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ON JANUARY 10, 1901, THE LUCAS GUSHER BLEW IN AT SPINDLETOP, NEAR BEAUMONT, TEXAS. The Hamill Brothers Had Started The Hole 3 Months Earlier For Captain.

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Presentation on theme: "ON JANUARY 10, 1901, THE LUCAS GUSHER BLEW IN AT SPINDLETOP, NEAR BEAUMONT, TEXAS. The Hamill Brothers Had Started The Hole 3 Months Earlier For Captain."— Presentation transcript:

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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 For Captain A. F. Lucas, And 6-inch Casing Had Been Set At 880 Feet After Minor Indications Of oil In The Next 7 Days, The Well Had Been Deepened By 140 Feet To, 1020 Feet, A Much Faster Rate Than Before. Running In A New Bit, The Crew Had 700 Feet Of 4-inch Drill Pipe In The Hole When The Well Started To Unload; That Is, Mud Started Flowing From The Casing. After Several Hard Kicks, Well Pressure Blew The Drill Pipe Out Of The Hole. Soon A Stream Of Oil And Gas Was Spraying More Than 100 Feet In To The Air, Producing By Some Estimates 75,000 To 100,000 Barrels Of Oil Per Day. Most Of The Signs Of A Developing Blowout Were Observable On The Lucas Well: Shows Of Oil And Gas In The Mud Drilling Break (Faster Drilling) Flow Of Mud From The Well Pit Gain

3 Hydrostatic pressure hydrostatic 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 pressure pressure = fluid density x vertical height of the fluid column

4 HP = C x MW x TVD where: HP = Hydrostatic Pressure (P h )(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 gallons A fluid weighing 1 ppg is therefore equivalent to 7.48 lbs /cu.ft The pressure exerted by one foot of the fluid over the base would be : 7.48 lbs / 144 sq.ins = psi Example: Calculating hydrostatic pressure the 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 psi 12

5 PRESSURE GRADIENT Pressure 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 MW PG = Pressure Gradient psi / ft MW = Fluid Density lbs/gal C = conversion constant psi /ft / lbs/gal Pressure 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 MW PG = Pressure Gradient psi / ft MW = Fluid Density lbs/gal C = conversion constant psi /ft / lbs/gal

6 OVER BURDEN PRESSURE Overburden 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 PRESSURE The 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 Pressure Subnormal Formation Pressure Abnormal 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, 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 causes Diagenesis Piezometric surface Tectonic causes Structural 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 SURFACE A 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 causes Any 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

17 Causes of subnormal formation pressure are: Depleted Reservoirs Piezometric Surface Tectonic Compression

18 DEPLETED RESERVOIRS Producing 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. Example The 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 SURFACE A 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 COMPRESSION During 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 PRESSURE Fracture 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.

22 FORMATION PORE PRESSURE MUD PRESSURE FRACTURE PRESSURE GRADIENT PSI/ft

23 leak-off test this 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

24 Leak-off test

25 Maximum Allowable Annulus Surface Pressure this is the maximum pressure that can be tolerated in the annulus, without risking a possible formation rupture at or below the casing shoe. MAASP = Pressure required to fracture the formation mines hydrostatic pressure created by the column of mud in the annulus. ( Formation fracture gradient – MW gradient ) * Depth of CSG Fracture gradient = 0.8 psi/ft MW gradient = 0.52 psi/ft Depth of CSG = 8200 ft MAASP = ( 0.8 – 0.52 ) * 8200 MAASP = 2290 psi

26 well bore and the U Tube 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 same AB P A = P B

27 U Tube in a wellbore 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. AB P A = P B pump choke

28 home work What will be the gain in the pits, and how far will the slug fall if the mud weight is 10 ppg,the pipes capacity is bbl/ft ? The volume of the slug is 30 bbls and weighs 11 ppg.

