2 ON JANUARY 10, 1901, THE LUCAS GUSHER BLEW IN AT SPINDLETOP, NEAR BEAUMONT, TEXAS. The Hamill Brothers Had Started The Hole 3 Months Earlier ForCaptain A. F. Lucas, And 6-inch Casing Had Been Set At 880 FeetAfter Minor Indications Of oil In The Next 7 Days, The Well HadBeen Deepened By 140 Feet To , 1020 Feet, A Much Faster RateThan Before. Running In A New Bit, The Crew Had 700 Feet Of4-inch Drill Pipe In The Hole When The Well Started To Unload;That Is, Mud Started Flowing From The Casing. After Several HardKicks, Well Pressure Blew The Drill Pipe Out Of The Hole.Soon A Stream Of Oil And Gas Was Spraying More Than 100 FeetIn To The Air, Producing By Some Estimates75,000 To 100,000 Barrels Of Oil Per Day.Most Of The Signs Of A Developing Blowout Were ObservableOn The Lucas Well:Shows Of Oil And Gas In The MudDrilling Break (Faster Drilling)Flow Of Mud From The WellPit Gain
3 Hydrostatic pressurehydrostatic pressure is defined as the pressure exerted by a fluid column. The magnitude of the pressure depends only on the density of the fluid and the vertical height of the column. The size and shape of the fluid column do not affect the magnitude of this pressurepressure = fluid density x vertical height of the fluid column
4 HP = Hydrostatic Pressure (Ph)(psi or Pounds Per Square Inch) HP = C x MW x TVDwhere:HP = Hydrostatic Pressure (Ph)(psi or Pounds Per Square Inch)MW = Fluid Density, or Mud Weight (1bs/gal or ppg or Pounds Per Gallon)TVD = True Vertical Depth of the Fluid Column (Feet or Ft)C = 0.052: Conversion factor used to convert density to pressure gradient (psi /ft Per 1bs/gal) is derived as follow:A cubic foot contains 7.48 US gallonsA fluid weighing 1 ppg is therefore equivalent to 7.48 lbs /cu.ftThe pressure exerted by one foot of the fluid over the base would be :7.48 lbs / 144 sq.ins = psiExample: Calculating hydrostatic pressurethe hydrostatic pressure exerted by a 10-foot column of fluid with a density of 10 ppg is:hydrostatic pressure = x density (10 ppg) x height (10 ft) = 5.2 psi12”12”12”
5 PRESSURE GRADIENTPressure gradient is defined as the pressure increment per foot of depth . Water, for example , will increase the hydrostatic pressure by psi for every foot - of hole.PG = C x MWPG = Pressure Gradient psi / ftMW = Fluid Density lbs/galC = conversion constant psi /ft / lbs/gal
6 OVER BURDEN PRESSUREOverburden Pressure is the Result Of The Combined Weight Of The Formation Matrix (Rock) And The Fluids (Water, Oil, And Gas) in the Pore Spaces Overlying The Formation Of Interest. The Average Value Of Overburden Pressure Gradient (OPG) is Often Assumed To be1.0 psi/ft .Actually, it me be as high as 1.35 psi/ft in some areas , and lower than 1.0 psi/ft in others.
7 PORE PRESSUREThe magnitude of the pressure in the pores of a formation , known as the formation pore pressure (or simply formation pressure ),Formation Pressures Vary Greatly, And Depend Upon Reservoir Characteristics. They Can Be Divided In To Three Categories:Normal Formation PressureSubnormal Formation PressureAbnormal Formation Pressure
8 NORMAL FORMATION PRESSURE Normal Formation Pressure Is Equal To The Hydrostatic Pressure Of Water Extending From The Surface To The Subsurface Formation Of Interest.this is because sedmentary beds were originally deposited in a water environment. Thus the normal pressure gradient in any area will be equal to the hydrostatic pressure gradiant of the water that occupies the pore space of the formations in that area.HENCE,0.433 PSI/FT < NORMAL FORMATION PRESSURE GRADIENT < PSI / ft
9 ABNORMAL FORMATION PRESSURE ABNORMAL FORMATION PRESSURE IS ANY FORMATION PRESSURE GREATER THAN THE CORRESPONDING NORMAL FORMATION PRESSURE.Formation pressure gradient > x 8.90 psi / ft > psi / ft
10 Causes of abnormally high formation pressure are: Depositional causesDiagenesisPiezometric surfaceTectonic causesStructural causes
11 DEPOSITIONAL CAUSES. INSUFFICIENT COMPACTION - as sediments are deposited, the pore pressure is normal as pore fluid is in contact with the overlaying seawater. as sedimentation continues, older sediments compact (due to increase in overburden pressure) and fluids are expelled from the older sediments. as long as equilibrium exists between rate of compaction and rate of fluid expulsion from sediments, and the expelled water can escape to surface or in other porous formation, pore pressure remains normal (hydrostatic). in some cases, rate of compaction is more than the rate of pore fluid expulsion.
