Well Control

Training course

Module 1Introduction to Well Control

Importance of Well ControlProvides a direct threat to the safety of the drilling rig and its personnel.Well control problems are costly in terms of time and money.Environmental DamageIncreased risk when drilling in unexplored areas with unknown pressure regimes.Prevention is always better than a cure.Time is of the essence

Prevention of BlowoutsAlert and well trained crewsKnowledge on causes of kicksKnowledge of warning signsShut-in responsibilitiesEquipmentTrained crews to properly operate equipment

Rules and RegulationsOperators and rig team members must comply with all government regulations.Regulations are in place to ensure protection of workers, natural resources and the environment.Supervisors, rig managers and drillers must be certified in Blowout Prevention and Well Control Training.HSE&UKOA

Rig Team ResponsibilitiesDrillerKick Detection and Well Shut-InSupervising Drill Crew During Well Control OperationsFloorhands, Derrickhands, Shakerhands, and All Crew MembersRemain Alert to Kick Warning SignsReport to Assigned Station Bill During Well Control OperationsMud LoggersReport Indicators of Formation Pressure Increases to Driller and Operations SupervisorMonitor and Record Circulating System During All OperationsEach Member Has an Important Role in Well Control

Rig Team ResponsibilitiesToolpusherEnsure that the Driller and Crew are Properly DeployedRemain on Rig Floor During Start of Tripping OperationsRemain on Rig Floor During Start of Kill OperationsBrief Crews Prior to Crew Change of All OperationsFor Offshore Operations - Inform Captain or OIM of Well Control Operations so that Emergency Marine Procedures can be Initiated ProperlyOperators SupervisorOverall Responsibility for Well ControlEnsure that All Team Members know Their ResponsibilitiesKeep Lines of Communication Open Among all Team MembersBrief all Team Members of Planned OperationsService PersonnelKnow Assigned Duties for Emergency ConditionsEach Member Has an Important Role in Kick Prevention

Your Role in Well ControlData Engineer must be able to recognise the signs of a developing well control situation.Early detection enables the driller to close in the well quickly and minimise the danger.Important to understand theories and procedures as you are expected to stay at you post during a well control situation.You will be expected to check calculations and be pro active in supporting the operation.

Basic Principles

Key TermsHydrostatic pressure ,BHPSurge/Swab PressuresDynamic pressure, BHCPECDPore pressureNormal pressureFracture pressureOverpressureUnderbalanceUnder pressure

Hydrostatic pressure

Hydrostatic pressure is the pressure exerted by the weight of a static column of fluid. It is a function of the height of the column and the fluid density onlyMay be called Bottom hole pressure (BHP) if combined with pressures induced by pipe movement

Surge and Swab PressuresFrictional pressure drops due to pipe movement. May be + or depending on direction of movementMagnitude in static mud depends on.

Wellbore geometry Mud properties Running speed

Circulation Friction Losses1.Mud Properties2.Measured Depth3.Size of the Drill String4.BHA Components5.Nozzle Sizes6.Annular ClearanceCirculation RatePipe MovementPipe RotationSurface EquipmentCuttings WeightTotal Friction Loss

Dynamic pressureBottom Hole Circulating Pressure Hydrostatic + the additional pressure exerted on the bottom of the hole by the movement of the fluid column.The increase in pressure is due to annular friction and the momentum of the mud. Usually expressed in psiMagnitude of BHCP depends on

Annular geometry Mud properties Flow rate Pipe rotation Pipe Movement Cuttings Weight

Effective Circulating Density (ECD)When the BHCP is converted to an equivalent mud weight it is known as the ECDEquivalent Circulating DensityBHCP=TV Depth (ft) x 0.052

Equivalent Mud/Circulating DensityDrillingBHP = Hydrostatic Pressure + APL= BHP TVD 0.052