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30 FLOW LINE Drill string Annulus BHP= Hydrostatic pressure of drilling fluid column inside drill string Fluid column A : Density 11 ppg Fluid column B : Density 11.5 ppg 1500 ft 2500 ft

31 FLOW LINE Drill string Annulus BHP= Hydrostatic pressure of drilling fluid column inside drill string BHP= Hydrostatic pressure of drilling fluid column inside Annulus

32 Static well bore with External Pressure In shut in well conditions, the BHP can be calculated using the following equations BHP = HP d + SIDPP BHP = HP a + SICP

33 CHOKE Drill string Annulus BHP= Hydrostatic pressure inside drillstring +SIDPP BHP= Hydrostatic pressure inside Annulus +SICP FORMATION ORESSURE Mud Pump SIDPP SICP Mud Pump CHOKE SICP SIDPP FORMATION ORESSURE

34 CHOKE BHP= Hydrostatic pressure inside drillstring +pump pressure – pressure loss inside drilling and bit FORMATION ORESSURE Mud Pump Pump pressure Friction pressure loss in the drillstring acting against pump pressure The well bore in dynamic condition – drill string side

35 BHP= Hydrostatic pressure inside Annulus +surface casing pressure +pressure loss inside annulus Mud Pump CHOKE SICPsurface casing pressure Pump pressre FORMATION ORESSURE Friction pressure loss in the annulus acting downwards The well bore in dynamic condition – annulus side

36 SICP H h SIDPP + HP dp = SICP + ( MG ×H ) + ( IG ×h ) SIDPP = H h SIDPP + ( MG × H ) + ( MG × h ) =SICP + ( MG×H ) + ( IG × h ) ( MG × H ) + ( MG × h ) - ( MG×H ) - ( IG × h ) = SICP-SIDPP IG =MG - GAS = TO 0.15 OIL&GAS = F/ 0.15 to/ 0.4 WATER & SALT WATER ABOVE 0.4 Influx Gradient Evaluation

37 Kick A kick is the undesired entry of formation fluids into the well bore Blowout A blowout is the uncontrolled flow of gas, oil, or other formation fluids Sometimes,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 1.Not keeping the hole full 2.Swabbing 3.Overpressure ( abnormal pressure ) formations 4.Lost circulation 5.Gas/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 = bls/ft Metal displacement = bls/ft Annular volume bls/ft Pipe capacity = bls /ft Mud gradient = psi / ft 1 stand = 94 ft Bottom 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 pressure How many stands would have to be pulled wet to remove a 50 psi overbalance and allow the well to flow ?

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43 2- swabbing Swabbing 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 string Balled-up bottom hole assembly Pulling pipe too fast Poor drilling fluid properties Large OD tools

44 3- Abnormal pressure reservoir 4- Lost circulation Causes of lost circulation High density of drilling fluid Going 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.

46 Kick Indicators 1.Primary kick Indicators 2.Secondary kick Indicators

47 Primary Kick Indicators 1.Increase in return flow rate 2.Increase in pit volume 3.Insufficient hole fill during tripping 4.Positive flow check

48 secondary Kick Indicators 1.Drilling break 2.Decrease in circulating pressure with a corresponding increase in circulating rate 3.Increase in gas cutting, oil cutting, or chlorides

49 Early warning signs( home work) Increase in background, connection, and trip gas Increase in the chlorides content of the mud Changes in the size and shape of cuttings Unaccounted –for fluid loss while tripping Increasing fill on bottom after a trip Increase in flow line temperature Increase in rotary torque Increase tight hole on connection Decrease in D-exponent Most of these signs are related to the indication of a transition zone prior to drilling into an abnormal pressure formation

50 PPG 10PPG10PPG BALANCED STATIC CONDITION Figure shows a balanced U-tube situation with fluid of the same density in the annulus and drill pipe sides. Depth = ft Shoe depth = 5000 ft Mud wt = 10 ppg

51 PPG 10PPG10PPG STANDARD CIRCULATION SITUATION Depth = ft Shoe depth = 5000 ft Mud wt = 10 ppg Circulating pressure 2600 psi APL = 260 PSI

52 PSI 5PPG 10PPG 10PPG10PPG SHUT-IN KICK PRESSURES

53 PPG 10PPG10PPG 5PPG بررسي حالتي كه وزن گل دا ليز از وزن گل درون لوله ها كمـــتر اسـت و گردش گل با سرعت زمان حفاري همراه با پس فشار برقرا ر است. SIDPP= 520PSI SPL= 2600 PSI APL= 260 PSI FP = 5720 PSI BHP= 5980 PSI

54 PPG 10PPG10PPG 5PPG بررسي حالتي كه وزن گل دا ليز از وزن گل درون لوله ها كمـــتر است و گردش گل با سرعت آرام همراه با پس فشار برقرا راست. SIDPP= 520PSI SPL= 700 PSI APL= 130 PSI FP = 5720 PSI BHP= 5850 PSI

