Lesson 10 Flow Mudcap Snub Closed systems

Lesson 10 Flow Mudcap Snub Closed systems - PETE 689...

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Unformatted text preview: PETE 689 Underbalanced Drilling (UBD) Lesson 10 Lesson Flow Drilling Mudcap Drilling Snub Drilling Closed Systems Read: UDM Chapter 2.8­2.11 Pages 2.180­2.219 Harold Vance Department of Petroleum Engineering Flow Drilling Flow Drilling Flow drilling refers to drilling operations in which the well is allowed to flow to surface while drilling. All UBD operations are really flow drilling operations, but the term is usually applied to drilling with a single phase mud, and no gas is injected except by the formation. Harold Vance Department of Petroleum Engineering Flow Drilling Clear drill brine density less than or equal to 1.02 g/cm3 Oil, Gas, and Brine 9.5 ppg Brine Pressure higher in HEEL of well causing lost returns Pressure lower in TOE of well causes influx Pore Pressure =3030 psi at 6234 ft Flowdrilling a naturally fractured horizontal well (courtesy of Signa Engineering Corporation) Harold Vance Department of Petroleum Engineering Drilling Fluid Selection Drilling Fluid Selection Density is determined by: • Maximum pressure ≤ to formation pressure. • Minimum pressure dictated by wellbore stability. Pressure limitations of diverter and BOP equipment. Harold Vance Department of Petroleum Engineering Surface Equipment Surface Equipment MUD PITS STACK CHEMICAL INJECTION GAS/FLUID SEPARATION SYSTEM UNDERBALANCE DRILLING MANIFOLD Schematic of surface equipment required for flowdrilling (courtesy of Signa Engineering Corporation) Harold Vance Department of Petroleum Engineering Surface Equipment 12 in. Flare 6 in. Flare 4­6 in. 4 in. Flare Gas boot (open on bottom) Water to rig Grade Gas Separator Choke Manifold Gas Separator Skimmer tanks ROP Annular Preventer Pipe Rams Blind Rams Oil tank Pipe Rams Oil to treatment off location Atmospheric surface system for flowdrilling (courtesy of Signa Engineering Corporation) Harold Vance Department of Petroleum Engineering Surface Equipment RBOP Choke Line Typical flowdrilling BOP stack (courtesy of Signa Engineering Corporation) Harold Vance Department of Petroleum Engineering Surface Equipment Rotating blowout preventer (RBOP). Harold Vance Department of Petroleum Engineering Surface Equipment Kelly Packer Hydraulic Fluid Hydraulic Fluid Nitrile Nitrile RBOP sealing elements RBOP sealing elements Harold Vance Department of Petroleum Engineering Surface Equipment Manual Choke Hydraulic Choke A typical flowdrilling choke manifold (courtesy of Signa Engineering Corporation) Harold Vance Department of Petroleum Engineering Sizing Flare Line Sizing Flare Line Weymouth’s equation can be used to predict the pressure drop for a gas, in steady­state, adiabatic, flow along the pipe: … Harold Vance Department of Petroleum Engineering Sizing Flare Line Sizing Flare Line Q = 433.5 To d16/3(P21­P22) Po STLZa Where: 2.73 Q gas flow rate (scf/D) d inside diameter of the pipe (the gas flare line in this case) (inches) To standard temperature (520 oF) Po standard pressure (14.7 psia) S fluid’s density below the bit (lbm/ft3) T pressure above the bit (psfa) L bottomhole pressure below the bit (psia) Za average compressibility factor (Weymouth used Za = 1) P1,P2 the inlet and outlet pressures (psia) Harold Vance Department of Petroleum Engineering Sizing Flare Line Sizing Flare Line …Weymouth's Equation 2.73 incorporates a friction factor, f = 0.032/d1/3 Harold Vance Department