Equivalent Mud/Circulating DensityDepth:12,100 ftMud Weight:16 ppgAnnular Pressure Loss: 300 psiSwab Pressure: 250 psiSurge Pressure: 400 psiOperationPump OffTrip OutTrip InDrillingHP = 12,100 ft x 0.052 x 16 ppgHP = 10,067 psi= HP TVD 0.052= 10,067 psi 12,100 ft 0.052= 16 ppgBHCP = (12,100 ft x 0.052 x 16 ppg) + 300 psiBHCP = 10,367 psi= BHCP TVD 0.052= 10,367 psi 12,100 ft 0.052= 16.5 ppgBottom Hole PressureEMD/ECDBHP = (12,100 ft x 0.052 x 16 ppg) - 250 psiBHP = 9817 psiBHP = (12,100 ft x 0.052 x 16 ppg) + 400 psiBHP = 10,467 psi= BHP TVD 0.052= 9817 psi 12,100 ft 0.052= 15.6 ppg= BHP TVD 0.052= 10,467 psi 12,100 ft 0.052= 16.6 ppg

Reverse CirculatingBullheading can increase the BHCP upto 10x that of normal circulation due to increased frictional pressure losses from the drillstring.

Always Reduce flow rates when reverse circulating.

Pore pressurePore pressure is the pressure of the fluid contained in the pore spaces of sediments or the rocks. It is also called formation pressure

Normal pressureAlso referred to as Normal Formation Hydrostatic Pressure. If no barriers occur to prevent the free movement of fluids within a formation, then it is reasonable to assume that the pore fluid will be homogeneous through all formations from the surface down. In offshore wells the normal pore fluid is therefore expected to be the local sea water.

Fracture pressureA formation can be made to fracture by the application of fluid pressure to overcome the least line of resistance within the rock structure. Normally fractures will be propagated in direction perpendicular to the least principal stress. Which of these three stresses is the least can be predicted by the fault activity in the area.

Measures Horizontal StressLeak-Off Test

OverpressureSubsurface pressure that is abnormally high, exceeding hydrostatic pressure at a given depth. Abnormally high pore pressure can occur in areas where burial of fluid filled sediments is so rapid that pore fluids cannot escape, so that the pressure of the pore fluids increases as overburden increases. Drilling into overpressured strata can be hazardous because overpressured fluids escape rapidly, so careful preparation is made in areas of known overpressure.

UnderpressureAny pressure which is less than the local normal pressure is deemed to be underpressure.

Commonly Underpressure is caused by depletion due to production.

UnderbalanceUnderbalance is of far more importance than overpressure during drilling operations. This occurs where the pore pressure is greater than the mud pressure. The resulting pressure imbalance provides a driving force which can cause fluids to flow from the formation into the well bore, or for the walls of the well to be pushed into the hole. The result is a fluid influx or stuck pipe.

Pressure Gradients

Pressure Gradient (psi/ft) = Density (ppg) x 0.052Commonly used GradientsPressure Gradient is the rate of change of pressure with depth

Pressure GradientsPressure Gradient = Density x ConstantUseful conversion constants

sg / m to psi/m 1.421sg / ft to psi/ft 0.433ppg / m to psi/ft 0.171ppg / ft to psi/ft 0.052Kg/m3 / m to Kpa/m 0.00981ppg / ft to PPTF 51.952sg / m to bar/m 0.098sg / ft to bar/ft 0.03ppg / m to bar/m 0.012ppg / ft to bar/ft 0.0036

Hydrostatic Pressure FormulaPHYD = MW x FT x 0.052

This can be rearranged to:

EMW = PHYD / (FT x 0.052)

Pressure calculations always use True Vertical Depth and NOT Measured Depth

Hydrostatic Calculation - QuestionWhat is the overbalance at the bottom of a well at 7493 ft TVD, with a MW of 9.5 ppg and a pore pressure of 3592 psi?Give results in EMW ppg, psi/ft and SG

