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Lesson 10 Flow Drilling Mudcap Drilling Snub Drilling Closed Systems

PETE 689 Underbalanced Drilling (UBD). Lesson 10 Flow Drilling Mudcap Drilling Snub Drilling Closed Systems Read: UDM Chapter 2.8-2.11 Pages 2.180-2.219. Harold Vance Department of Petroleum Engineering. Flow Drilling.

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Lesson 10 Flow Drilling Mudcap Drilling Snub Drilling Closed Systems

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  1. PETE 689 Underbalanced Drilling (UBD) Lesson 10 Flow Drilling Mudcap Drilling Snub Drilling Closed Systems Read: UDM Chapter 2.8-2.11 Pages 2.180-2.219 Harold Vance Department of Petroleum Engineering

  2. 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

  3. Flow Drilling Clear drill brine density less than or equal to 1.02 g/cm3 Oil, Gas, and Brine 9.5 ppg Brine Pressure lower in TOE of well causes influx Pressure higher in HEEL of well causing lost returns Pore Pressure =3030 psi at 6234 ft Flowdrilling a naturally fractured horizontal well (courtesy of Signa Engineering Corporation) Harold Vance Department of Petroleum Engineering

  4. 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

  5. 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

  6. Surface Equipment 12 in. Flare 6 in. Flare 4-6 in. 4 in. Flare Gas boot (open on bottom) Water to rig Grade Gas Separator Gas Separator Skimmer tanks Choke Manifold ROP Annular Preventer Oil tank Pipe Rams Blind Rams Oil to treatment off location Pipe Rams Atmospheric surface system for flowdrilling (courtesy of Signa Engineering Corporation) Harold Vance Department of Petroleum Engineering

  7. Surface Equipment RBOP Choke Line Typical flowdrilling BOP stack (courtesy of Signa Engineering Corporation) Harold Vance Department of Petroleum Engineering

  8. Surface Equipment Rotating blowout preventer (RBOP). Harold Vance Department of Petroleum Engineering

  9. Surface Equipment Kelly Packer Hydraulic Fluid Nitrile RBOP sealing elements Harold Vance Department of Petroleum Engineering

  10. Surface Equipment Manual Choke Hydraulic Choke A typical flowdrilling choke manifold (courtesy of Signa Engineering Corporation) Harold Vance Department of Petroleum Engineering

  11. Sizing Flare Line Weymouth’s equation can be used to predict the pressure drop for a gas, in steady-state, adiabatic, flow along the pipe:… Harold Vance Department of Petroleum Engineering

  12. Sizing Flare Line To d16/3(P21-P22) Po STLZa 2.73 Q = 433.5 Where: Q gas flow rate (scf/D) dinside diameter of the pipe (the gas flare line in this case) (inches) To standard temperature (520 oF) Po standard pressure (14.7 psia) S gas gravity (air = 1) 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

  13. Sizing Flare Line …Weymouth's Equation 2.73 incorporates a friction factor, f = 0.032/d1/3 Harold Vance Department of Petroleum Engineering

  14. Sizing Flare Line Assuming a gas gravity of 0.6, and substituting for standard temperature and pressure, Equation (2.73) becomes: d16/3(P21-P22) TL 2.74 Q = 19,754 Harold Vance Department of Petroleum Engineering Harold Vance Department of Petroleum Engineering

  15. 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 2.06d16/3 2.75 P1 = + P22 Harold Vance Department of Petroleum Engineering

  16. Sizing Flare Line The pressure differential exerted by the U-tube head can be expressed as: P1 – P2 = 0.433ρh 2.76 Where: Ρ specific gravity of the fluid in the U-tube or separator. hheight from the top of the gas boot to the bottom of the U-tube (feet). Harold Vance Department of Petroleum Engineering

  17. Sizing Flare Line Equations (2.75) and (2.76) can be combined to solve for the U-tube height, in terms of the gas flow rate, temperature, outlet (atmospheric) pressure, and flare line diameter: Q2TL 2.06d16/3 2.77 + P22 - P2 h = 0.433ρ Harold Vance Department of Petroleum Engineering

  18. 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

  19. Operating Procedures • Mechanical objectives during flow drilling are: • To control the well. • Minimize differential sticking problems. • Minimize drilling fluids losses. • Maximum tolerable surfaces pressures should be established before drilling starts. Harold Vance Department of Petroleum Engineering

  20. 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

  21. 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 non-damaging fluid down the drillstring through the bit and into the thief zone. Harold Vance Department of Petroleum Engineering