of Petroleum Engineering Sizing Flare Line Assuming a gas gravity of 0.6, and Assuming substituting for standard temperature and pressure, Equation (2.73) becomes: d16/3(P21­P22) Q = 19,754 TL Harold Vance Department of Petroleum Engineering 2.74 Harold Vance Department of Petroleum Engineering Sizing Flare Line Converting length, L, from miles to feet, and flow rate, Q, from scf/D to MMscf/D, the inlet pressure, P1, is: Q2TL P1 = + P22 2.06d16/3 2.75 Harold Vance Department of Petroleum Engineering Sizing Flare Line The pressure differential exerted by the The U­tube head can be expressed as: P1 – P2 = 0.433ρh 2.76 Where: Ρ specific gravity of the fluid in the U­tube or separator. h height from the top of the gas boot to the bottom of the U­tube (feet). Harold Vance Department of Petroleum Engineering Sizing Flare Line Equations (2.75) and (2.76) can be combined to solve for the U­tube height, in terms of the gas flow rate, temperature, outlet (atmospheric) pressure, and flare line diameter: Q2TL + P22 ­ P2 2.06d16/3 h = 2.77 0.433ρ Harold Vance Department of Petroleum Engineering Surface Pits Surface Pits Primary oil separation pit. Secondary oil separation pit. Skimmer system safety. Drilling fluid pit. Oil transfer tank. Harold Vance Department of Petroleum Engineering Operating Procedures Operating Procedures Mechanical objectives flow drilling are: during • To control the well. differential sticking • Minimize problems. • Minimize drilling fluids losses. Maximum tolerable surfaces pressures should be established before drilling starts. Harold Vance Department of Petroleum Engineering Mudcap Drilling Mudcap Drilling Utilized with uncontrollable loss of circulation during flowdrilling operations. Higher pressures than can be safely handled with the rotating head or RBOP. It is not strictly an underbalanced drilling technique. Harold Vance Department of Petroleum Engineering Mudcap Drilling Driller loads the annulus with a relatively high density high viscosity mud and closes the choke with surface pressure maintained. Drilling is then continued “blind” by pumping a clear non­damaging fluid down the drillstring through the bit and into the thief zone. Harold Vance Department of Petroleum Engineering Mudcap Drilling Applications: • Sustained surface pressures in excess of 2,000 psi. • Sour oil and gas production. • Small diameter wellbores. Harold Vance Department of Petroleum Engineering Mudcap Drilling Viscous Fluid Mudcap Mudcap Interface (Formation Fluid / Drillwater) Water replacement in formation fractures An example of mudcap drilling (courtesy of Signa Engineering Corporation) Harold Vance Department of Petroleum Engineering Mudcap Drilling GAS BUSTER MUD PITS To flare pit RIG FLOOR MUD PUMPS HCR Valve (Closed) Chemical Injection CHOKE (closed) DIVERTER Schematic of equipment required for mudcap drilling (courtesy of Signa Engineering Corporation) Harold Vance Department of Petroleum Engineering Determining Pore Pressure Determining Pore Pressure Pressure, psi Depth (TVD)/ 1,000, ft. 9,200 9,400 9,600 9,800 11.8 12.0 12.2 12.4 12.6 12.8 Pore Pressure Bore Hole Pressure PP Datum Determining the Reservoir Pressure Along the Wellbore Harold Vance Department of Petroleum Engineering Static Standpipe Pressures Static Standpipe Pressures PSPPstatic= 0.052 (EMWpore pressure ­ MWinjection fluid)TVD Where: PSPPstatic static standpipe pressure, psi. EMWpore pressure equivalent mud weight of formation pore pressure, ppg. MWinjection fluid density of the injection