Hydrostatic Calculation - AnswerGiven EMW = PHYD / (FT x 0.052)Then for pore pressureEMW ppg = 3592 / (7493 x 0.052)So pore pressure = 9.22 ppg EMWAs MW = 9.5 ppg the overbalance is 0.28 ppg EMWGiven PPG x FT x 0.052 = PSIThen overbalance in PSI = 0.28 x 7493 x 0.052 = 109 PSIAnd finally, given Pressure Gradient = Density (ppg) x 0.052So 0.28 x 0.052 = 0.0146 psi/ft

Mud Weight and Formation PressureTo minimise the risk of lost circulation.To minimise the risk of differential stickingTo minimise formation damage.To maintain an optimum ROP.Standard drilling practice is to have the mud weight as close as possible to balance with formation pressure. Reasons for this are:

Trip MarginPiston effect of swabbing requires a safety margin between the formation pressure and mud weight. Trip margin is added to the mud weight to ensure swabbing does not create under balance.Plot pressure reduction against running speed. Using Swab/Surge Software.A trip margin of 250 to 300 psi is usual

TRIP MARGINSHP = 9700 psi950010,587990097009300Start pumpsDecelerateAccelerateDecelerateAccelerateSTATICSTEADY SPEEDSTEADY SPEEDSTATICSTEADY CIRCULATIONSTATICSWABSURGEANNULUS FRICTION PRESSURETRIP MARGIN FORMATION PRESSURE = 9137 psi FRACTURE PRESSURE = 10,587 psi LOST CIRCULATION / UNDERGROUND BLOWOUT KICKS / HOLE INSTABILITY PRESSUREBottom Hole Pressure is Affected by Pipe Motion

Kicks and BlowoutsA kick occurs when formation fluid enters the wellbore indicating the well is in a state of imbalance. The drilling margins have been exceededKicks can be controlled at the surface if caught early enough.

Blowouts occur when a kick cannot be controlled at the surface.

Surface blowout occurs if a well cannot be shut in to prevent kicks reaching the surface

Underground blowout. Uncontrolled flow between two formations.One is kicking and one is loosing.

Barrier DefinitionsAny system that can be used to contain pressure and well fluids within the well, wellhead and christmas tree.

Barriers may be active or latent

Active barriers are already in a condition to contain pressure and well fluids

Latent barriers are not normally in a condition which can contain pressure and well fluids. These can be come active with some sort of external intervention.

BarriersACTIVEConditioned mud/brineWellhead housingTubing/CasingWireline plugsRTTS packerClosed annulus valvesLubricator stuffing boxClosed tree valvesClosed BOP

LATENTOpen tree valvesOpen BOPSafety valveOpen wireline BOPs

Well Control BarriersTwo well control barriers need to be in place at all stages of the well

BarrierDefinitionObjectivePrimaryFirst Line of DefenceControl kicks with hydrostatic pressure only.(Normal drilling)Drill to TD without a well control eventSecondarySecond Line of DefenceControl kicks with hydrostatic pressure assisted by BOPsSafely kill the kick without the loss of circulationTertiaryThird Line of DefenceAn underground blowoutAvoid a surface blowout. Regain primary well control

Causes of Kicks Improper hole fill on trips Drilling into known pressure zones with mud weight to low Drilling into unexpected abnormally pressured formations Loss of circulation. Fluid level not rate of loss is critical in well control Swabbing, rapid pipe movement, balled bit Overpressured shallow gas sands High ROPs in gas bearing formations, control ROP. Loss of hydrostatic during or after cementing operations Incomplete removal of formation fluids from the wellbore or BOP stack during testing or workover operations Post perforation kick. Weighting up brine may cause bigger kick as lighter oil migrates reducing the hydrostatic. Well is overbalanced but still kicks.Most CommonLeast Common

Warning Signs of KicksDrilling Break. Always flow check.Increase in flow returnsPit gainIncorrect trip volumes. Pressure may prevent mud draining from the string.Decrease in SPP or rise in SPMIncreasing gas values. CG , BGWell flows with the pump off, Ballooning , Loss of ECD, Charged fractures.Change in mud properties. > Salinity may > viscosity of mud > ECDIncreasing mud temperatureCavingsCutback in DxC or shale densityPWDGas cut mud expanding. 1200m bubble point.Pinched bit, undergauge hole Hookload/WOB variation, buoyancy

Kick TypesTwo types of Kick exist:Underbalance Kick The formation pressure increases to higher than the hydrostaticInduced Kick Hydrostatic decreases to below formation pressure.

