also exert a bottom hole pressure that is at least equal to, or slightly greater than formation pressure. As previously stated, the SITP is used as a bottom hole pressure gauge and is indicative of any existing differential between formation pressure and the fluid hydrostatic in the workstring. A pressure existing on the tubing gauge indicates the required additional hydrostatic pressure needed to balance formation pressure, and this additional hydrostatic is converted into its equivalent in mud weight via the kill weight mud formula. SITP > 0 psi means the fluid weight must be increased (with the tubing at or very near bottom) There are two methods available to use if the condition exists dictating a fluid weight increase: Wait & Weight Method This method is, in theory, a one-circulation kill method. The crew “waits” until the fluid is at the proper kill “weight” and then pumps kill weight fluid only with no additional safety factors in the form of additional weight. The overbalance at the bottom of the hole is provided by annular friction once circulation is under way. In most cases this method creates the least amount of wellbore stress and the lowest ultimate annular surface pressure. Constant Pump Pressure The Driller’s Method is designed to be a two-circulation kill operation. During the first bottoms-up circulation the kick is pumped from the well. Fluid weight is increased during this time and is pumped into the well on the second circulation. Like the Wait & Weight, an overbalance is provided for at the bottom of the hole in the form of annular friction pressure. This method usually creates higher wellbore stresses and higher ultimate annular surface pressure than the Wait & Weight. One advantage of the method is that circulation can begin shortly after shut-in pressures have stabilized. Circulating Kill Techniques
  • 109.
    Well Control DuringWorkovers and Completions 109 If there is no pressure on the tubing with the bit at or near bottom, no differential exists and no fluid weight increase is needed. SITP = 0 psi means no fluid weight increase In this instance, with no SITP, the Constant Pump Pressure method is used, which is exactly what needs to take place. The pump pressure is held constant while the well is circulated at a steady rate. After bottoms-up is achieved, the well should be dead. Prudence however, dictates that the well be circulated for a while longer just to make sure the annulus is completely free of influx. SITP > 0 psi Wait & Weight Method Concerns about ultimate annular surface pressure (gas kick) Driller’s Method Desire to begin killing shortly after surface pressure stabilization SITP = 0 psi Constant Pump Pressure Kill the well at a constant pump pressure and pump rate Circulating Kill Techniques
  • 110.
    Well Control DuringWorkovers and Completions 110 Circulating Kill Techniques Constant Pump Pressure By far the most commonly used circulation method is Constant Pump Pressure. Its name implies exactly what is to be done – maintain a constant pump pressure, at a constant pump rate, once the well is successfully brought on choke. To bring the well on choke perform the following: STEP 1 Observe and record the SICP STEP 2 Crack the choke and bring the pump online. STEP 3 While bringing the pump up to the selected kill rate, manipulate the choke to maintain a constant casing pressure. STEP 4 After the pump is at the kill rate, manipulate the choke to maintain a constant pump pressure until the well is dead.
  • 111.
    Well Control DuringWorkovers and Completions 111 The Wait and Weight Method gets it’s name from the fact that there is a “waiting” time while the mud weight is increased or “weighted” up prior to circulating the influx from the hole. The W & W Method is only required for killing a kick that requires a heavier fluid weight (called the kill weight fluid). Generally the well can be killed in one complete circulation. But, since it is only recommended to use a balancing kill fluid weight, additional circulation will be required to increase the fluid weight by a suitable safety factor after the well is dead. Advantages Include  Pressures exerted on the wellbore and on control equipment will generally be lower than when using the Driller’s Method. The difference is most significant if the influx is gas, and/or large volume kicks.  The maximum pressure exerted on the wellbore is the lowest is can be  The maximum annular surface pressure is as low as possible given the situation  The well will be under pressure for less time. Circulating Kill Techniques Wait & Weight Method
  • 112.
    Well Control DuringWorkovers and Completions 112 1. Determine a suitable circulation rate. The upper limit for the circulation rate is generally set by the maximum allowable annular friction pressure such that extreme ECD’s are not created. 2. Kill Weight Fluid (KWF). The kill weight fluid, which is a known value. The fluid in the pits must be weighted-up to the Kill Weight. 3. Calculate the workstring and annulus volumes and Surface to Bit and bottoms up pump strokes. The workstring and annular volumes need be known to determine where the influx and kill weight fluid is within the circulation path during the well kill. This data is usually obtained from the completed kill sheet. Vertical and Low Angle Wells Circulating Kill Techniques StrokesTotal OutputPump VolumeWellbore STKBBL BBL = /
  • 113.
    Well Control DuringWorkovers and Completions 113 4. Calculate the anticipated Initial Circulating Pressure (ICP). The ICP should be calculated in order to estimate the circulating pressure that will be required to maintain constant BHP at the start of the well kill. 5. Calculate the Final Circulating Pressure (FCP). As the workstring is displaced with kill weight fluid, the circulating standpipe pressure must be reduced to take into account the increased hydrostatic pressure of the mud in the pipe. The standpipe pressure must also compensate for the increase in friction pressure due to pumping a heavier weight fluid. Once the workstring is completely displaced with KWM, the static workstring pressure should be zero. The required circulating standpipe pressure at this point is just the SCR pressure adjusted for the KWF. 6. Construct a circulating drillpipe pressure schedule vs. pump strokes. The choke operator needs to manipulate the control choke to follow the schedule of circulating drillpipe pressure (required to maintain constant BHP) verses the accumulated pump strokes during the well kill. This will ensure the well kill is going smoothly and help identify any potential problems that may occur. Vertical and Low Angle Wells Circulating Kill Techniques
  • 114.