fluid, ppg. TVD true vertical depth of the top of reservoir, ft. Harold Vance Department of Petroleum Engineering Example Example Given: Reservoir described in Figure 3­1­2. Injection fluid is fresh water with no additives. A lateral is planned to intersect the formation top at 12,750’ MD (20,000’ TVD) and encounter the formation bottom at TD of 17,000’ MD (12,500’ TVD). Fractures exist at both the top and the bottom of the formation. Find: Maximum static standpipe pressure when the bit is at the top and at the bottom of the formation. Formation To Formation Bottom EMWpore pressure 15 ppg TVD 12,000 ft 12,500 ft = 4,156 psi 4,129 psi MWinjection fluid 8.34 ppg 14.7 ppg 8.34 ppg PSPPstatic 0.052*(15­8.34)*12,000’ 0.052*(15­8.34)*12,000’ Harold Vance Department of Petroleum Engineering Dynamic Standpipe Pressures Dynamic Standpipe Pressures PSPINJECTION = PSPPstatic+ΔPDP+ΔP Drill collars+ΔPMWD+ΔP Motor+ΔP Bit+ΔP frac Where: PSPINJECTION standpipe pressure while circulating or injecting down drillpipe.. PSPPstatic static standpipe pressure, psi. ΔPDP frictional pressure drop of fluid flowing down drillpipe. ΔP Drill collars frictional pressure drop of fluid flowing down drill collars. ΔPMWD pressure drop across the measurement­while drilling tool. ΔP Motor pressure loss to power motor. ΔP Bit pressure drop across bit nozzles. ΔP frac frictional pressure drop of fluid flowing through fractures. Harold Vance Department of Petroleum Engineering Example Example Given: The reservoir described above. A directional hole is to be drilled with a 4¾­in. mud motor that requires a flow rate of 240 gpm resulting in a 400­psi on­bottom pressure differential. MWD pressure drop is equal to 150 psi. The MWD and Motor together have a total length of 60 ft. The drillpipe to be used is 3½­in. 13.3 lb/ft. No Drill Collars are in the string. Nozzles are (3) 17’s (32nd of an inch). Assume the pressure drop through the fractures is 100 psi and average injection water viscosity is 0.5 cp. Find: The circulating standpipe pressure at the top and bottom of the formation. Harold Vance Department of Petroleum Engineering Example Formation Top Formation Top PSPPstatic 4,156 psi ΔPDP 710 psi ΔPDC 0 psi ΔPMWD 150 psi ΔPMotor 400 psi ΔPBit 100 psi ΔPfrac 100 psi Formation Bottom 4,129 psi 948 psi 0 psi 150 psi 400 psi 100 psi 100 psi Formation Top: 4,156+713+0+150+400+100+100=5,616 psi PSPINJECTION Formation 4,129+948+0+150+400+100+100=5,827psi PSPINJECTION Harold Vance Department of Petroleum Engineering Bottom: Example If the circulating system is limited to only 5,000 psi in the If example above, the injection fluid density can be increased to lower the required injection pressure. If the injection fluid is changed to 10.0 ppg (average viscosity of 0.8 cp), then the standpipe pressures will be as follows: PSPPstatic ΔPDP ΔPDC ΔPMWD ΔPMotor ΔPBit ΔPfrac Formation Top = = = = = = = 3,120 psi 915 psi 0 psi 150 psi 400 psi 120 psi 100 psi Formation Bottom 3,050 psi 1,222 psi 0 psi 150 psi 400 psi 120 psi 100 psi PSPINJECTION Formation Top: 3,120+915+0+150+400+120+100= 4,805psi PSPINJECTION Formation Bottom: Harold Vance Department of Petroleum Engineering 3,050+1,222+0+150+400+120+100=5,042psi Fluid Volume Requirements Fluid Volume Requirements The drillpipe injection rate during Mudcap operations can be expressed simply as: QDP = 0.0408 (IDHole2 ­ ODDrillpipe2)/AV Where: QDP injection rate down the drillpipe, gpm IDHole hole or casing inside diameter, in. ODDrillpipe drillpipe outside diameter, in. AV annular