and fracturing technology issues in tight gas development（致密气藏开发中的储层和压裂技术问题）课件

SPE Calgary Section Reservoir and Fracturing Technology Issues in Tight Gas Development A . (Tony) Settari University of Calgary TAURUS Reservoir Solutions, Calgary With contributions from R.C. (Bob) Bachman TAURUS Reservoir Solutions, Calgary Outline A bit of history of tight gas development Sampling of technology issues/advances: Reserves estimation PTA special issues for tight gas Modeling Frac treatment analysis/optimization Frac length vs conductivity Waterfracs Geomechanics - Shear fracturing Frac monitoring and links to geophysics Summary A bit of history of tight gas Onshore North America since the 1970s Tax incentives in the US in 1980s spurred technology, first foray into CBM business and shales Large amount of technology developed in 1980s: Driven by belief in “bigger is better” and “adding reserves by fracturing” Persistent low prices in the 1990s slowed R&D (with exceptions) Technology packaging and user friendliness Current scene Revival of tight gas on international scale (until summer 2008 ) Unconventional gas (TG, shale, CBM,) share rising Development of monitoring technology and geomechanical aspects jub size (lb of proppant) 9068867894980066707482 19201919191919191919192020 0406 A bit of history Schematic of the history of propped frac job sizes (Cotton Valley, Wilcox Lobo, U.S.) evolution of frac size (schematic) 1,400,000 1,200,000 1,000,000 800,000 600,000 400,000 200,000 0 year Maximum job size pumped: 7 MM lb of sand (Mobil, GHR in W. Texas) Reservoir characterization challenges Geology and stratigraphy Faulting Lenticular sands Channels and complex features Shale/sand sequences Fracture characterization Seismic methods Wellbore imaging DFM modeling Production, PTA, Integration of methods improves quality of characterization Reserves estimation Tight gas one possible definition: Permeability 1.0 (Not supported by theory?) Calendar Day Gas Rate (103 m3/d) 10 1 Reserves by Decline curves - Semilog plot of gas rate vs time 100 05001,0001,5002,0002,5003,0003,5004,000 Cumulative Gas (103 m3) harmonic exponential hyperbolic Super- harmonic decline? A “fix”: composite decline models 1. Initial Super-Harmonic decline 2. Hyperbolic decline model “bolted” on to Super-Harmonic model at some time 3. Minimum decline rate specified Prevents extremely low decline rates Not very satisfactory because the flow can be transient for a long time Boundary Affected Flow Transient Flow Cannot Use Arps Decline Curves in Transient Flow Regime: SPE 28628 Fetkovich (1994) Diagnostic of Fully Bounded Flow, Slope =1 Radial Flow Transients Direction of Increasing Skin 0 Slope = 1/2 slide courtesy of Fekete Associates Inc Fracture (skin) effectsReservoir effects Calendar Day Gas Rate (mscf/d) Example: slope seen on Fetkovich plot Problem: How to resolve the ambiguity? Are we seeing the effect of a fracture or of reservoir Assume no boundary dominated flow: OGIP=16 Bcf, Area=346 acres Assume boundary dominated flow starts: OGIP=4 Bcf, Area=83 acres 10 1,000 100 geometry? 10,000 10100,000100 1,000 10,000 Time from Start of Wells Production (days) P100 Line Bounded Flow P0 Line Linear Flow Forever PBU, PLTs etc. Anisotropic permeability Complex stratigraphy and reservoir characterization Single model for How can we do better ? Numerical model integrating simulation of: Frac job Goal: Account for all factors and match all data SIMULTANEOUSLY to obtain REALISTIC predictions Stress-strain model Injection/production Cleanup Long term production (incl. multiphase effects) Multiphase reservoir model W fcauses stress+displ. Waterblockage andcleanup entire sequence of events Propagation controlled byfracmech +flow Dynamicfracture duringpumping Conductivefracture Dynamicfracwidth duringproduction/PBU W fandvolume Example: Interpreting early PTA Tests Test done before the well was tied in Needed to run test shortly after treatment because of convenience and timing issues Frac fluid produced to start of first PTA = 165.7 m3 Frac Fluid Recovery = 43% Short frac length from PTA 16 m Calendar Day Gas Rate (103 m3/d) Dm (kPaa2/cp) 1 10 1,000 11000 10 100 Time from Start of Wells Production (days) 1.0E+08 Observed Initial Production Forecast 1.0E+11 1.0E+07 0.010.10100.001000.00 1.00 10.00 Delta Time (hours) Dm