Les enjeux de l`extraction pétrolière en conditions extrêmes non
Transcription
Les enjeux de l`extraction pétrolière en conditions extrêmes non
Les enjeux de l’extraction pétrolière en conditions extrêmes non conventionnelles Arnaud ETCHECOPAR SCHLUMBERGER Quality Low Perm Tight Gas Unconventional Oil Sands • large volumes • difficult to Gas Shales HP-HT Heavy Coalbed develop Oil Methane Gas Hydrates Oil Shales Improved Technology Conventional Resources •small volumes High – •easy to develop Medium Increasing Pricing RESOURCE TRIANGLE Nouveaux objectifs • • • • Tight sands gas (very low permeability) Center basin shales (source rocks) Heavy oil (viscosity problems) Low resistivity carbonates (impossible to evaluate using conventional resistivity methods) • Hydrates • Increasing oil recovery – Estimation of the remaining oil – decrease the oil wetability – Improvement of the exchanges matrix to fracture Nouvelles conditions • High temperature, High pressure • Ultra deep offshore Sismique dans l’artique? Tight sand gas U.S. Annual Percentage of Gas vs. Oil Rigs Operating 100.0% 90.0% 80.0% 70.0% 60.0% Percent of Gas Rigs 50.0% Percent ofOil Rigs 40.0% 30.0% 20.0% 10.0% 0.0% 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 U.S. Natural Gas Production Per Well 200 180 160 MMcf/Well 140 120 100 80 60 40 20 0 70 72 74 76 78 80 82 84 86 88 90 92 94 96 98 00 02 Tight Gas Development Challenges • Mainly geomechanical problems • Long intervals of stacked sands (500-1000m) – – – – – All zones require hydraulic fracturing Optimizing frac designs Optimizing number of frac stages Differential depletion Stress profile and rock properties • Very close well spacing required – Well spacing and positioning – Length/ orientation of fracs • High efficiencies required (low margins) p0 p1 p2 Center basins shales (source rocks) (micro to nano Darcy) • What are they? – Organic-rich shales – Source rocks – TOC : Adsorbed and free gas Common traits of gas shale reservoirs – Abundant gas (40 to 120 BCF/section) – Very low permeability (no production if no fracture) – Low recovery efficiency (8 to 12%) – Require natural fracture stimulation, then produce much more than expected from Darcy’s lows – Horizontal wells – Long well life Longitudinal View of Microseismic Events Scaled by Occurrence 8,600 8,800 9,000 Depth (TVD) (ft) • 9,200 9,400 Events from Start of Pumping-15:25 Haygood Lois #10 Perforations: Geophones 9,600 9,800 -1,200 -1,000 -800 -600 -400 -200 0 200 400 Distance Along Projection (ft) 600 800 1,000 1,200 Low resistivity carbonates Archie : Sw=80-90% .525 psi/ft water .454 psi/ft water 5450 BOPD, 0WC Resistivity from close wells : similar Rt, different Sw OIL Water Wetability Which measurement to replace resistivity? Increasing oil recovery – Estimation of the remaining oil, not so obvious • An objective for seismic methods? – decrease the rock wetability to oil • How chimical fluids diffuse inside rocks? – Improvement of the exchanges between matrix and fractures How to manage fractured reservoirs? ? 100m From borehole images it is possible to describe precisely a fractured reservoir (orientation, density, aperture, length etc) but…Oil recovery factors significantly lower than average (<< 35%) How to optimize fractured reservoir producibility? N A Common Scenario: Excellent initial production from the oil contained in fractures, followed by rapid depletion What is the best trajectory to produce such a reservoir? In case of water coning, is it possible to accelerate the exchanges between the matrix and the fractures? Another Common Scenario: Reservoir under water injection Porosity <15%, permeability < 5 mD, strongly oil-wet matrix, and connected fractures ÎVery limited water imbibition in the oil-wet matrix Æ Very low recovery factor < 10% Definition of High-pressure, Hightemperature (HPHT) Environment Global HPHT Fields and Prospects – HPHT wells begin at 150 degC [302 degF] and 68.95 MPa [10000 psi] – Ultra-HPHT wells begin at 205 degC [401 degF] and 137.90 MPa [20000 psi] – HPHT-hc wells have bottomhole conditions greater than 260 degC [500 degF] and 241.32 MPa [35000 psi] 650 HPHT-hc South Sumatra - HO Liaohe (HO) Reservoir Temperature Deep Gas (Antietam?) Salak mountain, West Java (Steam) 550 PDO South Oman (HO) 450 PDO Central Oman (HO) Oxy South Oman (HO) UltraHPHT Gulf of Thailand South Umm Gudair Eocene (HO) Krishna Godawari Scorpio (North Padre Island) Mobile Bay Victoria Jackdaw Xinjiang Pemex South 350 UDW Angola Khuff D HPHT Thunderhorse Jack 250 Kaskida Tubular Bells Tahiti Mad Dog 150 0 5000 10000 15000 20000 25000 30000 35000 Reservoir