KicksMost occur during trips.

Legal requirement to monitor all trips.

Most critical time is first 10 stands.

Gas Migration

Boyles Law - Open well with water base mud13,410 ft16.5 ppg1 bblP1 = HP = 11,505 psi6705 ftV2 =11,505 psi x 1 bbl5752V2 =2 bblsP2 = HP = 5752 psiV2 =11,505 psi x 1 bbl14 psiV2 =821 bbls2 bbls821 bbls EnCana Corporation

Unload PointGas Behavior - Water Base Mud and Open Wellbore40 bbls20 bbls10 bblsNormally the Drillershould be able todetect the expandinggas with pit level andflow monitoringequipment.UNLOAD POINT!Length of MudLength of FreeRising GasLength of Mud = Length of GasUnload Depth = Length of Gas Kick x TVD EnCana Corporation

Unload PointGas Behavior - Water Base Mud and Open WellboreNormally the Drillershould be able todetect the expandinggas with pit level andflow monitoringequipment.UNLOAD POINT!Length of MudLength of FreeRising GasLength of Mud = Length of GasUnload Depth = 375 ft x 12,100 ftUnload Depth = 2130 ft EnCana Corporation40 bbls20 bbls10 bbls

Unload PointGas Behavior - Oil Base Mud and Open Wellbore10 bblsThe real danger is when the bubble point depth and the unload condition depth are equal.This condition is extremely hazardous since violentunloading of the well can occurwith no warning to the Driller.WELL SUDDENLY UNLOADS!Bubble Point DepthLiquid Gas in SolutionBreaks OutCritical InfluxVolume=0.25 x (Bubble Point Depth)2 x Annular CapacityTotal Vertical DepthCritical Influx Volume is the initial kick volume that will unload the mud from the bubble point depth to the surface.. Bubble point pressures range from 1500 - 5000 psi depending on the type of OBM and wellbore conditions. Bubble Point Depth = Bubble Point Pressure MW 0.052 EnCana Corporation10 bbls10 bbls

Unload PointGas Behavior - Oil Base Mud and Open WellboreWELL SUDDENLY UNLOADS!Bubble Point DepthLiquid Gas in SolutionBreaks OutBubble point pressures range from 1500 - 5000 psi depending on the type of OBM and wellbore conditions. Critical InfluxVolume=0.25 x (3496 ft)2 x 0.0623 bbl/ft12,100 ft.Bubble point depth = 2000 psi 11 ppg 0.052 = 3496 ft.=15.7 bblsThe real danger is when the bubble point depth and the unload condition depth are equal.This condition is extremely hazardous since violentunloading of the well can occurwith no warning to the Driller.Critical Influx Volume is the initial kick volume that will unload the mud from the bubble point depth to the surface.. EnCana Corporation10 bbls10 bbls10 bbls

Explosive UnloadingA small isolated bubble of gas is swabbed in (unnoticed), circulated to the surface (no expansion or further kick indications), where it expands and is also accelerated upwards by trailing bubbles of gas expanding underneath segments of mud.

The net effect is an instantaneous (a couple of seconds at most) very high gas rate that could result in a flash fire if not effectively dealt with.

Type 1 EnCana Corporation

Explosive UnloadingType 2A slow continuous flow from a tight high-pressured formation enters the wellbore over a long period of time undetected. The net effect of this influx is that there is a column of gas cut mud from the bit right up to the rotary table.

The net effect is a "domino" unloading of the well, whereby a large part of the annulus is unloaded of mud. As well as enough gas at surface to cause a flash fire, the well will probably become much further underbalanced and the "tight" zone will flow faster and perhaps a second (permeable) zone will become underbalanced and will also start to flow.