    Well Control DuringWorkovers and Completions 114 1. Bring pump on line as per Pump Start-up procedure. 2. Compare the actual Initial Circulating Pressure to that shown (calculated) on the Tbg. Pressure Schedule. Re-construct the Tbg. Circulating Schedule if necessary. 3. Adjust the choke as necessary to control the drillpipe pressure according to the schedule. Continue until kill weight fluid returns to the surface.  Always be alert to potential problems. If ANY problem is suspected, STOP the pump and CLOSE the well in. 4. Stop the pump and close the choke. SITP and the SICP should be equal or nearly equal to zero. If so, open choke and check for flow. If not, bring pump back on line and circulate through the choke to further condition the mud. Pump Strokes Circ. Pressure (psi) 0 ICP (psi) FCP (psi) Strokes To Bit (1) (2) (3) (4) (5) (6) (7) (8) (10) (9) Circulating Pressure Schedule Vertical and Low Angle Wells Circulating Kill Techniques
  • 115.
    Well Control DuringWorkovers and Completions 115 Choke and Standpipe Pressure WELL DATA: Well depth 11,480 ft BHA 6 ½”, 591 ft Shoe depth 6,560 ft Pipe 5” OD DP MW 14.2 ppg Method Driller’s Kick EMW 15.2 ppg Influx 20 bbls gas SIDPP 600 psi SCR 500 psi @ 30 spm Volume Pumped (bbls) SurfacePressure(ps drillpipe Volume 800600400200 SCR SIDPP Annulus Volume 200 400 600 800 1000 1200 1600 1400 1800 Choke Pressure (W and M Method) Choke Pressure (Driller’s Method) SCR (FCP) Stand Pipe Pressure A B C D E Circulating Kill Techniques
  • 116.
    Well Control DuringWorkovers and Completions 116 1. Bring pump on line as per Pump Start-up. 2. Compare the actual Initial Circulating Pressure to the pre-calculated ICP. If the actual measured ICP is greater that the pre-calculated ICP, correct the kill sheet and use the actual ICP.  If the actual ICP is less than the calculated ICP, stop the pump and close the well in. Determine if there are any problems in the circulating system. 3. Adjust the choke as necessary to control drillpipe pressure constant until all influx is circulated from well.  Always be alert to potential problems. If ANY problem is suspected, STOP the pump and CLOSE the well in. 4. Stop the pump and close the choke. SITP and SICP should be equal or near equal. If so (and necessary), then kill the well using the W & W method. If not, bring the pump back on line and circulate through choke to condition wellbore fluids. Circulating Kill Techniques
  • 117.
    Well Control DuringWorkovers and Completions 117Volume Pumped (bbls) Pressure(psi) 1800 1600 1400 1200 1000 800 600 400 200 200 400 600 800 Stand Pipe Pressure Choke Pressure A B C D E First Circulation - Choke and Standpipe Pressure WELL DATA: Well depth 11,480 ft BHA 6 ½”, 591 ft Shoe depth 6,560 ft Pipe 5” OD DP MW 14.2 ppg Method Driller’s Kick EMW 15.2 ppg Influx 20 bbls gas SIDPP 600 psi SCR 500 psi @ 30 spm Circulating Kill Techniques
  • 118.
    Well Control DuringWorkovers and Completions 118 Second Circulation - Choke and Standpipe Pressure Volume Pumped (bbls) SurfacePumped(psi) SCR SIDPP drillpipe Volume Annulus Volume 800600400200 200 400 600 800 1000 1200 1600 1400 1800 SCR2 Stand Pipe Pressure Choke Pressure WELL DATA: Well depth 11,480 ft BHA 6 ½”, 591 ft Shoe depth 6,560 ft Pipe 5” OD DP MW 14.2 ppg Method Driller’s Kick EMW 15.2 ppg Influx 20 bbls gas SIDPP 600 psi SCR 500 psi @ 30 spm Circulating Kill Techniques
  • 119.
    Well Control DuringWorkovers and Completions 119 Pump Operator 1. Begin slow and easy; it should take at least a full minute to bring the pump up to the planned kill rate. 2. Monitor the pump rate increase and drillpipe and casing pressures. Communicate these values to the Choke Operator. 3. Pump pressure should rise steadily and casing pressure should remain relatively constant. If any unusual pressure behavior is seen - stop pumping and communicate to the Choke Operator to close-in the well. Choke Operator's Responsibilities 1. Upon word from the Pump Operator that the pump has started, crack open the choke slightly and monitor the drillpipe and casing pressures. 2. As the pump comes up to kill rate, adjust choke as necessary to control casing pressure constant at the shut-in value until the pump is up to desired kill rate. 3. Be aware of unusual pressure behavior and communicate to the Pump Operator the drillpipe and casing pressures. Be prepared to instruct the Pump Operator to shut down the pump if unusual pressures are seen. 4. When the pump has reached the proper kill rate, continue to control casing pressure constant until the casing and drillpipe pressures have stabilized. 5. Record drillpipe pressure as the correct Initial Circulating Pressure (ICP). Compare it to the pre-calculated ICP value. Note: If actual ICP is greater than the calculated ICP, use the actual ICP and correct same on the Kill Sheet. If the actual ICP is less than the calculated ICP, stop the pumps, close in the well and determine if a problem exists in the circulating system. Then retry bringing the pump on line. Circulating Kill Techniques
  • 120.