12 DIAGENESIS diagenesis is the process whereby the chemical nature of the sediment is altered due to increasing pressure and temperature as the sediment is buried deeper. gypsum converts to anhydrite plus free water. the volume of water released is approximately 40 % of the volume of gypsum. if the water cannot escape then overpressures will be generated.
13 PIEZOMETRIC SURFACEA PIZOMETIC SURFACE IS AN IMAGINARY LEVEL TO WHICH THE GROUND WATER WILL RISE IN A WELL. THE WATER TABLE IN AN AREA IS AN EXAMPLE OF A PIEZOMETRIC SURFACE. IF THE SURFACE ELEVATION IS HIGHER THAN PIEZOMETRIC SURFACE LEVEL, SUBNORMAL PORE PRESSURES ARE MOST OFTEN ENCOUNTERED (SEE FIGURE BELOW).
14 Structural causesAny structure such as an anticline or dome may have abnormally high pressures above the oil- water or gas –water contact in the oil or gas zone because hydrocarbons are less dense than water. If the anticline or dome is large ,abnormal pressures may be quite high
15 TECTONIC CAUSES TECTONIC FORCES MAY CAUSE ABNORMAL PRESSURES DUE TO FOLDING AND FAULTING DUE TO SALT DIAPIRISM. DIAPIRISM IS THE UPWARD MOVEMENT OF LOW DENSITY PLASTIC FORMATIONS (SEE FIGURE BELOW).
16 Subnormal formation pressure Subnormal Formation Pressure Is Any Formation Pressure Less Than the Corresponding Normal Pressure.Formation PressureGradient < X 8.33 ppg < Psi / ft
18 DEPLETED RESERVOIRSProducing Large Volumes Of Reservoir Fluids Causes A Decline In Pore Pressure As The Fluids In The Reservoir Expand To Fill The Void Spaces Created Because Of Production.ExampleThe original reservoir formation pressure in oil field “A” was 3250 psi at a depth of 7000 ft vertical depth. This equates to a formation pressure gradient of psi , which is the normal hydrostatic gradient . After producing many years from the field , the reservoir formation pressure dropped to approximately 2525 psi .this gives a subnormal pressure gradient of 0.36 psi/ft .
19 PIEZOMETRIC SURFACEA PIZOMETIC SURFACE IS AN IMAGINARY LEVEL TO WHICH THE GROUND WATER WILL RISE IN A WELL. THE WATER TABLE IN AN AREA IS AN EXAMPLE OF A PIEZOMETRIC SURFACE. IF THE SURFACE ELEVATION IS HIGHER THAN PIEZOMETRIC SURFACE LEVEL, SUBNORMAL PORE PRESSURES ARE MOST OFTEN ENCOUNTERED (SEE FIGURE BELOW).
20 TECTONIC COMPRESSIONDuring A Lateral Compression Process Acting On Sedimentary Beds, Up warping Of Upper Beds And Down warping Of Lower Beds May Occur. The Intermediate Beds Must Expand To Fill The Voids Left By This Process Causing Subnormal Pressures, Due To The Increase In Pore Volume (See Figure Below).
21 FRACTURE PRESSUREFracture Pressure is the amount of pressure it takes to permanently deform ( fail or split ) the rock structure of a formation . Overcoming formation pressure is usually not sufficient to cause fracturing .