EnCana Corporation

Practices to Prevent UnloadingTrippingLimit tripping speeds to minimize swab / surgeMonitor hole fill in and out of the hole DrillingAdjust detection equipment alarm as low as possibleCirculate BU at any increase in gas levelsNo more than one connection in holeFlow check all drilling breaksBe alert to activities that allow undetectable influx volumesSwabbing when picking up off bottomDrilling through gas sandsMud transfers, spills and leaks, pulling wet pipe, partial lossesCirculate bottoms up through open choke with BOP closedEspecially the last 1500 - 3000 ft. of bottoms up EnCana Corporation

Gas Through Cement Kicks EnCana Corporation

Gas Through Cement KicksABInitially after cement placement, slurrybehaves as a fluid and transmitsfull hydrostatic pressure.Static gel strength development begins;meanwhile fluid is lost from cement slurryto permeable formations causingvolume reductions. EnCana Corporation

Gas Through Cement KicksCement slurry static gel strength reducestransmission of hydrostatic pressure simultaneously as volume losses occur. Together these factors cause loss of overbalance pressure, permitting gas to enter and percolate through the unset cement.CDGas percolation leads to formation of a discrete gas channel through the unsetcement. Gas may channel to a lower pressurezone or back to surface. Once formed,these channels will remain in the cement. EnCana Corporation

End of Module Summary -Key TermsOverpressurePore pressureOverburdenHydrostatic pressureFracture pressureNormal pressureUnderbalanceUnder pressureHydrocarbon ReservoirsAquifiersDisequilibrium CompactionCharged SandsAquathermal PressuringClay DiagenesisTectonicsDiapirism

Condition Mud Prior to TripsCheck the mud priorto trips!!Mud Engineer and Derrickhand/ShakerhandShould not be more than 0.1 ppg difference weight in and out

Mud properties out should be within prescribed limits

If returning mud/fluid is gas cut - circulate additional bottoms up and/or condition mud prior to POOH EnCana Corporation

Slugging ConsiderationsHave a standard procedure for slugging the pipe Know the pit gain caused by slug falling. Dont chase the slug with extra volume Be aware of the hydrostatic increase due to accumulated slugging.Know how to use your slugging formulas EnCana Corporation

Slugging ConsiderationsMud Density: 16 ppgSlug Density: 18 ppgSlug Volume: 40 bblsDP Cap:0.017220 bbl/ftSlug Length:2322 ftPit Gain =(18 ppg - 16 ppg)16 ppg40 bbls xPit Gain = 5.0 bbls(18 ppg - 16 ppg)16 ppg2322 ft xDepth SlugFalls=Depth SlugFalls= 290 ft EnCana Corporation

Establish Baseline CriteriaMeasure SPRs as high as 5 bbl/min rotating and static. Record PWD readings.Establish baseline ECDs while rotating and reciprocating the drill string. Record PWD readings.Record PWD readings from reciprocating the drill string with the pump off.Run hydraulics for swab and surge pressure correlation and effects of mud compressibility.Record drain down volumes and pit changes when degasser and centrifuges are started.Establish flow on connection footprint following drillout.

Baseline ConditionsA baseline well condition for mud compressibility will be established in cased hole for a number of circulating and rotating conditions just before drilling outBaseline tests will include PWD responses. All changes in the well can be referenced to this baseline.

Acceptable FlowchecksThe Flow check should have monitored the well for a minimum of 15 minutes. Always rotate pipe slowly) when conducting a flow check - this will help prevent sticking and will break up the gels. Bleed off any drill pipe pressure before conducting a flow check.A decreasing trend of flow can be identified from a plot of Volume Vs Time.The rate and volume of flow follows the trend seen at previous flow checks.