    Well Control DuringWorkovers and Completions 120 WELL DATA: Well depth 11,480 ft BHA 6 ½”, 591 ft Shoe depth 6,560 ft Pipe 5” OD DP MW 14.2 ppg Method Driller’s Kick EMW 15.2 ppg Influx 20, 30, 40, 50 bbls gas 200 400 600 800 1000 1200 1600 1400 1800 Volume Pumped (bbls) ChokePressure(psi) 800600400200 20 BBLS 30 BBLS 40 BBLS 50 BBLS Driller’s Method for Various Influx Volumes Circulating Kill Techniques
  • 121.
    Well Control DuringWorkovers and Completions 121 Wait and Weight Method for Various Influx Volumes WELL DATA: Well depth 11,480 ft BHA 6 ½”, 591 ft Shoe depth 6,560 ft Pipe 5” OD DP MW 14.2 ppg Method Wait and Weight ChokePressure(psi) 20 BBLS 30 BBLS 40 BBLS 50 BBLS 200 400 600 800 1000 1200 1600 1400 1800 Volume Pumped (bbls) 800600400200 Circulating Kill Techniques
  • 122.
    Well Control DuringWorkovers and Completions 122 Precautions When ReversingAlthough reversing out is a common procedure in some operations, considerable forethought should be given to reversing out a kick, especially a gas kick. The choke pressure profiles seen on pages 18 and 19 reflect the required surface pressure supplied by the choke to make up for the lack of hydrostatic pressure in the annulus. And as seen in the illustrations, the trend is for back pressure to increase. This is expected given the expansion of the gas that has to be allowed. With gas expansion comes a decrease in overall annular hydrostatic pressure thus the required increase in back pressure. 20 BBLS 30 BBLS 40 BBLS 50 BBLS Volume Pumped (bbls) Required choke pressure is increasing due to gas expansion which causes a decrease in annular hydrostatic pressure Required Back Pressure Circulating Kill Techniques
  • 123.
    Well Control DuringWorkovers and Completions 123 Occasionally the decision is made to reverse out a kick - reasons being: To minimize contamination of expensive workover fluid Limit or minimize ultimate pressure on the casing due to a large influx Save time As long as the kick fluid is liquid, or primarily liquid, risks are minimal, but if the kick is predominantly gas, there are specific items to consider, namely the potentially rapid change in surface pressures and the equipment used when the reverse procedure is implemented. The well diagram on the following page will be used as an example to illustrate the differences between normal and reverse circulation where a gas kick is concerned. Reversing Out Kicks Circulating Kill Techniques
  • 124.
    Well Control DuringWorkovers and Completions 124 0 psi 407 psi WELL DATA 10000’ 2 7/8” TBG - 58 BBL Vol. 10000’ 5.5” ID Csg - 214 BBL Form Press EMW: 10 ppg = 5200 psi Kick Volume: 20 bbl Kick Length: 936’ Kick Hydrostatic Pressure: 94 psi Fluid Weight: 10.3 ppg SITP: 0 psi SICP: 407 psi Reversing Out Kicks Circulating Kill Techniques The information below will be used as baseline data for the example of comparing normal and reverse circulation of a gas kick in a workover environment. Stabilized Shut-in Conditions
  • 125.
    Well Control DuringWorkovers and Completions 125 58 bbl pumped - normal circulation 6001’ of fluid above gas 2714’ of fluid below gas 1285’ of gas 27.4 bbl 594 psi A volume pumped equal to the tubing volume (58 bbl) has been pumped. The influx has expanded based on the reduction in hydrostatic pressure above the gas. With this expansion comes a reduction in the annular hydrostatic pressure resulting in an increase in casing pressure. 20 bbl pumped - reverse 6001’ of fluid above gas 3454’ of gas 20 bbl 1756 psi The influx has been removed from the casing and now resides in the tubing. Static casing pressure is now 0 psi. The static tubing pressure reflects the vast change in tubing hydrostatic pressure due to the considerable vertical length occupied by the gas. Reversing Out Kicks
  • 126.
    Well Control DuringWorkovers and Completions 126 75 bbl pumped - normal circulation 5049’ of fluid above gas 3510’ of fluid below gas 1441’ of gas 30.8 bbl 679 psi A total volume of 75 bbl has been pumped. The influx has further expanded, and the decreased annular hydrostatic pressure has resulted in a casing pressure of 679 psi. Reversing Out Kicks 1270’ of fluid above gas 3454’ of fluid below gas 5276’ of gas 30.6 bbl 2732 psi 40 bbl pumped - reverse Considerable gas expansion has taken place in a relatively short period of time requiring extensive choke adjustments. Take note of the change in tubing pressure between this drawing and the previous one.