Deriv - observed Post Frac Analysis Frac Length = 16 m 1.0E+10 100 1.0E+09 Dm - observed Simulation match of the 1st PTA + production Interpreted frac length from 1st PTA = 16 m Initial production forecast higher than actual was the job bad? Long linear flow? What Went Wrong bad frac job or bad analysis? Second PTA test run after 300 days Showed full frac length of 160 m Numerical model was run to obtain simultaneous match of Early 1st buildup Cleanup Production 2nd buildup Calendar Day Gas Rate (103 m3/d) Dm (kPa2/cp) Dm (kPa2/cp) Interpretation resulting from modeling both buildups and production Early time PTA fracture length obscured by frac treatment fluid near wellbore (equivalent to shorter frac) Long term linear flow due to flow anisotropy - Kx/Ky = 400 1 100 10 1,000 1101001000 Time from Start of production (days) 1.0E+09 1.0E+08 1.0E+10 1.0E+11 1.0E+07 0.0010.0100.1001.00010.000 100.000 1000.00 0 Delta Time (hours) 1.E+09 1.E+08 1.E+10 1.E+07 0.010.101.0010.00100.001000.00 Delta Time (hours) Frac design optimization issues Optimization of length vs conductivity Principles known for 20+ years, practised Recently re-introduced for tight gas Poor fracture conductivity New field technology Waterfracs Monitoring Shear fracs Fracture conductivity issue: Common problem: “Low” fracture conductivity (compared to design values) Design based on: published prop conductivity data closure stress at estimated BHP for design rate Typical outcome: Order of magnitude lower frac conductivity than design (based on the gas rate and BHP) Many field cases exist. Texas waterfracs conductivity 20-50 md-ft for 0.5 MM lb of proppant! How it May Happen: Cumulative effect . Gel damage to prop - factor 0.3-0.7 Water saturation in the fracture - gas perm reduced by 0.5 - 0.1 (depending on cleanup) To keep the rate, BHP is decreasing - prop base k drops (0.8-0.2 depending on proppant) Gas phase turbulence - factor 1.0 - 0.1 (based on full perforations, smaller with partial perfs !) As BHP decreases, reservoir k may decrease in a stress sensitive formation - factor 1 - 0.1 Cumulative effect one to two orders of magnitude decrease in “apparent” conductivity Calculated Dimensionless Fracture Conductivity 0.010.1110100 Input Dimensionless Fracture Conductivity Relative permeability in the fracture effect on conductivity (SPE 98329) Pressure Transient Test Interpretation 10 Results from Linear Fracture Relative Permeability Data Results from Non-Linear Fracture Relative Permeability Data 1 Unit Slope Line 0.1 0.01 Waterfracs Technology introduced by accident Evolved from “We dont need no proppant” (Mayerhofer + Meehan) to hybrid fracs used today Major drivers Reduced cost of treatment Less damaging Optimization using coupled reservoir and geomechanical models Evolution of Bossier Sand Stimulation Practices 199919981997199619952000200120022003 Large Conventional Polymer Gel Treatments High-concentration polymer gels (40 to 50 lbs guar per 1000 gal fluid) Large sand volumes (100,000 to 300,000 lbs 20/40 proppant) Small Slick Water-Fracs 5000 to 10,000 bbls slick water No sand to 40,000 lbs proppant Large Slick Water-Fracs 8000 to 10,000 bbls slick water 100K to 250K lbs proppant Large Hybrid Slick Water-Fracs Inject slick water to create fracture geometry Inject 30 to 35 lbs polymer per 1000 gal fluid to carry proppant 100K to 350K lbs proppant Inj rate (BPD) BHP (psia) BHP (psia) Water rate (bbls/d) Gas rate (MScf/d) 3500 Frac+cleanup+PBU, dynamic fracture, Lfp=220 ft, k=0.01 md 3000 2500 1800 Frac job 1400 1200 1000 800 600 400 200 0 2000 0 102030406070809010050 time (days) 20,000 Field gas rate Qw, 10 layer model match PBU at 84 days, 10 layer model, k=0.01 md 2000 1500 1000 5000 4500 4000 848688949698100 18,000 16,000 90 92 time (days) Field PBU data model match 14,000 12,000 10,000 8,000 6,000 4,000 PBU 2,000 - Typical Bossier Well Overall Match using a coupled modeling system (GEOSIM) Simulated waterfrac, model with dynamic fracture 0 80000 60000 40000 20000 180000 160000 140000 120000 100000 200000 0 0.02 1600 0.040.060.10.120.14 0.08 time (days) 0 Field water cleanup rate Qg, 10 layer model match 6000 4000 12000 10000 8000 14000 model rate field rate model BHIP field BHP (calc from THP) 2000 gas rate MSCFD Inj rate (BPD) BHP (psia) BHP (psia) water rate STBD Gas afterflow rate (mscf/d) BHP (psia) Gas rate (MSCF/d) How close can we get in modeling waterfracs? Tight gas well in Wyoming (SPE 119394) 5500 6000 7000 6500 9500 9000 8500 8000 7500 00.050.10.150.20.250.30.350.4 time (days) 0 10000 30000 20000 80000 70000 60000 50000 40000 A-13 Stage 1 - Final HM, original initial pressures, pfoc 6950 pormult, wbs, variable k matrix, frac kr, variable Tmult in stages obs BHP SRT+mini at 10080 ft obs BHP Junk+main HM4 final match (higher krw) Inj rate PBU July 27, 06, history match 2000 3500 3000 2500 1500 1000 500 0 172 174176 200 150 100 50 0 190 250 450 400 350 300 BHP data model BHP, HM6_ws_0.1 model afterflow 178 180 182 184 186 188 time (days) Stage 3 200 0 1400 1200 1000 800 600 400 0268 4 time (days) 200 0 400 2000 1800 1600 1400 1200 1000 800 600 gas rate data Qg,modelvar2 final_match Water rate data Qw, modelvar2 final_match Fracing sequences Cleanup Well A13 Production match on 160 and 80 acre 3000 2000 1000 0 4000 8000 7000 6000 5000 10000 9000 050100150300350400 200 250 time from Feb 5, 2006 300 200 100 0 450 400 800 700 600 500 1000 900 BHP data gas rate data PLT gas rates HM6_ws_0.1 HM6_ws_0.1_80ac Production, PLTs, Buildup Reserves Spacing Fract design optimizatio n Shear Fracturing Evidence of secondary fracturing and increased permeability (leak-off) Geomechanics needed to analyze Some field cases of very successful wells with small waterfracs Can we exploit it to make consistently better wells? a) primary SPF, no formation failure (classical fracture mechanics) b) combination of SPF and microfracturing or microchanelling (hard rock, granular media) Some possible models of injection into geomaterials c) “Homogenized” model (fracture + enhanced zone + unfailed zone) - successfully used in oil sands, chalk, coal d) Induced matrix fracturing or microchanelling without SPF resultsfromPTA Bestfitexponential Sample15245.8Oriskany Sample25266.0Oriskany Sample35383.7Heldelberg Sample45391.7Heldelberg Sample55634.4Anhydrite Sample65636.4Anhydrite approxfit(y=13.515x-0.3297) Normalized Pore Volume, dPV/PVi, (fraction) Permeability (md) Evidence for the dilation of microfractured rock around Single Plane Fracture Example Brine disposal into Oriskany sandstone (k=0.01 - 0.03 md, =1.5%, but likely microfractured) (SPE REE, April 1999) At fracture face: 1000x k, 3 x ! 0.01 2000 2500300035004500500055006000 4000 pressure (psia) 1 050025003000 1000 1500 2000 Net Stress (decreasing only), psi Porosity ratio /init vs eff stress 3 2.8 2.6 2.4 2.2 2 1.8 1.6 1.4 1.2 Permeability vs eff stress 1000 100 10 1 0.1 Frac monitoring Perhaps the most significant recent technology advance helping to understand fracturing Microseismic (downhole, surface) Borehole tiltmeters Provides bounds on frac length, gives azimuth, but more accurate geometry determination is elusive Often shows surprising asymmetry of frac wings Treated well Typical example of microseismic (Bossier play) Monitor well Can we really tell from microseismic if there is a fracture and how big? Fractured reservoirs: modeling geomechanics and links to geophysics Coupled modeling of flow and deformation in fractured reservoirs is now possible Deformation of fractures affects moduli and seismic velocities Gives possibilities for: Improved seismic interpretation (especially 4-D) Better predictions of well productivity strain functions Coupled modeling for fractured media: detailed model PORFRANC Jointed coupled model develop equivalent continuum properties changing with stress state Flow model Solid model dynamic tensordynamic stress permeability, transition from(equivalent single to dual continuum) porosity! field scale model GEOSIM K tensor = f(time) Analytical model of media with regular joint sets (multiplane theory) detailed model Joint sets Effective modulus (MPa) Links with geophysics: Changes of modulus E with stress state - example P I Effective E as a function of eff stress 4000 2000 0 14000 12000 10000 8000 6000 16000 01101001000 frac spacing 0.2 m frac spacing 2 m Effective stress (MPa) Equivalent E of rock mass with regular set of joints kz,top kz,middle kz,bottom Ez,middle Ez,bottom kz,top kz,middle kz,bottom Ez,top Ez,middle Ez,bottom Equivalent modulus in z dir (MPa) Equivalent modulus in z dir (MPa) fracture z permeability (md) fracture z permeability (md) Links with geophysics: Changes of