Flow Checks During TripsIt is a good practice to check the well for flow during trips.The best times for slow checks are:Before pulling off bottomAfter pulling the first few (5) standsWhen there is a discrepancy in the trip recordHalf way up the open holeAt the shoePrior to pulling the BHA into the BOP stackWhen out of the holeWhen in doubt EnCana Corporation

Gas Solubility in Oil Based Mud EnCana CorporationA gas influx in an oil based mud will not behave inthe same manner as a gas influx in a water based mud. This is caused by the ability of gas to dissolve in anoil based mud.

This has consequences for both:

The size of an influx when detected

And the way in which an influx will act

These areas will be examined in this presentation

Gas Solubility in Oil Based Mud EnCana CorporationConclusions - Whilst Circulating Bottoms UpIn an OBM there will be very little increase in pit gain until the gas breaks out of the mud. This can lead to a very rapid pit gainIn a WBM there will be a continual increase in pit gain as the influx is circulated out. The speed of increase will get bigger as the circulation continuesThe influx in an OBM will arrive at the surface later than it would in a WBMAs mud is lost a secondary kick may start

Gas Solubility in Oil Based Mud EnCana CorporationFlowcheck in a Deep Well

Gas Solubility in Oil Based Mud EnCana CorporationRiser Unloading

Hydrates EnCana Corporation

Hydrates EnCana CorporationInhibition with methanol

Gas Solubility in Oil Based Mud EnCana CorporationCirculating out a Drilled Kick From 6000 ft WellComparison with a 50:50 oil water emulsion mud.An emulsion mud acts more like an OBM than a WBM unless free gas is presentGas dissolves preferentially in the oil until it becomes saturatedAn emulsion mud will reach saturation before an OBM, once mud is saturated free gas will form

Gas Solubility in Oil Based Mud EnCana CorporationConclusions - Influx BehaviorDissolved gas does not migrateNegative flow check does not mean no influxInflux in OBM will take longer to arrive at surfaceGas break out of OBM can be rapid

Hole Fill RequirementsProper hole filling procedures prevents the loss of hydrostatic pressure as pipe is tripped in or out of the well=Mud Gradient x (Pipe Displacement + Pipe Capacity)(Annular Capacity + Pipe Capacity)Hydrostatic Lossper ft of PipePulledDryPipeWetPipe=0.02 psi/ft or 1.91 psi/std=0.832 psi/ft x (0.00919 bbl/ft + 0.01722 bbl/ft )(0.364 bbl/ft + 0.01722 bbl/ft )=0.058 psi/ft or 5.5 psi/std EnCana Corporation

Hole Fill RequirementsProper hole filling procedures prevents the loss of hydrostatic pressure as pipe is tripped in or out of the well Proper Hole Fill Procedure Requires: Determine the maximum acceptable loss of hydrostatic between fills Use trip sheets and accurately measure mud volumes Proper manifolding of valves and equipment Responsible monitoring and communicating results EnCana Corporation

Kick Detection1. Stop the rotary2. Position the top drive for access/installation/operation of string safety valves.3. Stop the pump.4. Align the flowline to the trip tank.5. Engage the hole fill pump.6. Monitor the trip tank for gain or loss 10 - 15 minutes.Well Flow Check Procedure While DrillingIf the Well Flows:

Shut In ImmediatelyIf Well Flow is Very Slight:

Shut-in the well on the annular.

If on bottom: Circulate bottoms upthrough the choke for verificationthat no influx has occurred.

If off bottom: Strip to bottom and circulate bottoms-up.If No Well Flow:

Resume operations andcontinue to monitor kickwarning signs.Know the flow back volumesfor your rigs surface lines.Once the pumps are off.,ECD is lost. Flow may be strong. Be readyto shut-in. EnCana Corporation

OverbalanceOverbalance controls formation pressureMonitor and record mud/fluid densities in and out on a continuous basisOverbalance is reduced when tripping out the hole because of swab pressureA 250-300 psi trip margin should be maintained as a minimumMud densities must be increased when drilling abnormally pressured zonesKey Prevention FactorKey Points EnCana Corporation