23 leak-off testthis test is usually made just after drilling 10 to 30 feet through a casing shoe . It measures the maximum mud weight or surface pressure the formation at the casing shoe will withstand before fluid is forced into it. The well is shut in by closing the blowout preventer. Pressure is increased by pumping slowly into the well. At a certain point pressure will being to drop off , indicating that the exposed formation is taking on significant amounts of mud . The fracture is the total of the surface pumping pressure and the hydrostaic pressure at the casing shoe
25 Maximum Allowable Annulus Surface Pressure this is the maximum pressure that can be tolerated in theannulus , without risking a possible formation rupture ator below the casing shoe .MAASP = Pressure required to fracture the formationmines hydrostatic pressure created by thecolumn of mud in the annulus .( Formation fracture gradient – MW gradient ) * Depth of CSGFracture gradient = 0.8 psi/ftMW gradient = 0.52 psi/ftDepth of CSG = 8200 ftMAASP = ( 0.8 – 0.52 ) * 8200MAASP = 2290 psi
26 well bore and the ‘U’ Tube A U- tube is a combination of two vertical tubes, column A and B , connected at the bottom such that the pressure at the bottom of each tube is the sameABPA = P B
27 PA = P B U Tube in a wellbore A B A well bore is similar to a U- tube . The fluid column inside the drill string can be considered column A, and the fluid column inside the drill annulus can be considered column B.pumpchokePA = P BAB
28 home workWhat will be the gain in the pits , and how far will the slug fall if the mud weight is 10 ppg ,the pipe’s capacity is bbl/ft ?The volume of the slug is 30 bbls and weighs 11 ppg .
34 The well bore in dynamic condition – drill string side Pump pressureMud PumpCHOKEBHP= Hydrostatic pressure inside drillstring +pump pressure – pressure loss inside drilling and bitFriction pressure loss in the drillstring acting against pump pressureFORMATION ORESSUREThe well bore in dynamic condition – drill string side
35 Pump pressreMud PumpBHP= Hydrostatic pressure inside Annulus +surface casing pressure +pressure loss inside annulusCHOKESICPsurface casing pressureFriction pressure loss in the annulus acting downwardsFORMATION ORESSUREThe well bore in dynamic condition – annulus side
36 Influx Gradient Evaluation SIDPP + HPdp = SICP + ( MG ×H ) + ( IG ×h )SIDPP + ( MG × H ) + ( MG × h ) =SICP + ( MG×H ) + ( IG × h )( MG × H ) + ( MG × h ) - ( MG×H ) - ( IG × h ) = SICP-SIDPPIG =MG -GAS = TO 0.15OIL&GAS = F/ to/ 0.4WATER & SALT WATERABOVE 0.4SIDPPSICPHH=hh
37 KickA kick is the undesired entry of formation fluids into the well boreBlowoutA blowout is the uncontrolled flow of gas , oil , or other formation fluidsSometimes ,formation fluids from a reservoir formation at high pressure can flow into another underground formation that is at a lower pressure and different depth . This kind of uncontrolled flow is an underground blowout and can be very difficult to control.
38 Kick causes Not keeping the hole full Swabbing Overpressure ( abnormal pressure ) formationsLost circulationGas/oil/water cut mud
39 1- Not keeping the hole full during tripping As the drill string comes out of the well the level of drilling fluid in the annulus drops by a volume equal to the volume of drill string removed. If the fluid level is allowed to drop too far , the hydrostatic pressure on the formation is reduced below formation pressure , which allows formation fluids to enter the well bore.Note that the majority of all kicks worldwide occur during tripping operation
40 Casing capacity = 0.0729 bls/ft Metal displacement = bls/ftAnnular volume bls/ftPipe capacity = bls /ftMud gradient = psi / ft1 stand = 94 ftBottom hole pressure (BHP) will be reduced by pulling wet pipe and NOT filling the hole this allows the mud level to drop therefore reducing the hydrostatic pressureHow many stands would have to be pulled wet to remove a 50 psi overbalance and allow the well to flow ?