velocity across drillpipe­casing annulus, ft/min. Harold Vance Department of Petroleum Engineering Fluid Volume Requirements Fluid Volume Requirements The cumulative daily drillpipe injection volume consumed may be expressed as: QDP DailyCum = (18/24)QDP(60)(24/42) This assumes 18 hrs of circulation/injection over a 24­ hour period. Where: QDP DailyCum QDP daily cumulative injection volume down the drillpipe, bbls defined by equation above Harold Vance Department of Petroleum Engineering Fluid Volume Requirements Fluid Volume Requirements Given: MCD is planned for a 6 1/8­in. hole using 3½­in., 13.3 lb/ft drillpipe and 4¾­in. mud motor. Assume desired minimum AV = 100 ft/min Find: Minimum injection rate and minimum daily consumption of injection fluid. QDP = 0.0408 (6.125 2 – 3.5 2)/100 = 103 gpm QDP DailyCum = 25.7*103 = 2,649 bbls/day Harold Vance Department of Petroleum Engineering Fluid Volume Requirements Annular volumes will depend Annular upon whether the operator desires continuous or periodic injection of annular fluids or whether a floating mudcap is to be used. Harold Vance Department of Petroleum Engineering Fluid Volume Requirements Fluid Volume Requirements The amount of fluid to inject into the annulus periodically can be estimated by: QAnn = (SF)VHMTPI(IDHole2 ­DDrillpipe2)/1,029 Where: QAnn periodic annular injection volume, bbls. SF safety factor VHM hydrocarbon migration rate, ft/min. T PI time period between injection volumes, min. IDHole hole or casing inside diameter, inc. ODDrillpipe drillpipe outside diameter, inc. Harold Vance Department of Petroleum Engineering Fluid Volume Requirements Fluid Volume Requirements An estimate of the cumulative volume injected into the annulus daily can be determined with: QAnn Daily Cum = 24*60*QAnn/TPI Where: QAnn Daily Cum annular daily cumulative injection volume, bbls/day. QAnn periodic annular injection volume, bbls. T PI time period between injection volumes, min. Harold Vance Department of Petroleum Engineering Example Example Given: MCD is planned for a sour gas well in a fractured reservoir. Use a gas migration rate of 15 ft/min. A 6 1/8­in. hole is planned to be drilled using 3½­in., 13.3 lb/ft drillpipe. Use the periodic injection method with time between injection periods equal to 30 minutes. Assume a safety factor of 2. Find: The minimum daily annular fluid or mudcap volume requirement. QAnn = 2*15*30*(6.125 2 ­3.5 2)/1,029 = 22 bbls. QAnn Daily Cum = 24*60*22/30 = 1,060 bbls/day Harold Vance Department of Petroleum Engineering Snub Drilling Snub Drilling UBD operation utilizing a snubbing unit or coiled tubing unit. Expense is justifiable if very high formation pressures are anticipated, and uncontrollable loss of circulation is expected. Harold Vance Department of Petroleum Engineering UPPER CABLE GUIDE SNUBBING CABLES COUNTER BALANCE WEIGHTS SNATCH BLOCK PIPE GUIDE TRAVELING SLIP ASSEMBLY STAND GUIDE OPERATOR’S SLIP CONSOLE OPERATOR’S BOP CONSOLE WORK BASKE T STATIONARY SLIP ASSEMBLY SHEAVES SWIVEL BASE ASSEMBLY Harold Vance Department of Petroleum Engineering DUAL SHEAVE DROWN SWIWEL STARTING VALVE TONG ARM POWER TONG QIN POLE TRAVELING SLIPS ROTARY TABLE KELLY HOSE CONTROL CONSOLE WORK BASKET PIPE ELEVATOR DUAL WINCH STATIONARY SLIPS STAND PIPE STRIPPER BOP RISER SPOOLS PIPE RACKS HYDRAULIC EQUALIZING VALVES POWER PACK FUEL TANK TOOL BOX PUMP MANIFOLD HOSE BASKE T Harold Vance Department of Petroleum Engineering 7” 26# @ 8128’ Pilot hole dressed off to 8285” Top of productive interval @ 8157’ KOP @ 8302’ 60 deg 6­1/8” Hole to 8550’ 4­3/4” Hole SHALE Target Center FORMATION DIP 6­80 N 820E (Secondary Target) SHALE (Primary Target) 8558’ 8578’ 8594’ 8618’ Pilot Hole Top of SHALE 8821’ Harold Vance Department of Petroleum Engineering Drilling Spool 7­1/16”, 10M x 7­1/16”,5M RIG FLOOR Cameron single 7­ 1/6”, 10M Annular Preventer Cameron 7­1/16”, 10M Cameron “U” double 7­1/16”, 10M Install companion flange w/2” WECO 1502 thread Drilling Spool 7­ 1/16”, 15M x 10M Cameron “U” double 7­1/16”, 15M DSA 7­1/16”, 10M x 7­1/16”, 15M Frac Valve 7­ TUBING HEAD 1/16”, 10M 11”, 5M x 7­1/16”, 10M Outlet with (2) 1­13/16” 10M Gate Valve SOW CASING HEAD 11”, 5M x 9­ 5/8”, BOP stack ( courtesy of Signa Engineering Corporation) Harold Vance Department of Petroleum Engineering FLARE PIT 6” GAS 6” GAS Gas LIQUID Buster LIQUID SKIMMER Gas Buster 4” GAS MUD PIT ADJUSTABLE MANUAL CHOKE DRILLING FLUID RETURN SAND SEPARATER ALL GAS MANUAL CHOKE HYD.L CHOKE DRILLING FLUID RETURN GAS + LIQUID Prevailing Wind Direction WELLHEAD Snub drilling choke system ( courtesy of Signa Engineering Corporation) Harold Vance Department of Petroleum Engineering Closed Systems Closed Systems Refers to UBD operations with a specific surface system. A pressurized, four phase separator and a fully closed surface system, is used to handle the returned fluids. Harold Vance Department of Petroleum Engineering Ignitor Flere Stack Sample Catcher Production Tank Pressure Vessel Choke Manifold Stack N2 Pumpers Mix Drilling Fluid Tank Rig Pump Vaporizor A typical closed surface system (modified after Lunan, 1994 2). Harold Vance Department of Petroleum Engineering Rotating Blow out Rotating Blow out Preventer/Diverter Preventer/Diverter RBOP Height 1700 mm To Shala Shaker RBOP ESD Northland Manifold 6” Gate Valve Annular Returns to Choke Manifold and Separator 4” Globe Valves Annular Preventer 127mm (5”) Pipe Rams Kill Line Wills Choke Kill Line Tubing Spool Flare Stack Choke Line Connected to Northland Separator Manifold Shear/Blind Rams 127mm (5”) Pipe Rams Sample Catchers Choke Line Connected to Rig Manifold Choke Separator 200 psi Vessel Rig Manifold Water Returned to Oil Storage/ Rig Tanks Transport HCR Choke Flare Pit Casing Spool Surface Casing 300­400m, 508.0mm Intermediate Casing 1300­1450m, 339.7mm Production Casing 1890m, 244.5mm Flow control arrangement (after Saponja, 19957). Harold Vance Department of Petroleum Engineering Flow Direction Output Data Header Valve #2 Sample Catcher #1 Sample Catcher #2 Full Bore Valve #2 Valve #3 Full Bore Valve #1 Valve #1 Choke Bypass Well Effluents Flow Direction Input Data Header Valve #4 Integrated flow control and sample catcher manifold (after Lunan and Boote, 199412). Harold Vance Department of Petroleum Engineering Well Effluents In Adjustable Partition Plates Gas Out Gas Gas Velocity Reducer Continuous Pressurized Solids Transfer Pump A typical, horizontal, four­phase separator, for underbalance drilling (after Lunan and Boote, 199412). Harold Vance Department of Petroleum Engineering Other Surface Equipment Other Surface Equipment Cuttings filter. Heater. Degasser. Flare stack/pit. Production tank. Water tank. Solids tank. Instrumentation. Harold Vance Department of Petroleum Engineering ...
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This note was uploaded on 10/30/2011 for the course PETROLEUM 689 taught by Professor Jeromej.schubert during the Fall '11 term at Texas A&M University-Galveston.

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