  • 127.
    Well Control DuringWorkovers and Completions 127 100 bbl pumped - normal circulation 3561’ of fluid above gas 4680’ of fluid below gas 1759’ of gas 37.6 bbl 848 psi A total volume of 100 bbl has been pumped. The expanded influx and decreased annular hydrostatic pressure has resulted in a casing pressure of 848 psi. 43.5 bbl pumped - reverse 153’ of fluid above gas 4050’ of fluid below gas 5796’ of gas 33.6 bbl 3010 psi Clearly seen in this diagram is the rapid expansion of the gas as it approaches the surface. And along with this expansion and reduction in annular hydrostatic pressure is a rapid increase in required back pressure in a relatively short period of time. Reversing Out Kicks
  • 128.
    Well Control DuringWorkovers and Completions 128 125 bbl pumped - normal circulation 5850’ of fluid below gas 2255’ of gas 48.2 bbl 1141 psi 75 bbl pumped - reverse 0 psi 1895’ of fluid above gas A total volume of 125 bbl has been pumped. The expanded influx and decreased annular hydrostatic pressure has resulted in a casing pressure of 1114 psi. Reversing Out Kicks Both the tubing and annulus are now full of fluid and the well is dead.
  • 129.
    Well Control DuringWorkovers and Completions 129 148 bbl pumped - normal circulation 6926’ of fluid below gas 3046’ of gas 65.1 bbl 1537 psi 28’ of fluid above gas Reversing Out Kicks A total volume of 148 bbl has been pumped. The influx has expanded from its initial volume of 20 bbl to now occupying 65.1 bbl of space in the annulus. The casing pressure of 1537 psi is the result of the decrease in annular hydrostatic pressure due to this expansion.
  • 130.
    Well Control DuringWorkovers and Completions 130 BBL Pumped PSI 300100 200 1000 2000 3000 4000 Tbg Displaced Annulus Displaced Tubing pressure response reverse circulation. Take note of the sharp changes that take place in a relatively short period of time. Casing pressure during response normal circulation Reversing Out Kicks Circulating Kill Techniques Comparison of Normal Circulation To Reverse Circulation
  • 131.
    Well Control DuringWorkovers and Completions 131 What is to be gained from the graph on the previous page? Take particular note of the relatively small amount of time it takes for surface pressure to increase significantly when reversing out. And, by comparison, the gradual increase in surface pressure while circulating in a normal fashion. Although somewhat simplified, the examples are representative of a constant bottom hole pressure method of killing a well while circulating - a well-known and widely accepted well killing concept. The danger lies not so much in the mathematical possibility of reversing out a kick as it does in its realistic implementation. The main requirements to successfully reversing out a gas kick: The proper equipment, installed properly, tested and in excellent working order Experienced and knowledgeable people with a good understanding of the U-tube Reversing Out Kicks Circulating Kill Techniques
  • 132.
    Well Control DuringWorkovers and Completions 132 Reversing Out Kicks There are ‘weak links’ in the chain, so-to-speak. The first occurs at the connection between the tubing and whatever kind of line will be used to connect the tubing to the choke manifold. Normally a full-opening safety valve is installed, and wisely so, but there should also be a back-up safety valve in case the full opening valve fails or the line between the tubing and choke manifold develops a leak. Either a low-torque valve or a pneumatic actuator are excellent choices. Consider this: Gas is flowing through the chicksan and into the choke manifold. A leak develops in the chicksan line. The normal reaction is to stop pumping and close the choke. But in this case, closing the choke would not stop the flow because the leak is upstream of the choke. The logical alternative would be to close the full-opening safety valve through which there is now a strong flow of gas. If the flow is strong enough, the valve will not be able to be fully closed - the well is now out of control and the chicksan, in all probability, will wash and fail in a short period of time.
  • 133.
    Well Control DuringWorkovers and Completions 133 Low-Torque Valve Full Opening Safety Valve Crossover Workstring Full Opening Safety Valve Crossover Workstring Pneumatic Actuator The illustrations are two means of “backing-up” the full opening safety valve. Should the chicksan lines develop a leak while circulating gas, either the low-torque valve or the pneumatic actuator could be closed, pressure bled from the lines via the choke and the leak repaired. When using the low- torque valve, an operating handle must be on hand. And when using the actuator, always have the fuseable cap in place. Reversing Out Kicks
  • 134.
    Well Control DuringWorkovers and Completions 134 Another ‘sore spot’ is the line connecting the tubing to the choke manifold. Normally this is chicksan. And very often this line is of a smaller ID than the tubing to which it will be connected. This means the velocity of whatever is flowing through it accelerates and presents more of an opportunity to wash or cut out. Reduced ID accelerates the velocity of the flow and increases the potential for pipe washing and cutting. Reversing Out Kicks
  • 135.