43 2- swabbingSwabbing occur when the drill string is pulled from the well , producing a temporary bottom hole pressure reduction . This can lead to an under balanced condition , allowing formation fluids to enter the well bore below the drill stringBalled-up bottom hole assemblyPulling pipe too fastPoor drilling fluid propertiesLarge OD tools
44 3- Abnormal pressure reservoir 4- Lost circulationCauses of lost circulationHigh density of drilling fluidGoing into hole too fast (surging)Pressure due to annular circulation friction
45 5- cutting of drilling fluid with oil , gas , or water When the bit penetrates a porous formation the fluids contained in the formation (gas, oil , or water ) escape and mix with the drilling fluid ,Cutting drilling fluid (contaminating with the low-density formation fluid ) reduce the density of the fluid in the annulus and causes a subsequent loss of hydrostatic pressure.
47 Primary Kick Indicators Increase in return flow rateIncrease in pit volumeInsufficient hole fill during trippingPositive flow check
48 secondary Kick Indicators Drilling breakDecrease in circulating pressure with a corresponding increase in circulating rateIncrease in gas cutting, oil cutting , or chlorides
49 Early warning signs( home work) Increase in background, connection, and trip gasIncrease in the chlorides content of the mudChanges in the size and shape of cuttingsUnaccounted –for fluid loss while trippingIncreasing fill on bottom after a tripIncrease in flow line temperatureIncrease in rotary torqueIncrease tight hole on connectionDecrease in D-exponentMost of these signs are related to the indication of a transition zone prior to drilling into an abnormal pressure formation
50 10PPG 0 0 2600 5200 10PPG BALANCED STATIC CONDITION BALANCED STATIC CONDITIONFigure shows a balanced U-tube situation with fluid of the same density in the annulus and drill pipe sides.10PPG10PPG26005200Depth = ftShoe depth = 5000 ftMud wt = 10 ppg
53 10PPG بررسي حالتي كه وزن گل دا ليز از وزن گل درون لوله ها كمـــتر اسـت و گردش گل با سرعت زمانحفاري همراه با پس فشار برقرا راست .SIDPP= 520PSISPL= PSIAPL= PSIFP = PSIBHP= 5980 PSI10PPG10PPG455059805PPG
54 10PPG بررسي حالتي كه وزن گل دا ليز از وزن گل درون لوله ها كمـــتر است و گردش گل با سرعت آرامهمراه با پس فشار برقرا راست .SIDPP= 520PSISPL= PSIAPL= PSIFP = PSIBHP= 5850 PSI10PPG10PPG448558505PPG
55 SCR MeasurementsWhen a well control situation arises , the pressure inside the wellbore prohibits the use of normal circulation rates used during drilling because :It might lead to high pressure inside the annulus , causing lost circulationIt might cause higher pressure at surface than the working pressure rating of the surface pump and high pressure linesIt might be difficult to safely control the well and monitor the process at high pumping rate
56 SCR Measurements (cont.) therefore in most cases control of the well is gained while circulating at low flow rate , called slow circulation rate (SCR)A drilling crew determines accurate circulation pressure at specified slow circulation rate every tour or every significant change in drilling fluid density and properties or after drilling every 500 feet , whichever comes first.
57 GAS MIGRATIONWhen a well is shut-in on a gas kick because of its low density , gas tends to migrate , or move upward , in a well. If the gas volume remains the same ,the pressure also will remain the same based on the gas compressibility equation, but the casing pressure will increase as the hydrostatic pressure decreases due to the upward movement of the gas. If the gas is allowed to expand , the pressure in the gas kick will decrease. Gas expansion is controlling the backpressure with a choke while circulating
58 EXAMPLE MUD GRAD = 0.5 PSI / FT SHOE DEPTH = 6000 FT HYD PRESS @ SHOE = 3000 PSITVD = FTBHP = 5000 PSI3000 PSISHOE5000 PSI