55 SCR Measurements When 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 circulation It might cause higher pressure at surface than the working pressure rating of the surface pump and high pressure lines It 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 MIGRATION When 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 MUD GRAD = 0.5 PSI / FT SHOE DEPTH = 6000 FT HYD SHOE = 3000 PSI TVD = FT BHP = 5000 PSI 5000 PSI EXAMPLE 3000 PSI SHOE

59 W/H PRESS = 5200 – (10000 * 0.5 ) = 200 HYD SHOE = 3200 PS 5200 PSI 200 PSI STAGE ONE = 3200 PSI SHOE 5200-(4000* 0.5) = (6000 * 0.5 ) = 3200 BHP = GAS PRESS = 5200 PSI

60 W/H PRESS = 2200 PSI HYD SHOE = 5200 PSI BHP = 7200 PSI = 7200 PSI 2200 PSI STAGE TWO 5200 PSI SHOE

61 W/H PRESS = GAS PRESS = 5200 HYD SHOE = 8200 PSI BHP = PSI = PSI 5200 PSI STAGE THREE = 8200 PSI SHOE

62 STAGE ONE SHOE H GAS = 200 FT H MUD = 8300 FT 4000 FT GG = 0.1 PSI / FT MG = 0.5 PSI / FT 2330 FP = 4500 PSI PSI SICP = 4500-((200*0.1)+(8300*0.5)) 4500 PSI 330 PSI

63 STAGE TWO SHOE H GAS = 400 FT H MUD = 8100 FT 4000 FT GG = 0.1 PSI / FT MG = 0.5 PSI / FT 2410 FP = 4500 PSI PSI SICP = 4500-((400*0.1)+(8100*0.5)) 4500 PSI 410 PSI

64 STAGE THREE SHOE H GAS = 600 FT H MUD = 7900FT 4000 FT GG = 0.1 PSI / FT MG = 0.5 PSI / FT 2490 FP = 4500 PSI PSI SICP = 4500-((600*0.1)+(7900*0.5)) 4500 PSI 490 PSI

65 STAGE FOUR SHOE H GAS = 1000 FT H MUD = 7500 FT 4000 FT GG = 0.1 PSI / FT MG = 0.5 PSI / FT 2250 FP = 4500 PSI PSI SICP = 4500-((1000*0.1)+(7500*0.5)) 4500 PSI 650 PSI

66 shut-in methods There are two types of shut-in methods in the oil industry Hard shut-in Soft 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 ANNULAR PIPE RAM BLIND RAM PIPE RAM Choke Closed To Mud gas Seperator, Mud tanks, Flare Bleed –off line to Flare To Mud gas Seperator, Mud tanks, Flare Choke Closed Drill string Kill Line Valve Closed ` Valve or BOP Open Valve or BOP Close Hard Shut –in: initial line up of choke line and choke manifold Choke line HCR valve closed

69 ANNULAR PIPE RAM BLIND RAM PIPE RAM Choke Close To Mud gas Seperator, Mud tanks, Flare or Overboard Bleed –off line to Flare or Overboard To Mud gas Seperator, Mud tands, Flare or Overboard Choke Closed Drill string Kill Line Valve Closed ` Valve or BOP Open Valve or BOP Close Hard Shut –in: Close Annular BOP Choke Line HCR Valve closed Annular BOP Close

70 ANNULAR PIPE RAM BLIND RAM PIPE RAM Choke Close To Mud gas Seperator, Mud tanks, Flare or Overboard Bleed –off line to Flare or Overboard To Mud gas Seperator, Mud tands, Flare or Overboard Choke Closed Drill string Kill Line Valve Closed ` Valve or BOP Open Valve or BOP Close Hard Shut –in: open HCR valve Choke Line HCR Valve closed Annular BOP Close

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 ANNULAR PIPE RAM BLIND RAM PIPE RAM Choke open To Mud gas Seperator, Mud tanks, Flare or Overboard Bleed –off line to Flare or Overboard To Mud gas Seperator, Mud tands, Flare or Overboard Choke Close Drill string Kill Line Valve Closed ` Valve or BOP Open Valve or BOP Close s oft Shut –in: initial line up of choke line and choke manifold Choke line HCR valve closed

74 ANNULAR PIPE RAM BLIND RAM PIPE RAM Choke open To Mud gas Seperator, Mud tanks, Flare or Overboard Bleed –off line to Flare or Overboard To Mud gas Seperator, Mud tands, Flare or Overboard Choke Close Drill string Kill Line Valve Closed ` Valve or BOP Open Valve or BOP Close Soft shut-in :open choke line HCR valve open Choke Line HCR Valve Annular BOP Close