Kick DetectionEarly kick detection minimizes the severity of the kickTrend monitoring is of utmost importance to early kick detectionThe rig team must communicate warning signs to appropriate supervisors to ensure kick preventionDetection systems such as flow show devices and pit level indicators must be calibrated regularly and maintained in proper working orderKey Prevention FactorKey Points EnCana Corporation

Hole ProblemsHole problems can indicate loss of well controlLoss of circulation loss of hydrostaticTorque and drag increasesStuck pipe working pipe during well control may induce loss of circulationGas cut mud or contamination by H2S or CO2 can lead to loss of well controlKey Prevention FactorKey Points EnCana Corporation

OBM Rheology Effects EnCana Corporation

Kick ToleranceThe maximum volume of gas (based on a given pore pressure) that can be circulated from thewell without causing excessive mud loss at the casing shoe.Calculate the Kick Tolerance

(Assume 0.5 ppg Kick Intensity)

1. Calculate the MASP for shoe Leak-Off

2. Calculate the maximum allowable underbalance.

3. Calculate the maximum length of gas beneath shoe (to cause SICP = MASP).

4. Calculate this volume at shut-in, V1 shut-in

5. Calculate this volume at the shoe, V shoe

6. Calculate what V shoe would be at shut-in V2 shut-in. (Use Boyles Law)

7. Report the Kick Tolerance as the lessor of V1 shut-in and V2 shut-in.

Kick Tolerance - worked exampleCalculate the Kick Tolerance

1. Calculate the MASP for shoe Leak-Off

MASP = (LOT EMW - MW) x SHOE TVD x 0.052 MASP = (18 ppg - 16 ppg ) x 12,075 ft x 0.052) = 1256 psi

2. Calculate the maximum allowable underbalance.

MAX ALLOWABLE UNDERBALANCE= MASP TVD 0.052 = 1256 psi 14,345 ft 0.052 = 1.68 ppg

3. Calculate the hydrostatic pressure loss due to influx including the kick intensity.

HYD PRESS LOSS = MASP - (KICK INTENSITY x TVD x 0.052 = 1256 ppg - (0.5 ppg x 14,345 ft x 0.052) = 883 psi

4. Calculate the maximum length of gas beneath shoe (to cause SICP = MASP).

MAX GAS LENGTHshoe = HP LOSS (GRmud - GRgas) = 883 psi (0.832 psi/ft - 0.1 psi/ft) = 1206 ft

Gas Gradient = 0.1 psi/ftMud Density = 16 ppgMud Gradient = 0.832 psi/ft8.5 holeTD @ 14,345 ft9 5/8 Shoe @ 12,075 TVDLOT = 18 ppg (0.936 psi/ft)5 Drill Pipe510 of 6.5 Drill CollarsOH DP ANN VOL= 0.0459 bbl/ftOH DC ANN VOL= 0.0291 bbl/ft1256

Kick Tolerance - worked exampleCalculate the Kick Tolerance

5. Calculate this volume at shut-in, V1 shut-in

If the gas length is equal to or less than than the drill collar length then: V1 shut-in = MAX GAS LENGTH x OH DC ANN VOL If the gas length is greater than the drill collar length then: V1 shut-in =

LDC x OH DC ANN VOL + ((MAX GAS LENGTH - LDC ) x OH DP ANN VOL) = (510 ft x 0.0291 bbl/ft) + ((1206 - 510) x 0.0459 bbl/ft) = 46.79 bbls

6. Calculate this volume at the shoe, V shoe

V shoe = MAX GAS LENGTH x OH DP ANN VOL = 1206 ft x 0.0459 bbl/ft = 55.36 bbls

7. Using Boyles Law calculate what V shoe would be at shut-in V2 shut-in. (Use Boyles Law)

V2 shut-in. = V shoe x LOPSHOE HP @TVDBOTTOM = 55.36 bbls x 11,302 psi 11,960 psi = 52.3 bbls