65 STAGE FOUR HGAS = 1000 FT HMUD= 7500 FT SHOE @ 4000 FT 650PSIHGAS = 1000 FTHMUD= 7500 FTFTGG = 0.1 PSI / FTMG = 0.5 PSI / FTFP = 4500 PSI PSISICP = 4500-((1000*0.1)+(7500*0.5))PSISHOE
66 shut-in methodsThere are two types of shut-in methods in the oil industryHard shut-inSoft shut-in
67 hard shut-in procedure In the hard shut-in method, the hydraulic valve on the choke line (HCR VALVE )and the choke itself are kept closed during normal operations. after kick indicators are observed and a kick is confirmed ,following procedure is used
68 Hard Shut –in: initial line up of choke line and choke manifold ` Valve or BOP OpenValve or BOP CloseChokeClosedANNULARTo Mud gas Seperator, Mud tanks, FlarePIPE RAMKill LineValve ClosedChoke line HCR valve closedBLIND RAMPIPE RAMBleed –off line to FlareTo Mud gas Seperator, Mud tanks, FlareDrill stringChokeClosedHard Shut –in: initial line up of choke line and choke manifold
69 To Mud gas Seperator, Mud tanks, Flare or Overboard ` Valve or BOP OpenValve or BOP CloseChokeCloseANNULARAnnular BOPCloseTo Mud gas Seperator, Mud tanks, Flare or OverboardPIPE RAMKill LineValve ClosedBLIND RAMChoke LineHCR Valve closedPIPE RAMBleed –off line to Flare or OverboardTo Mud gas Seperator, Mud tands, Flare or OverboardDrill stringChokeClosedHard Shut –in: Close Annular BOP
70 Hard Shut –in: open HCR valve ` Valve or BOP OpenValve or BOP CloseChokeCloseANNULARAnnular BOPCloseTo Mud gas Seperator, Mud tanks, Flare or OverboardPIPE RAMKill LineValve ClosedBLIND RAMChoke LineHCR Valve closedPIPE RAMBleed –off line to Flare or OverboardTo Mud gas Seperator, Mud tands, Flare or OverboardDrill stringChokeClosedHard Shut –in: open HCR valve
71 The primary advantage of a hard shut-in is that the kick influx is held to a small volume because the well is closed in more quickly . One disadvantage is that with some hard shut-in procedures , casing pressure cannot be observed ,since the choke-line valves are closed thus MAASP could be exceeded , which could cause formation fracture and lost circulation
72 soft shut-in procedure In the soft shut-in method , the HCR valve is closed and the choke is open during normal operations . When primary indicators of kick are experienced , following procedure is used
73 soft Shut –in: initial line up of choke line and choke manifold ` Valve or BOP OpenValve or BOP CloseChokeopenANNULARTo Mud gas Seperator, Mud tanks, Flare or OverboardPIPE RAMKill LineValve ClosedBLIND RAMChoke line HCR valve closedPIPE RAMBleed –off line to Flare or OverboardTo Mud gas Seperator, Mud tands, Flare or OverboardDrill stringChokeClosesoft Shut –in: initial line up of choke line and choke manifold
74 Soft shut-in :open choke line HCR valve ` Valve or BOP OpenValve or BOP CloseChokeopenANNULARAnnular BOPCloseTo Mud gas Seperator, Mud tanks, Flare or OverboardPIPE RAMKill LineValve ClosedBLIND RAMPIPE RAMBleed –off line to Flare or Overboardopen Choke LineHCR ValveTo Mud gas Seperator, Mud tands, Flare or OverboardDrill stringChokeCloseSoft shut-in :open choke line HCR valve
75 soft Shut –in: Close Annular BOP ` Valve or BOP OpenValve or BOP CloseChokeopenANNULARclose Annular BOPTo Mud gas Seperator, Mud tanks, Flare or OverboardPIPE RAMKill LineValve ClosedBLIND RAMPIPE RAMBleed –off line to Flare or OverboardChoke LineHCR Valve OpenedTo Mud gas Seperator, Mud tands, Flare or OverboardDrill stringChokeClosedsoft Shut –in: Close Annular BOP
76 Soft shot-in : Close choke ` Valve or BOP OpenValve or BOP CloseClosechokeANNULARAnnular BOPCloseTo Mud gas Seperator, Mud tanks, Flare or OverboardPIPE RAMKill LineValve ClosedBLIND RAMPIPE RAMBleed –off line to Flare or OverboardChoke LineHCR Valve OpenedTo Mud gas Seperator, Mud tands, Flare or OverboardDrill stringChokeClosedSoft shot-in : Close choke
77 The primary disadvantage of a soft shut-in is that it requires more steps and time than a hard shut-in . The result can be a large influx of kick fluids .