    Well Control DuringWorkovers and Completions 135 In every joint of chicksan there are two points where leaks can occur - the hammer unions located at either end of each joint. Another point of concern is in the elbow joints. A better system would be made up of flanged connections but, unfortunately, that is rarely available, so we’ll deal with what we are most likely to have to work with. The hammer unions need to be made up tightly and tested, paying special attention not only to the unions during the test but the elbow joints as well. Additionally, the chicksan must be securely anchored to minimize any movement that may occur while gas is being circulated through it. Reversing Out Kicks
  • 136.
    Well Control DuringWorkovers and Completions 136 Another point of concern are the chokes - both manual and remotely controlled. Remotely controlled, pneumatic or hydraulic, are not known for operating at very fast rates. And manual chokes, which can be somewhat difficult to operate with no pressure on them, can be extremely slow and arduous to operate while under pressure. Referring back to the graph of the reverse circulation, it should be clear, that a fast-acting choke is a must. If the choke can not be manipulated in a timely fashion, the results can be either over-pressuring the wellbore or allowing more influx into the well, prolonging the kill operation, and making an already uncomfortable situation all the more serious. As the gas surfaces and is being bled from the well, the tubing hydrostatic pressure begins to increase at a rapid rate. Because of this, the required back pressure must decrease relative to the increasing hydrostatic pressure. If the choke can not be opened fast enough, the bottom hole pressure will begin to increase - maybe to dangerous levels. Choke Concerns Reversing Out Kicks
  • 137.
    Well Control DuringWorkovers and Completions 137 100 200 1000 2000 3000 4000 Rapid choke adjustments required to provide the needed back pressure. If the choke opening can not be reduced fast enough BHP will decrease and another kick can enter the wellbore. Relatively rapid choke adjustments must take place to relieve back pressure due to the increase in tubing hydrostatic pressure. If the choke opening can not be increased fast enough BHP will increase which could result in loss of circulation or forcing fluids and unwanted solids into the producing formation. PSI BBL Pumped Choke Concerns Reversing Out Kicks
  • 138.
    Well Control DuringWorkovers and Completions 138 Liquid Kicks By comparison, if the kick is a liquid, oil or water, or a mix of the two, much of what has been described in the previous several pages will not take place. There will be no severe loss of hydrostatic - liquids don’t expand as gas does. And instead of constantly increasing tubing pressure, the tubing pressure would be on a steady decline. To be realistic about things though, it is rare to have a liquid hydrocarbon influx enter the well and not have some associated gas. So in “the real world” there would be some increase in surface pressure but not nearly so as compared to a “full blown” gas influx. Reversing Out Kicks
  • 139.
    Well Control DuringWorkovers and Completions 139 Potential Problems During the course of a well control operation problems could arise in some part, or parts of the circulating system that can have a direct impact on the circulating surface pressures or the effectiveness of the choke to alter pressures. Complications include:  Float or check valve in the workstring  Plugged workstring  Choke plugged  Workstring washout  Choke washout Excessive surface pressures while circulating Circulating Kill Techniques
  • 140.
    Well Control DuringWorkovers and Completions 140 Float or Check Valve in Workstring Circulating Kill Techniques Potential Problems Circulating Kill Techniques The presence of a check valve in the workstring prohibits the reading and monitoring of SITP. This can be alleviated with the following procedure: STEP 1 Record the stabilized SICP STEP 2 Start pumping on the tubing with a very slow rate – as slow as the pump will pump – do this while closely monitoring the SICP STEP 3 Record the pump pressure when the SICP first begins to increase. Record this pressure and immediately stop the pump. STEP 4 Subtract any observed casing pressure increase from th recorded pump pressure. The result is the SITP. Theoretically the check valve would open and there would be a slight decrease in pump pressure, the decrease indicating when the check valve opens. At this point the pump is stopped and the pressure recorded as the SITP. However, it’s virtually impossible to stop a pump that quickly and not add pressure to the casing after the check valve opens.
  • 141.
    Well Control DuringWorkovers and Completions 141 Plugging or Plugged Workstring Potential Problems Circulating Kill Techniques While circulating out a kick, anytime circulating pressures change suddenly, observe what’s happening on the other side of the well before taking action. If the Tubing pressure changes see what’s happening to casing pressure If the Casing pressure changes see what’s happening to tubing pressure If the workstring begins to plug there will be a noticeable increase in pump pressure without a corresponding increase in casing pressure. Additionally, there may be a noticeable decrease in flow from the well. Monitor the tubing pressure for stabilization If the tubing pressure continues to rise, stop the pump and close the choke Try, (once or twice) suddenly opening the choke for short durations to free the obstruction from the workstring – if this is unsuccessful, allow the casing pressure to stabilize, begin a volumetric procedure, and make preparations to perforate the workstring
  • 142.
    Well Control DuringWorkovers and Completions 142 Plugging or Plugged Choke Potential Problems Circulating Kill Techniques Evidence of a plugging or plugged choke will initially be an increase in casing pressure, decrease in flow, followed by an increase in tubing pressure. This is a serious problem because the circulating system is now closed and fluid being pumped will be pumped into the producing formation. Corrective actions must be taken rather quickly. STEP 1 Stop the pump and close the choke STEP 2 Try (once or twice) suddenly opening the choke to clear the debris STEP 3 If this proves to be unsuccessful, isolate the choke with valves on the choke manifold, line up to another choke and continue with the kill – bleed any excess pressure that ay have been exerted on the casing After the well is dead, the plugged choke must be cleared. Extreme caution should be exercised as pressure can be trapped in the choke and when relieved, can eject the debris at extreme velocities.