8. Report the Kick Tolerance as the lessor of V1 shut-in and V2 shut-in. 52.3 bbls

Gas Gradient = 0.1 psi/ftMud Density = 16 ppgMud Gradient = 0.832 psi/ft8.5 holeTD @ 14,345 ft9 5/8 Shoe @ 12,075 TVDLOT = 18 ppg (0.936 psi/ft)5 Drill Pipe510 of 6.5 Drill CollarsOH DP ANN VOL= 0.0459 bbl/ftOH DC ANN VOL= 0.0291 bbl/ft1256

Kick Tolerance - Graphical Analysis EnCana CorporationMAX UNDERBALANCE (ppg)(Vk)max170.15 bbls201030405060Max AllowableUnderbalance= 1.68 ppg00.40.81.22.0(Vk)max274.38 bblsMax kick size that can be safely circulatedto the shoe without exceeding MASP = 52.3 bblsKick Size bbls1.60.20.61.01.41.870

Kick Tolerant RegionKick Tolerance - Graphical AnalysisKick Size (bbls) EnCana CorporationMAX UNDERBALANCE (ppg)(Vk)max170.14 bbls201030405060Max AllowableUnderbalance= 1.68 ppg00.210052.3 bblsKick Tolerant Region0.5 ppg Kick IntensityMax kick size that can be safely circulatedto the shoe without exceeding MASP = 52.3 bbls700.40.60.81.01.21.81.61.4

Choke Line Friction PressureThe choke line friction pressure must be removed when circulating kicks from the well.

Remember!!

Choke line friction pressure is the amount of pressureloss when circulating at slow pump rates throughthe choke line with the BOP closed. When the well is shut-in and circulation is throughthe choke, the choke line is applying additional unwanted pressure to the formation. The amount of choke line back pressure can be determined by knowing the slow pump pressure for the system.

Choke Line Friction Pressure Should be Measured:

After a round trip;After any mud weight change;After any significant change in mud properties or type;Each time the choke and kill lines are flushed. EnCana Corporation

Slow Pump PressuresThe slow pump pressure is used a s a reference pressure when circulating kicks from the well.

Remember!!

Circulating pressure is the sum of all the friction pressures in the circulating system or flow path. When the well is shut-in and circulation is throughthe choke, the choke is used to apply controllingpressure to the formation. The amount of choke back pressure can be determined by knowing theslow pump pressure for the system.

Slow Pump Pressure Should be Measured:

Each tour;After any mud weight change;Every 500 ft of new hole drilled;After each BHA change or trip;After any significant change in mud properties or type. EnCana Corporation

Slow Pump PressuresSlow circulating rates should be pre-determined and should be based on the following;Rig barite mixing capabilityECD on open holeReaction time for choke operatorPump & pressure limitationsCapacity of mud gas separatorChoke line friction (floaters)Convenience and ease of usePipe depth should be near bottom (within 50 ft)Procedure:Position stringRotate slowlyReduce pump speed to desired slow circulating rateAllow drill pipe pressure to stabilize and the driller should record circulating rate and pump pressure from the drillers console. Lead floorhand or AD should record circulating rate and drill pipe pressure reading from the choke panel and standpipe. EnCana Corporation

Drilling ProgramsCasing requirementsExpected formation pressuresExpected formation changes H2S potentialIdentification of loss zonesKick toleranceStick diagram for posting in dog house as per regulations

What information should they contain

OBM Density Effects EnCana Corporation

Circulation SystemEstimating Pump PressuresNew Pump PressureNew Pump Pressure()New Mud DensityOld Mud Density= Old Pump Pressure x EnCana Corporation

Bullheading - Drilling WellboresKey Points Used to pump influx back into formation Depends upon:Amount of open holeInflux location compared to permeable zone When to BullheadLarge volume of influxExcess surface pressureH2SPipe off bottom - stripping not feasibleNo pipe in holeSurface pressures need to be reduced EnCana Corporation

Bullheading - Drilling WellboresImportant ConsiderationsCharacteristics / condition of open holeBOPE & casing rating (wear?)Type of influx & relative permeability of the formationQuality of the filter cakeConsequence of fracturing open holeInflux position EnCana Corporation