78 Shut-in procedure while drilling When a kick is taken while drilling , the following well shut-in procedure should be used:Stop pipe rotationPick the drill string up off-bottom to space out correctly ( ensure that a tool joint is not across a BOP pipe ram )Stop pumping - shut off the mud pumps .Check the well for flow and confirm kick .Shut in the well with the annular BOP , using either a hard or soft shut-in methodVerify that the well is shut in and that there are no leaks in the system .Read and record SIDPP and SICP
79 Shut-in procedure while tripping When a kick is suspected during tripping , the following well shut-in procedure should be used:Check the well for flow and confirm kick .Space out the drill string correctly , with a drill pipe tool joint close to the rotary table and no tool joints placed across a BOP pipe ram . Set the drill string in slips in the rotary tableInstall a fully opened drill string safety valveClose the drill string safety valveShut in the well with the annular BOP using either a hard or soft shut-in method
80 Killing a wellAll well kill methods use a common principle :Maintain a minimum constant bottom hole pressure equal to or greater than the formation pressure while circulating out the formation influx to regain control of the well
82 After well shut-inAfter a kick has been taken and the well is shut in adequate preparation is required before starting a well kill operation . These preparations include :preparation a kick sheetDetermining kill fluid density and mixing kill fluidPerforming calculations to obtain the data required for well killPreparing a pump pressure schedule
83 Prepare kick sheetThe general well data , drill string / annulus contents , circulating times , and the mud pump data (SCR ) is recorded routinely and kept available at all times at the rig floor through a kick sheet .The shut-in drill pipe pressure , shut-in casing pressure , and pit gain is also recorded on the kick sheet after the well has been shut in.Some additional information is also added to kick sheet , such as kill fluid density , initial circulating pressure final circulating pressure / pump pressure schedule , time to kill the well , etcetera.
84 Mix kill fluidThe well will be considered killed only when the hydrostatic pressure of the drilling fluid column in the well is higher than the formation pressure and primary control of the well has been regained . The required density of the kill fluid is calculated using following equation :Calculate kill fluid densitySIDPPMW k = MWo0.052 ×TVD
85 Mix kill fluid( b ) calculate the required quantity of weighting materialNormally , barite is used as weighting material to raise the density of the drilling fluid . The required quantity of barite to raise the original drilling fluid density to kill fluid density can be calculated using following equation:Barite required (lbs) = MWk -MWo1472× Total active drilling fluid volume (bbl) ×35 – MWkMWo = original drilling fluid density , or original Mud Weight (ppg )MWk = kill fluid density , or kill mud weight (ppg)
87 Perform calculations for well killing procedure Initial circulating pressure ( ICP )ICP = SIDPP + P scrICP = initial circulating pressureSIDPP = shut-in drill pipe pressurePscr = pump pressure at kill flow rate ( slow circulation rate)
88 Perform calculations for well killing procedure (cont.) (b ) Displacement times and corresponding pump strokesCalculate displacement times and pump strokes using the volume and the slow circulation rate for well kill operation .normally , the displacement time and corresponding pump strokes are calculated for three milestones, these are:Kill fluid at the bitInflux circulated out of the wellKill fluid returning to surface
89 Pscr = pump pressure at kill flow rate (slow circulation rate) (c ) Final circulating pressure (FCP )FCP is the circulation pressure on the drill pipe pressure gauge when the kill fluid exits the bit. FCP can be calculated using the following equation:Pscr × MWkFCP =MWoFCP = final circulating pressureMWk = kill fluid density or Kill Mud Weight (ppg)Pscr = pump pressure at kill flow rate (slow circulation rate)MWo = original drilling fluid density , or original Mud Weight(ppg)
90 Driller’s MethodStart pumpingHold casing pressure constant by manipulating the choke.Bring pumps up to kill speed.Adjust pressure to ICP.Casing pressure will increase this due to gas expansion in the well boreHold ICP constant until influx is outShut down pumps holding casing pressure constantCheck that drill pipe pressure and casing pressure is equal
92 Casing pressure is held constant as pumps are brought up to speed by opening the choke If the casing pressure is held constant when starting then BHP is constant1300500DP1300CP500closeopen= 1000 psiICP = =1300 psiBHP5500 psiTVD = 10000