Pressure This definition does not specify, nor depend on, the source of heat or pressure. (i.e. wells having a source of heat introduced to the well bore for extraction purposes can still be governed by this definition.) Source document: HPHT Definition v1.doc Wells vs Burial Depth Burial Depth (m) Year Joseph Deep Offshore Knotty Head Slide source: Deeply Buried Reservoir Project - TOTAL presentation to SLB Jan. 2007 Original data source: IHS 2005 Why is HPHT Different? •Effects of high-pressure impacts: •Effects of high-temperature: – Formation – Thermal expansion/contraction • • • Pore pressure Fracture pressure Compaction and effective stress (slower ROP) – Wellbore • • • • • Drilling mud density Completion fluid density Cement density, viscosity Downhole tools (MWD, LWD, WL, Testing, Completions, AL) Tubulars – Surface Equipment • BOPs, wellheads • • • • • reservoir fluids wellbore fluids Cement (and spacers) tubulars seals – Electronics • • stability longevity – Surface Equipment • Handling of mud and drill pipe Much less measurements … and usually accompanied by significant concentrations of H2S and CO2. HPHT Operations – Drilling Challenges •Well Placement – Adequate ratings (P&T) for all equipment used in drilling wells in “conventional” environment (Motors, RSS, MWD) – Casing wear/increased exposure as a result of slower ROP Well Control – ECD management – Pore pressure is near frac gradient, drilling fluid density, rheology, surge/swab pressure . – Mud loss is an issue due to lithology and geopressure. – Hole ballooning causes mud storage problems. The walls of the well expand outward because of increased pressure during pumping. When pumping stops, the walls contract and return to normal size. Excess mud is then forced out of the well. – Borehole stability – geomechanics modeling – Fluid stability – Water-based mud realistically works to 425°F while oil and synthetic mud is stable up to 500°F. Gas solubility in OBM. – Early kick detection –significant gas expansion from bottomhole conditions to surface. Slow ROP or Non-Productive Time – Drilling in HPHT formations are 10% of normal drilling conditions – Stuck pipe and twisting off – Trip Time – caused by tool failure (LWD/MWD) and bit trips – Suboptimal decision making caused by lack of XHPHT experience (the “learning curve”) – Safety issues associated with handling hot drilling fluids, hot drill strings HPHT Operations – Cementing Challenges Performance – Fluid properties • Gas flow must be controlled (significant in HPHT environment) . • Pumpable and stable/homogeneous at elevated temperature/pressure • Filtrate loss must be controlled at BHCT • Compatible with all well fluids at BHCT • Limited shrinkage over time • Consider formation damage issues – Mechanical properties • Adequate strength for long-term structural integrity • Wellbore strengthening/stability products to reach targets • Must provide a good shear bond • Low permeability – H2S and CO2 stability Design and Test – Rheological model – accurate computer simulations and rheology measurements that occur in downhole conditions are required in predicting wellbore pressures during cement placement. – Lab testing at BHST/BHP – No standards of test format for use with HPHT wells. – Alternative Sealants –replacements for conventional Portland cement. Operations – Sealant Density Control – Equipment must be capable of mixing high density sealants accurately. – Bond Logs and Evaluation – Ensure zonal isolation and bond to the formation and the pipe. – Friction Pressure – to take into account for very long work strings that may be encountered. – Optimizing Placement – Develop procedures and methods to optimize drilling fluid displacement during cement jobs in HPHT conditions. – Equipment ratings – plug and float, ECP’s, Liner Packers HPHT Operations – Completion Challenges •Fluids – Expansion, upper limits to fluid density, stability, corrosion – Formation compatibility Flow Assurance – Temperature limits of inhibitors, high injection pressures – Compatibility with well effluents Equipment Ratings/Reliability – Time/temperature stability of (perforating) explosives, gun pressure ratings – Measurements (sensors and system longevity) – Seal longevity (dynamic, metal-metal, new polymers) – Packer performance – rig time (intervention), casing stress from slips – Metallurgy – Thermal cycling and tubing stresses •Operations – Intervention rig time (especially subsea) and equipment specs – Training in HPHT operations Equipment Testing Facilities Conclusion • Ca fait beaucoup de changements pour une industrie tres conservatrice…