Work Process Estimate Stresses and Pressures 1. 2. PCL Well Construction s’Prop kfw i. Determine Fcd and FOI iii. Estimate Fracture Geometry a) b) 4. Young’s’Modulus Sand/Shale σ Fluid Loss – ‘C’ and Spurt Loss 5. Stresses - DFIT a) ii. (Evaluate Various Proppants and Frac Lengths) 3. Calibrate Model 6. Fluid Selection – Apparent Viscosity (cps) Fluid Loss and Efficiency – Minifrac b) i. ii. 7. Upper Bound - SRT Lower Bound - Horner Plot (Pr) Pc - √t , ‘G’, G dP/dG Material Balance P* Pressure History Match (Refine H, E, C Estimates) 8. Economics – Refine Job Size NPV, DROI, Xf, Q, PPG, Proppant and Fluid Volume, Proppant Type Many Stresses/Pressures ! IN SITU STRESSES The Dominant Variable For Hydraulic Fracture Design Dominant Variable ? Must Know • Magnitude of Stress • Orientation/Direction of Stress • Stress Differences Origin/Magnitude of Stresses max (Equal to Overburden, V ?) intermediate h-max min h-min Fracture Opens Perpendicular to Minimum Stress (At Shallow Depths or in Highly Over-pressured Reservoirs, This Can Lead to Horizontal Fractures) Typical Stress Magnitude 0.7 psi/foot-of-depth 200 400 5,000 True Vertical Depth 1,000 5,000 2,000 7,500 3,000 (m) 10,000 (ft) 600 S H (bar) (psi) 10,000 Comparison of trend lines for U.S. gulf Coast, The North Sea, & Onshore Netherlands (after Breckels, et al) Cube of Rock LxLxL F 1 2 = 1 2 Stress = = F/A = F/ L 2 Strain = = / L Poisson's Ratio = = 2 / 1 Young's Modulus = E = / Elasticity Relations For Stress Elasticity Relations For Stress “0” Lateral Strain Assume Uniaxial Strain in "z" Direction h x y x y Then Due To Overburden h v Effective Stress ' + P = Fracture Closure Stress Is a Total Stress, , = ' + p H V 1 Should Read H ' V ' or 1 ( H PRe s ) ( V PRe s ) 1 H PCL ( V PRe s ) PRe s 1 Basic Stress Relations Rock Property Young’s Modulus CL K (OB PRe s ) PRe s E Tectonic T Gravity K may 1 Tectonic Strain OR ??? K = 1/3, Normally good assumption for Porous/Permeable Rocks Faulting Theory For Stress ' 'v max fis the “Angle of Internal Friction” Typically 30 deg 'h 'min For “Normal” fault environment, “K” is related to fand for f=30 degress, K=1/3. Horizontal Stress (Related to Faulting – Hubbert & Willis) 1 sin h' v' 1 sin 1 sin ( h p) ( v p) 1 sin for 30 deg rees, sin 0.5 h 1 / 3 ( v p) p Identical to Eaton’s Poisson’s Ratio Equation ! Fracture Propagation Gradient (psi/ft) Effect of Pore Pressure On Stress 1 Slope = 2/3 gives K = 1/3 0.9 0.8 0.7 after Salz 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 Pore Pressure Gradient (psi/ft) 1 Basic Stress Relations Rock Property Young’s Modulus CL K (OB PRe s ) PRe s E Tectonic T Gravity Tectonic Strain CL 1 K 2/3 PRe s K = 1/3, Normally good assumption for Porous/Permeable Rocks Effect of Geologic Structure Estimate “Gravity” Component of Stress THEN ASK What about tectonics ? • May Affect Minimum Stress, i.e., PClosure • Strong Affect on Stress Differences & Fracture Orientation/Direction Geologic Structure Maximum Principal Stress Intermediate Principal Stress Minimum Principal Stress Geologic Structure “Normal” Stress State High Angle