93 Till the gas influx gets further up the hole there is little expansion and the casing pressure will rise slowly as mud (hydrostatic) is pushed out of the hole.1300520DP1300CP520closeopenBHP5500 psi
94 As the bubble begins to expand it pushes mud out of the hole causing a loss of hydrostatic. To keep BHP constant, drill pipe pressure must be kept constant.1300650DP1300CP650closeopenBHP5500 psi
103 Once the influx is circulated out , the well should be shut –in Compare the drill pipe and casing pressure gauges and confirm that they are equal .if casing pressure is greater than drill pipe pressure then you may not have all the influx out of the well.Once you are confident that the annulus is clean line up the pumps on kill weight fluid300300DP300CP300closeopenBHP5500 psi
104 Hold casing pressure constant as you bring the pumps up to 40 spm . Continue to hold casing pressure constant as you displace the drillsting .Drillpipe pressure should drop as hydrostatic in the drillpipe increases.1300300DP1300CP300closeopenspm = 1000 psiICP= = 1300 psi on DPBHP5500 psi
109 Continue circulating holding drillpipe pressure constant at FCP . Once the drillpipe is full of kill weight fluid the hydrostatic will remainContinue circulating holding drillpipe pressure constant at FCP .Casing pressure should drop as kill weight fluid displaces the annulus .1060300DP1060CP300closeopenBHP5500 psi
112 Wait-and-Weight Method This is a one-circulation well control method. It is sometimes referred to as the Engineer’s method . In the wait-and-weight method, the influx is circulated out and primary control of the well is regained in one circulation. In this method, the drilling fluid is first weighted up to the kill fluid density, then the kill fluid is pumped in the well, displacing both the formation fluid influx and the original drilling fluid.Following are the steps of the wait-and-weight well control method:1. Mix the kill fluid.2. Bring the pump up to speed for the circulation at slow rate. Slowly open the remotely operated choke while the pump is slowly brought up to speed. Maintain choke pressure equal to the shut-in casing pressure prior to the start of the circulation.3. Once the pump is up to speed, record the initial circulating pressure on the drill pipe pressure gauge.maintain drill pipe pressure as per the drill pipe pressure schedule. Ensure that the pump rate is kept constant during circulation.4. Pump kill fluid into the well through the drill string. As the drill string isdisplaced with kill fluid, the drill pipe pressure will reduce as thehydrostatic pressure of the drilling fluid column inside the drill stringincreases. Once the fluid inside the drill string has been displaced by killfluid, the drill pipe pressure should equal the FCP. Maintain this drill pipepressure for further circulation.
113 F C C ANALYSIS OF ICP & FCP I P P 3000 2000 1000
116 HGAS = 200 FT HMUD = 6000 FT GG = 0.1 PSI / FT MG = 1.0 PSI / FT GAS BUBBLE COLLAPSEHGAS = 200 FTHMUD = 6000 FTGG = 0.1 PSI / FTMG = 1.0 PSI / FT
117 HGAS = 50 FT HMUD = 6150 FT GG = 0.1 PSI / FT MG = 1.0 PSI / FT GAS BUBBLE COLLAPSEHGAS = 50 FTHMUD = 6150 FTGG = 0.1 PSI / FTMG = 1.0 PSI / FT
118 Other well control methods VolumetricLubricate and bleedbullheading
119 Volumetric methodThe volumetric method is a non-circulating well kill method and can be used only if the influx can migrate up , such as a gas kick where the free gas is able to migrate up in the well . Generally , the volumetric method is used in following situationsDuring any shut in period after the well has kicked and the gas is migrating upIf the pumps are inoperable.If there is a washout in the drill string that prevents displacement of the kick through conventional circulation methods .If the pipe is a considerable distance off bottom, out of the hole or stuck / parted off bottom.If the drill string is plugged
120 Record the shut-in casing pressure Monitor the shut-in pressure and if they are found to be increasing with time , this confirms gas migration. Commence with the volumetric method to allow controlled expansion of gas.Select an overbalance margin and operating range for casing pressure. Recommended overbalance margin , 100 psiNote : the overbalance margin in the casing pressure ensures that the overbalance inside the well bore is maintained as mud is bled from the wellCalculate hydrostatic pressure (HP) per bbl fluid in the upper annulus.HP per bbl ( psi/bbl ) = fluid gradient (psi/ft) ÷ annular capacity factor (bbl /ft)Calculate volume to bleed each cycle.Volume to bleed (bbl/cycle ) = range (psi) ÷ HP per bbl (psi/bbl)Construct casing pressure vs. volume to bleed schedule.