  22. 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

  23. 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

  24. Mudcap Drilling GAS BUSTER To flare pit MUD PITS RIG FLOOR Chemical Injection HCR Valve (Closed) MUD PUMPS CHOKE (closed) DIVERTER Schematic of equipment required for mudcap drilling (courtesy of Signa Engineering Corporation) Harold Vance Department of Petroleum Engineering

  25. Pore Pressure Bore Hole Pressure PP Datum Determining Pore Pressure Pressure, psi 9,200 9,400 9,600 9,800 11.8 12.0 12.2 Depth (TVD)/ 1,000, ft. 12.4 12.6 12.8 Determining the Reservoir Pressure Along the Wellbore Harold Vance Department of Petroleum Engineering

  26. Static Standpipe Pressures PSPPstatic= 0.052 (EMWpore pressure- MWinjection fluid)TVD Where: PSPPstaticstatic standpipe pressure, psi. EMWpore pressureequivalent mud weight of formation pore pressure, ppg. MWinjection fluiddensity of the injection fluid, ppg. TVDtrue vertical depth of the top of reservoir, ft. Harold Vance Department of Petroleum Engineering

  27. Example Given: Reservoir described in Figure 3-1-2. Injection fluid is fresh water with no additives. A lateral is planned to intersect the formation top at 12,750’ MD (12,000’ 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 14.7 ppg MWinjection fluid 8.34 ppg 8.34 ppg TVD 12,000 ft 12,500 ft PSPPstatic 0.052*(15-8.34)*12,000’ 0.052*(15-8.34)*12,000’ = 4,156 psi 4,129 psi Harold Vance Department of Petroleum Engineering

  28. Dynamic Standpipe Pressures PSPINJECTION = PSPPstatic+ΔPDP+ΔP Drill collars+ΔPMWD+ΔP Motor+ΔP Bit+ΔP frac Where: PSPINJECTIONstandpipe pressure while circulating or injecting down drillpipe.. PSPPstaticstatic standpipe pressure, psi. ΔPDPfrictional pressure drop of fluid flowing down drillpipe. ΔP Drill collarsfrictional pressure drop of fluid flowing down drill collars. ΔPMWD pressure drop across the measurement-while drilling tool. ΔP Motor pressure loss to power motor. ΔP Bitpressure drop across bit nozzles. ΔP fracfrictional pressure drop of fluid flowing through fractures. Harold Vance Department of Petroleum Engineering

  29. Example Given: The reservoir described above. A directional hole is to be drilled with a 4¾-in. mud motor that requires a flow rate of 240 gpm resulting in a 400-psi on-bottom 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 3½-in. 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

  30. Example Formation Top Formation Bottom PSPPstatic4,156 psi 4,129 psi ΔPDP 710 psi 948 psi ΔPDC 0 psi 0 psi ΔPMWD 150 psi 150 psi ΔPMotor400 psi 400 psi ΔPBit100 psi 100 psi ΔPfrac100 psi 100 psi PSPINJECTION Formation Top: 4,156+713+0+150+400+100+100=5,616 psi PSPINJECTIONFormation Bottom:4,129+948+0+150+400+100+100=5,827psi Harold Vance Department of Petroleum Engineering

  31. Example If the circulating system is limited to only 5,000 psi in the 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: Formation Top Formation Bottom PSPPstatic = 3,120 psi 3,050 psi ΔPDP =915 psi 1,222 psi ΔPDC = 0 psi 0 psi ΔPMWD = 150 psi 150 psi ΔPMotor = 400 psi 400 psi ΔPBit = 120 psi 120 psi ΔPfrac = 100 psi 100 psi PSPINJECTION Formation Top: 3,120+915+0+150+400+120+100= 4,805psi PSPINJECTIONFormation Bottom: 3,050+1,222+0+150+400+120+100=5,042psi Harold Vance Department of Petroleum Engineering

  32. 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 drillpipe-casing annulus, ft/min. Harold Vance Department of Petroleum Engineering

  33. 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 daily cumulative injection volume down the drillpipe, bbls QDP defined by equation above Harold Vance Department of Petroleum Engineering

  34. Fluid Volume Requirements Given: MCD is planned for a 6 1/8-in. hole using 3½-in., 13.3 lb/ft drillpipe and 4¾-in. 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

  35. Fluid Volume Requirements Annular volumes will depend 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

  36. 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

  37. 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

  38. 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 1/8-in. hole is planned to be drilled using 3½-in., 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