75 ANNULAR PIPE RAM BLIND RAM PIPE RAM Choke open To Mud gas Seperator, Mud tanks, Flare or Overboard Bleed –off line to Flare or Overboard To Mud gas Seperator, Mud tands, Flare or Overboard Choke Closed Drill string Kill Line Valve Closed ` Valve or BOP Open Valve or BOP Close soft Shut –in: Close Annular BOP Choke Line HCR Valve Opened close Annular BOP

76 ANNULAR PIPE RAM BLIND RAM PIPE RAM Close choke To Mud gas Seperator, Mud tanks, Flare or Overboard Bleed –off line to Flare or Overboard To Mud gas Seperator, Mud tands, Flare or Overboard Choke Closed Drill string Kill Line Valve Closed ` Valve or BOP Open Valve or BOP Close Soft shot-in : Close choke Choke Line HCR Valve Opened Annular BOP Close

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 When a kick is taken while drilling, the following well shut-in procedure should be used: Stop pipe rotation Pick 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 method Verify that the well is shut in and that there are no leaks in the system. Read and record SIDPP and SICP Shut-in procedure while drilling

79 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 table Install a fully opened drill string safety valve Close the drill string safety valve Shut in the well with the annular BOP using either a hard or soft shut-in method Shut-in procedure while tripping

80 All 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 Killing a well

81 Minimum constant bottom hole pressure formation pore pressure shut-in drill pipe pressure+ hydrostatic pressure of the original drilling fluid column in the drill string Minimum constant bottom hole pressure formation pore pressure + safety margin (0-200 psi)

82 After well shut-in After 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 sheet Determining kill fluid density and mixing kill fluid Performing calculations to obtain the data required for well kill Preparing a pump pressure schedule

83 Prepare kick sheet The 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 fluid The 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 : (a)Calculate kill fluid density SIDPP MW k = + MWo ×TVD

85 Mix kill fluid ( b ) calculate the required quantity of weighting material Normally, 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) = MW k -MW o 1472× Total active drilling fluid volume (bbl) × 35 – MW k MW o = original drilling fluid density, or original Mud Weight (ppg ) MW k = kill fluid density, or kill mud weight (ppg)

86 example : Original density = 10 ppg TVD = 6000 ft SIDPP = 150 Safety margin = 50 psi Drill string volume = 150 bbl Annulus volume = 500 bbl Active surface volume = 300 Calculate weighting material requirement

87 Perform calculations for well killing procedure (a)Initial circulating pressure ( ICP ) ICP = SIDPP + P scr ICP = initial circulating pressure SIDPP = shut-in drill pipe pressure P scr = pump pressure at kill flow rate ( slow circulation rate)

88 Perform calculations for well killing procedure (cont.) (b ) Displacement times and corresponding pump strokes Calculate 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 bit Influx circulated out of the well Kill fluid returning to surface

89 (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: P scr × MW k FCP = MW o FCP = final circulating pressure MW k = kill fluid density or Kill Mud Weight (ppg) P scr = pump pressure at kill flow rate (slow circulation rate) MWo = original drilling fluid density, or original Mud Weight(ppg)

90 Drillers Method 1.Start pumping 2.Hold casing pressure constant by manipulating the choke. 3.Bring pumps up to kill speed. 4.Adjust pressure to ICP. 5.Casing pressure will increase this due to gas expansion in the well bore 6.Hold ICP constant until influx is out 7.Shut down pumps holding casing pressure constant 8.Check that drill pipe pressure and casing pressure is equal

91 DP 300 CP * 10 *.052 =5200 psi = 5500 psi BHP Mud weight = 10 ppg TVD = closeopen

92 DP 1300 CP 500 ICP = =1300 psi 5500 psi BHP = 1000 psi TVD = closeopen 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 constant

93 DP 1300 CP psi BHP closeopen 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.

94 DP 1300 CP psi BHP closeopen 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.

95 DP 1300 CP psi BHP closeopen

96 DP 1300 CP psi BHP closeopen

97 DP 1300 CP psi BHP closeopen

98 DP 1300 CP psi BHP closeopen

99 DP 1300 CP psi BHP closeopen

100 DP 1300 CP psi BHP closeopen

101 DP 1300 CP psi BHP closeopen

102 DP 1300 CP psi BHP closeopen

103 DP 300 CP psi BHP 300 closeopen 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 fluid

104 DP 1300 CP psi BHP closeopen 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. spm = 1000 psi ICP= = 1300 psi on DP

105 DP 1250 CP psi BHP closeopen

106 DP 1200 CP psi BHP closeopen

107 DP 1150 CP psi BHP closeopen

108 DP 1100 CP psi BHP closeopen

109 DP 1060 CP psi BHP closeopen Once the drillpipe is full of kill weight fluid the hydrostatic will remain Continue circulating holding drillpipe pressure constant at FCP. Casing pressure should drop as kill weight fluid displaces the annulus.