121 Allow SICP to increase by over balance margin. Allow SICP to increase by operating range.While maintaining the SICP constant at the new value , bleed small volumes of mud into a calibrated tank until the calculated volume in step 3 is bledRepeat steps 6 and 7 until gas is at surfaceSafety margin = psiRange = 100 psiFluid grad = psi /ftCapacity factor = bbl /ft (9 5/8” * 5” )Hp per bbl = ÷ bbl / ft = psi/bblVolume to bleed = 100 ÷ = 8 bblsCasing pressure 1 = = 600 psiCasing pressure 2= = 700 psiCasing pressure 3 = = 800 psi
122 Example SICP = 400 psi ; range &SM = 100 psi ; volume bleed =8 bbls Gas migrating to surface16001400Bleeding while holding constant casing pressure1200Casing pressure (psi)1000800range600Range : 100 psi400Safety margin : 100 psi200Volume bled (bbls)8162432404856
123 Lubricate and bleed procedure In this procedure, the gas and the associated casing pressure is bled off and replaced with fluid keeping the bottom hole pressure constant. The following procedure is used for lubricate and bleedmix kill fluidPump through kill line into closed –in well to increase casing pressure by desired range . Recommended range = 100 psiAllow time for fluid to “ fall “ through the gas (usually minute ).Calculate bleed down pressure . The shut-in casing pressures during the lubricate and bleed procedure are related as the following equationP3= (P1)² ÷P2Where , P1 = SICP before pumping P2 = stabilized SICP after pumpingP3 = the pressure to bleed down toBleed dry gas from choke to reduce casing pressure to P3Repeat step 1 through 4 until gas is removed
125 BullheadingIn this well kill method , the formation influx is pumped back (bullheaded ) into the reservoir . It is a common well kill method is also used whenThe influx is very large and circulating out the influx will either exert very high pressure on the surface equipment or will result in very high volume of gas at the surface .The influx contains hydrogen sulfide (H2S) and it is not desired to circulate out the kick to the surface due to personal safety reasonsWhen an influx is taken with no pipe in the hole
127 Example: Depth of formation/perforations at 10,171 feet TVD Formation pressure = psi = 8.8 ppgFormation fracture pressure = psi = 13.8 ppgTubing 4-1/2“ N Internal capacity = bbl/ftInternal yield = 8,430 psiShut-in tubing head pressure = 3,650 psiGas density = 0.1 psi/ftTotal internal volume of tubing= 10,171 ft x bbl/ft = 155 bblMaximum allowable pressure at pump start up.= (13.8 ppg x 10,171 ft x 0.052) - (0.1 psi/ft x 10,171 ft)= 6,281 psiMaximum allowable pressure when the tubing has been displaced to brine at 1.06 sg (8.8 ppg).= (13.8 ppg – 8.8 ppg) x 10,171 ft x .052 = 2,644 psiTubing head pressure at initial shut – in.= 3,650 psi
128 Surface pressure (psi) Volume of tubing displaced (bbl) Tubing head pressure when tubing has been displaced to brine.= 0 psi (i.e. the tubing should be dead)The above values can be represented graphically (as shown in the figure v.1 below). This plot can be used as a guide during the bullheading operation.Static tubing pressurethat wouldfracture formationInclude psi safetyfactor (to avoid fracturingformation)tubing pressure toBalance formation pressureTubing burst pressure90008000700060005000400030002000100050100150Surface pressure (psi)Volume of tubing displaced (bbl)
129 در هنگام كشتن چاه بحراني ترين لحظه زماني است كه سر گاز به كفشك ميرسد . چـــــرا ؟زيرا در اين زمان گاز بيشترين انبساط را در چاه بازپيدا كرده و در اين لحظه فشار هايدرواستاتيك اززيركفشك تا ته چاه به كمترين مقدار رسيده است بنابراينطبيعي است كه بيشترين فشار به زير كفشك در ايـــنهنگام وارد شود.