  39. 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

  40. UPPER CABLE GUIDE SNUBBING CABLES COUNTER BALANCE WEIGHTS SNATCH BLOCK PIPE GUIDE TRAVELING SLIP ASSEMBLY STANDGUIDE OPERATOR’S SLIP CONSOLE OPERATOR’S BOP CONSOLE WORK BASKET STATIONARY SLIP ASSEMBLY SHEAVES SWIVEL BASE ASSEMBLY Harold Vance Department of Petroleum Engineering

  41. DUAL SHEAVE DROWN SWIWEL QIN POLE STARTING VALVE TRAVELING SLIPS TONG ARM ROTARY TABLE KELLY HOSE POWER TONG CONTROL CONSOLE PIPE ELEVATOR WORK BASKET DUAL WINCH STATIONARY SLIPS STAND PIPE HYDRAULIC EQUALIZING VALVES STRIPPER BOP POWER PACK FUEL TANK TOOL BOX RISER SPOOLS PIPE RACKS PUMP MANIFOLD HOSE BASKET Harold Vance Department of Petroleum Engineering

  42. 7” 26# @ 8128’ Top of productive interval @ 8157’ KOP @ 8302’ Pilot hole dressed off to 8285” 60 deg 6-1/8” Hole to 8550’ 4-3/4” Hole FORMATION DIP 6-80 N 820E 8558’ (Secondary Target) SHALE 8578’ SHALE Target Center 8594’ (Primary Target) 8618’ Pilot Hole Top of SHALE 8821’ Harold Vance Department of Petroleum Engineering

  43. Drilling Spool 7-1/16”, 10M x 7-1/16”,5M RIG FLOOR Cameron single 7-1/6”, 10M Annular Preventer Cameron 7-1/16”, 10M Cameron “U” double 7-1/16”, 10M Install companion flange w/2” WECO 1502 thread Drilling Spool 7-1/16”, 15M x 10M Cameron “U” double 7-1/16”, 15M DSA 7-1/16”, 10M x 7-1/16”, 15M Frac Valve 7-1/16”, 10M TUBING HEAD 11”, 5M x 7-1/16”, 10M Outlet with (2) 1-13/16” 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

  44. FLARE PIT 6” GAS LIQUID Gas Buster LIQUID 6” GAS Gas Buster SKIMMER 4” GAS DRILLING FLUID RETURN ALL GAS MUD PIT ADJUSTABLE MANUAL CHOKE HYD.L CHOKE MANUAL CHOKE DRILLING FLUID RETURN GAS + LIQUID SAND SEPARATER Prevailing Wind Direction WELLHEAD Snub drilling choke system ( courtesy of Signa Engineering Corporation) Harold Vance Department of Petroleum Engineering

  45. 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

  46. Ignitor Flere Stack Sample Catcher Stack Pressure Vessel Choke Manifold Production Tank N2 Pumpers Mix Drilling Fluid Tank Vaporizor Rig Pump A typical closed surface system (modified after Lunan, 19942). Harold Vance Department of Petroleum Engineering

  47. Rotating Blow out Preventer/Diverter Rotating Blow out Preventer/Diverter To Shala Shaker RBOP ESD Northland Manifold RBOP Height 1700 mm 6” Gate Valve Sample Catchers Annular Returns to Choke Manifold and Separator 4” Globe Valves Annular Preventer Wills Choke 127mm (5”) Pipe Rams Flare Stack Choke Line Connected to Northland Separator Manifold Kill Line Separator 200 psi Vessel Shear/Blind Rams Rig Manifold Choke Choke Choke Line Connected to Rig Manifold 127mm (5”) Pipe Rams Water Returned to Rig Tanks Oil Storage/ Transport Kill Line HCR Tubing Spool Flare Pit Choke Casing Spool Surface Casing 300-400m, 508.0mm Intermediate Casing 1300-1450m, 339.7mm Production Casing 1890m, 244.5mm Flow control arrangement (after Saponja, 19957). Harold Vance Department of Petroleum Engineering

  48. Flow Direction Output Data Header Valve #2 Sample Catcher #1 Sample Catcher #2 Valve #3 Full Bore Valve #2 Full Bore Valve #1 Valve #1 Choke Bypass Well Effluents Input Data Header Valve #4 Flow Direction Integrated flow control and sample catcher manifold (after Lunan and Boote, 199412). Harold Vance Department of Petroleum Engineering

  49. Well Effluents In Adjustable Partition Plates Gas Out Velocity Reducer Gas Gas Continuous Pressurized Solids Transfer Pump A typical, horizontal, four-phase separator, for underbalance drilling (after Lunan and Boote, 199412). Harold Vance Department of Petroleum Engineering

  50. 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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