110 DP 1060 CP psi BHP closeopen

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112 Wait-and-Weight Method This is a one-circulation well control method. It is sometimes referred to as the Engineers 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 is displaced with kill fluid, the drill pipe pressure will reduce as the hydrostatic pressure of the drilling fluid column inside the drill string increases. Once the fluid inside the drill string has been displaced by kill fluid, the drill pipe pressure should equal the FCP. Maintain this drill pipe pressure for further circulation.

113 ANALYSIS OF ICP & FCP I C P C P F

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116 GAS BUBBLE COLLAPSE H GAS = 200 FT H MUD = 6000 FT GG = 0.1 PSI / FT MG = 1.0 PSI / FT

117 GAS BUBBLE COLLAPSE H GAS = 50 FT H MUD = 6150 FT GG = 0.1 PSI / FT MG = 1.0 PSI / FT

118 Other well control methods Volumetric Lubricate and bleed bullheading

119 Volumetric method The 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 situations During any shut in period after the well has kicked and the gas is migrating up If 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 psi Note : the overbalance margin in the casing pressure ensures that the overbalance inside the well bore is maintained as mud is bled from the well Calculate 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 bled Repeat steps 6 and 7 until gas is at surface Safety margin = 100 psi Range = 100 psi Fluid grad. = psi /ft Capacity factor = bbl /ft (9 5/8 * 5 ) Hp per bbl = ÷ bbl / ft = psi/bbl Volume to bleed = 100 ÷ = 8 bbls Casing pressure 1 = = 600 psi Casing pressure 2= = 700 psi Casing pressure 3 = = 800 psi

122 Volume bled (bbls) Example SICP = 400 psi ; range &SM = 100 psi ; volume bleed =8 bbls Casing pressure (psi) Gas migrating to surface Bleeding while holding constant casing pressure range Range : 100 psi Safety margin : 100 psi

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 bleed mix kill fluid Pump through kill line into closed –in well to increase casing pressure by desired range. Recommended range = 100 psi Allow 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 equation P3= (P1)² ÷P2 Where, P1 = SICP before pumping P2 = stabilized SICP after pumping P3 = the pressure to bleed down to Bleed dry gas from choke to reduce casing pressure to P3 Repeat step 1 through 4 until gas is removed

124 1000 psi 1100 psi909 psi 1009 psi 819 psi (P 1 )² ÷ P 2 = P 3 P 1 =1000 psiP 2 =1100 psi

125 Bullheading In this well kill method, the formation influx is pumped back (bullheaded ) into the reservoir. It is a common well kill method is also used when The 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 (H 2 S) and it is not desired to circulate out the kick to the surface due to personal safety reasons When an influx is taken with no pipe in the hole

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127 Example: Depth of formation/perforations at 10,171 feet TVD Formation pressure= 4654 psi= 8.8 ppg Formation fracture pressure= 7299 psi= 13.8 ppg Tubing 4-1/2 N 80 Internal capacity = bbl/ft Internal yield= 8,430 psi Shut-in tubing head pressure= 3,650 psi Gas density= 0.1 psi/ft Total internal volume of tubing = 10,171 ft x bbl/ft = 155 bbl - Maximum 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 psi - Maximum 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 psi Tubing head pressure at initial shut – in. = 3,650 psi

128 - 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 S urface pressure (psi) Volume of tubing displaced (bbl) Static tubing pressure that would fracture formation Include psi safety factor (to avoid fracturing formation) tubing pressure to Balance formation pressure Tubing burst pressure

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 باز پيدا كرده و در اين لحظه فشار هايدرواستاتيك اززير كفشك تا ته چاه به كمترين مقدار رسيده است بنابراين طبيعي است كه بيشترين فشار به زير كفشك در ايـــن هنگام وارد شود.


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