  • 143.
    Well Control DuringWorkovers and Completions 143 Washed-Out Workstring Potential Problems Circulating Kill Techniques A washout in the workstring comes on slowly and may be hard to detect. Decreases in pump pressure, and seemingly, frequent choke adjustments to maintain tubing pressure can be indicators of the problem. Possible remedies: Continue the kill operation and then attempt to locate the washout after the well is dead Shut down the kill operation and locate and pack-off the washout with wireline. If this option is selected, a volumetric procedure must be implemented until circulation can be restored. This procedure can take some time. After the well is dead, the decision can be made as to the need to locate the washout before tripping out.
  • 144.
    Well Control DuringWorkovers and Completions 144 Choke Washout Potential Problems Circulating Kill Techniques Like the washing out workstring, a choke that’s washing out can be, at first, hard to detect. There will be a gradual decrease in circulating pressure necessitating more frequent than normal choke adjustments. Also, if the well is brought of choke and the choke closed, it will not provide a positive seal. Solutions to the problem are easy. If it is suspected that the choke is washing, line up another choke and gradually open the second choke while closing the first choke. Isolate the defective choke with valves on the choke manifold. After the well is dead, repair and pressure test the faulty choke.
  • 145.
    Well Control DuringWorkovers and Completions 145 Potential Problems Circulating Kill Techniques Excessive Surface Pressure Excessive surface pressure can be a relative term. In terms of workovers, excessive surface pressure can be with respect to formation pressure or can be with regard to casing burst pressure. In either case, if excessive casing pressure exists, two options are available: Continue to circulate in hopes that the pressure will decrease Begin bleeding pressure to relieve the excess while risking the possibility of taking more influx There is no clear cut answer to the problem of excessive casing pressure. If it is decided to relieve pressure, the pump rate should be reduced. To accomplish this and maintain a constant BHP, hold the casing constant while reducing the pump rate. Allow the pump pressure to stabilize and record the stabilized pump pressure of the new rate. Begin reducing the annular pressure in small increments. Manipulate the choke to increase the pump pressure to the reduced pump rate pressure as soon as possible.
  • 146.
    Well Control DuringWorkovers and Completions 146 Wells with very low bottom hole pressures require a somewhat more delicate approach to killing, if it’s desired the well be worked over dead. To prevent possible formation damage and pumping excessive quantities of water into a formation, it may be necessary, and wise, to work the well over with only enough hydrostatic placed in the tubing to slightly overbalance the formation pressure. This is accomplished by placing a partial column of fluid on the formation. The volume to pump can be calculated using the following procedure: ( ) D e s i r e d P S I F l u i d W e i g h t F e e t o f F l u i d P P G.0 5 2 × = F e e t o f F l u i d T b g I D B B L×       = 2 1 0 2 9 Control With a Partial Column of Fluid Kicks During Workovers STEP 1 Length of Fluid Column STEP 2 Pumping Volume
  • 147.
    Well Control DuringWorkovers and Completions 147 The “delicacy” which must be employed comes into effect when the fluid is pumped into the well. Lubrication and bleeding (previously discussed) is the best approach. And in this instance, the volume method suffices. Stage the fluid into the hole while periodically bleeding gas and pressure from the tubing through a hand adjustable choke. The pressure to bleed is based on added hydrostatic. Using the data from the previous page the fluid can be staged into the well in six increments, in this case, a BBL at a time. The hydrostatic pressure added per BBL pumped can be determined using the following: 1 0 2 9 0 5 22 T b g I D F l u i d W e i g h t A d d e d H y d r o s t a t i cP P G       × × =. After the fluid is pumped into the well, time should be given for the fluid to fall; 15-20 minutes should be adequate. Following this, pressure from the tubing is bled equal to the hydrostatic pressure added. While this is “technically” correct, it’s somewhat difficult to bleed exactly 76 psi from a well, even with a good gauge, so practicality should come into play. In this case, bleed 70 psi from the tubing and then close the choke. Perform this operation as many times as needed to achieve the desired hydrostatic pressure in the well – in this example, 6 pumping “cycles” would be used. Control With a Partial Column of Fluid Kicks During Workovers After all the fluid is pumped into the well, pressure at the surface should be zero or near zero. Should any residual pressure remain, attempt to bleed this pressure. If it bleeds to zero, the well is dead and can be entered. If surface pressure increases, calculate the volume required to equal this pressure and perform another pumping cycle.
  • 148.
    Well Control DuringWorkovers and Completions 148 At left the diagrams illustrate the “before” and “after” of this procedure. It’s quite possible to have the surface reduced to zero or near zero before the entire volume of kill fluid is pumped. Should this be the case, continue to pump as per the cycles and make sure the complete volume is pumped. After the last cycle is completed (pumping and bleeding) monitor the surface pressure for about 20- 30 minutes to ensure the well is dead. If surface pressure appears, calculate the volume to equal this pressure using the formulas on the previous two pages. Control With a Partial Column of Fluid Kicks During Workovers Kill Fluid
  • 149.
    Well Control DuringWorkovers and Completions 149 Once the well is initially killed, consideration must be given to maintaining the hydrostatic pressure. If the next operation calls for the removal of a string of rods or tubing, the displacement of the “wet” part of the string must be calculated and an equal volume pumped into the well. Once the rods are completely removed, the well should be shut- in and routed to a blooie line where it can be closely monitored for flow. When the rods or tubing are re-run the displaced volume will most likely enter the formation due to the hydrostatic overbalance caused by the rod displacement. Monitor the well closely while running back to bottom and always be prepared to pump additional fluid. If a workstring is to be run in the well, the displacement must be calculated per the calculated kill fluid column length and this volume pumped into the well when the workstring is pulled from the hole. Calculate the displacement for this length Control With a Partial Column of Fluid Kicks During Workovers
  • 150.
    Well Control DuringWorkovers and Completions 150 Stripping is a technique for moving the string through the BOP stack when the well is shut-in under pressure. In most cases, stripping is required to return the workstring to bottom after shutting in on a kick with the pipe is off bottom. Stripping requires a high level of coordination among crew members. There are two annular stripping techniques; Short Term and Long Term. Points of Concern: • Moving the tool joint through the annular • Annular element wear • Redundancy in BOP control system • Excessive surface pressures • Accurately measuring fluids on the surface • Crew coordination • Gas migrating • Manufacturer’s info regarding BOP equipment Factors affecting well pressures when stripping: Compression - fluids are compressed as pipe is lowered. Under-bleeding - not bleeding correct volume equal to steel displacement removed. Influx penetration - pipe penetrating the influx causes the influx to elongate, resulting in additional hydrostatic pressure loss. Gas migration - must be controlled properly. Artificial migration - once pipe has penetrated the influx, additional pipe stripped will “pump” the influx up the hole. Restored overbalance - occurs when last few stands are stripped to bottom and the hole is filled. Kicks During WorkoversStripping
  • 151.
    Well Control DuringWorkovers and Completions 151 Procedure 1. Strip first stand without bleeding fluid to allow casing pressure to increase by a desired 100 – 200 psi “safety margin” 2. Continue to strip bleeding a fluid volume equivalent to closed end displacement of pipe stripped • Lower pipe slowly • Pipe burrs should be removed from tool joints and slip area on pipe • Pipe should be filled from the inside BOP to surface for each stand 3. Monitor casing pressure for gas migration - be prepared for volumetric or long term stripping if indicated 4. Once on bottom, implement a circulating technique to kill the well Applications:  When stripping approximately 20 stands or less  There is no gas migration Kicks During WorkoversShort Term Stripping
  • 152.
    Well Control DuringWorkovers and Completions 152 Since the type of influx is not usually know, it is prudent to plan a stripping procedure around a “worst case” scenario; a gas kick having the potential to migrate. Well fluids can be accurately accounted for by bleeding from the choke into a calibrated trip tank and then bleeding volume from the trip tank into a calibrated stripping tank used to account for the closed end displacement. Fluid accumulation in the trip tank is assumed to be from gas expansion as it migrates and can then be accounted for accurately. The life of the annular preventer can be extended significantly by use of a surge bottle. Kicks During WorkoversStripping
  • 153.
    Well Control DuringWorkovers and Completions 153 Opening Line Closing Line Surge Bottle Manual Choke Calibrated Trip Tank Recommended Equipment Layout for Short Term Stripping Collect and measure volumes for pipe displacement Partially charged accumulator bottle compensates for tool joint passage through the annular
  • 154.
    Well Control DuringWorkovers and Completions 154 Strip and Bleed Worksheet MASP 1366 psi 80 % MASP 1250 psi Closed end Displacement 2.3 bbls/std Safety Factor 200 psi Stand Number SICP (Before Stripping) SICP (After Stripping) Barrels Bled SICP (After Bleeding) 0 400 1 400 716 0.6 600 2 600 1000 2.3 625 3 625 975 2.3 650 4 650 975 2.3 625 5 625 975 2.3 625 6 625 950 2.3 625 7 625 975 2.3 625 8 625 975 2.3 625 9 625 960 2.3 625 10 625 950 2.3 600 11 600 920 2.3 600 12 600 920 2.3 590 13 590 890 2.3 600 14 600 900 2.3 680 15 680 1000 2.3 750 16 750 1100 2.3 800 17 800 1120 2.3 820 18 800 1120 2.3 820 19 820 1140 2.3 820 20 820 1140 2.3 850 21 22 Sample Data Sheet Short Term Stripping Pictured at right is a sample of a stripping data sheet that should be completed with any stripping operation. The benefit of using a document such as this is the ability to monitor fill and pressure trends making much easier to detect the onset of gas migration. Kicks During Workovers
  • 155.
    Well Control DuringWorkovers and Completions 155 Long Term Stripping Kicks During Workovers Long term stripping takes place when gas begins to migrate during a stripping operation. In this case, volumes must be accurately measured to account for pipe displacement as well as the required controlled gas expansion. The equipment requirements are a little different as an additional tank is needed to measure the volume bled for gas expansion. The general procedure combines both stripping and volumetric procedures: Strip in workstring without bleeding so that surface pressure increases by a pre-determined safety factor (100-200 psi) Continue stripping while bleeding off the calculated displacement – monitor gradually increasing surface pressure created by migration After surface pressure has increased by a selected working margin for volumetric procedure begin bleeding the calculated volume while holding surface pressure constant, all the while continue stripping and bleeding the volume for displacement Displacement volume is to be bled into the trip tank and volumes for migration are to be bled into the migration tank
  • 156.
    Well Control DuringWorkovers and Completions 156 Pw = V1 = V2 = Ps = Pchoke1 = Pchoke2 = Pchoke3 = 1. Select a working pressure range to control BHP, Pw. For Example: Pw = 100psi 2. Calculate the hydrostatic pressure per bbl of mud in the upper annulus. 3. Calculate the length of influx when penetrated by BHA, Lp. 4. Calculate the length of influx in open hole, Loh. 5. Calculate the pressure increase due to influx penetration, Ps 6. Calculate the strip and trip tank volumes V1 and V2 7. Calculate Pchoke values. Hydrostatic per bbl = Fluid Gradient (psi/ft) Upper Annular Capacity (bbl/ft) L1 (ft) = Influx Volume (bbls) OH by DC Capacity (bbl/ft) L2 (ft) = Volume of Influx (bbls) Open hole capacity (bbl/ft) Working Pressure range (Pw) Upper Annular Capacity (bbl/ft) V2 (bbls) =V1 (bbls) = Closed End Pipe Disp. Per Stnd. Ps (psi) = (L1 – L2) x (Fluid Gradient) Pchoke1 = Pa + Pw + Ps Pchoke2 = Pchoke1 + Pw (etc.) Pa =
  • 157.
    Well Control DuringWorkovers and Completions 157 Opening Line Closing Line Surge Bottle Manual Choke Calibrated Trip Tank Recommended Equipment Layout for Short-Term Stripping Partially charged accumulator bottle compensates for tool joint passage through annular Collect and measure volumes for pipe displacement Collect and measure volumes for volumetric procedure Calibrated migration tank
  • 158.
    Well Control DuringWorkovers and Completions 158 Kicks During WorkoversStripping Strip first stand closed in to allow casing to increase to Pchoke1. Choke operator to bleed as needed to hold casing pressure constant at Pchoke value. After each stand, drain V1 volume (closed end displacement per stand) from trip tank into stripping tank. Lower pipe slowly Remove burs from tool joints and slip area on pipe Pipe should be filled from the inside BOP to surface for each stand Continue as in Step 2 until a net gain of V2 (volume representing gas migrating) is noted in the trip tank. Then close the choke. Repeat Steps 1 through 3. Once the workstring is back on bottom, kill the well using a circulating method. A similar worksheet can be used to track the performance of the procedure

Editor's Notes

  • #18 Lecture:
  • #19 Lecture:
  • #22 Lecture: Step1 - Prior to selecting “desired value” - set a pressure limit to minimize risk of formation damage or excessive fluid loss Step 2 - If formation drinks, pressure will fall to stabilized value. Use that for “P2” - not theoretical value. Also - consider reducing amount of increase on next cycle. Step 3 - P3 becomes P1 for next cycle
  • #102 Lecture: Bullet 2 Such as when waiting to increase mud weight or when shut down for bad weather Bullet 3: If Maasp a concern - use low end of range (50 psi)
  • #111 Lecture Bullet 3 - Additional circulating time may be required to circulate mud with added safety margin.
  • #116 Lecture: Pt. A = SICP A to B = Kill mud displaced in drillpipe - casing pressure same as in driller's Gas expanding (and lengthening) as it moves uphole Pt B = Kill weight mud starts up annulus From this point on all annulus pressures lower than driller's B to C = Gas continues expanding and lengthening (dashed line) Note annulus pressure lower than driller's (solid line) D to E = Original mud behind influx displaced out until point E Pt E = Kill mud arrives at choke
  • #118 Lecture: Pt. A = SICP A to B = Drop in cp as influx shortens when leaving bha annulus B to D = Gas expanding (and lengthening) as it moves uphole Choke pressure required to balance kick zone pressure increases Choke operator closing to maintain correct DPP At point C - gas length same as when shut-in around bha) Pt. D = Gas arrives at choke Choke operator closes to ensure choke pressure doesn't drop significantly as gas passes across choke D to E - Gas vented from well PHyd of mud column increasing to replace exiting gas Choke operator opens to reduce back pressure to maintain correct DPP Pt. E - Gas out of well Choke press. will stabilize to value determined by original underbalance
  • #119 Lecture: Well circulated to kill weight during this circulation First establish correct ICP Then reduce standpipe pressure as dp displaced to kill wt. (accd to DPP schedule) Little choke manipulation while kill weight pumped down dp Once kill weight starts up annulus, choke is opened to maintain correct FCP Once hole displaced to kill weight, choke pressure to maintain FCP will be zero. In practice, choke wide open and may not be possible to keep standpipe pressure down to FCP
  • #120 Lecture:
  • #121 Lecture: Dip in wait and weight curves due to added Phyd of kill mud Note that in driller's method , maximum pressure always higher