or No Faults Always Vertical Fracture Geologic Structure V hm in Low Angle "Thrust" Fault h-max High Stresses Possibly Horizontal Fractures Strike-Slip SH-Max >> SH-Min East Texas Example SH-Max >> SH-Min So wellbore fractures during drilling. SH-Max >> SH-Min East Texas Example No Breakdown Problems so All Zones Fracture & Contribute. Tracers Provide Good Data for Fracture Height Courtesy of The “Other” Horizontal Stress Effects on Breakdown & Logs Equal Stresses Lead to High, Compressive Hoop Stress. A “Stress Cage” Around Well ! SH-Max = SH-Min South Texas Example Stress Cage Around Well so Tracer Log is Misleading Courtesy of Chevron SPE 76812 Geologic Structure Salt Intrusion Other (Any ?) Geologic Structures Affect In Situ Stresses & Fracture Geometry Fracture Azimuth h-max h-min Fracture Azimuth Low Permeability -- Loss Of Reserves Design Xf < Re Good Drainage Poor Drainage Fracture Azimuth High Permeability -- Sweep Effects Design Xf < Re / 2 Good Areal Sweep Injector Producer Poor Areal Sweep Preferred Fracture Azimuth, Vertical Fracture Minimum Horizontal In Situ Stress N E Plan View Maximum Horizontal In Situ Stress Greater Closure Stress Due To Non-Favorable Near Well Fracture Orientation High Near Well Pcl ---------Vertical Fracture Turning To Preferred Azimuth cl local cl ( H max cl ) sin 2 ( ) Effect of Fracture Turning On Near Well Closure Stress cl / ( max - cl ) 1.0 0.8 0.6 0.4 0.2 - cl is increase in near wellbore closure stress - cl is minimum in situ stress, i.e., closure stress - max is the "other" stress acting on the fracture 10 20 30 40 50 60 70 80 Angle (deg) ( or ) Little Effect for angles < 15 degrees ! Possible Magnitudes of In Situ Stress Differences Mesa Verde data showing the difference in stress gradient as a function of the lithology. General guideline for stress difference between sand and shale is about 0.2 psi/ft. Historical Review of In-Situ Stress Contrast Formation Almond Canyon Sands Cleveland Clinton/Medina Codell Cotton Valley Formation Cotton Valley Formation Cotton Valley Formation Moxa Arch Meseverde Meseverde Meseverde Meseverde Muddy J Upper Picture Cliffs Main Picture Cliffs Picture Cliffs Travis Peak/Hosstin Travis Peak/Hosstin Travis Peak/Hosstin Travis Peak/Hosstin Lower travis Peak Lower Travis Peak Lower travis Peak Vicksburg Vicksburg Vicksburg Wilcox Wilcox Wilcox Devonian Carbonate Hugoton Hugoton Hugoton Lewis Average Of Database Interval top feet Strss Shale bottom Grad Stress feet psi/ft psi/ft 6495 6927 Taylor Upper Taylor Frontier North Labarge North Labarge Piceance Piceance C-1 U-X L-X L-Z 1 2 3 McAllen Ranch McAllen Ranch Hinde & Barosa Acrabuz-Culebra Acrabuz-Culebra DC Herrington-Krider Winfield Council Grove 0.658 0.4 0.768 0.487 9170 9340 0.62 9273 9394 0.7 9954 10101 0.69 11173 11205 0.73 2000 0.785 2000 0.81 0.79 0.81 0.81 0.87 5066 7900 4260 4067 2900 6189 7359 7418 7550 9505 9814 9944 13131 0.53 7930 0.53 0.604 0.546 3000 0.6 6211 0.49 7368 0.6 7424 0.52 7560 0.56 9510 0.61 9822 0.62 9946 0.61 0.919 0.898 0.932 0.75 0.692 0.65 0.83 0.55 0.65 0.71 0.67 0.7 0.71 0.69 0.97 11700 2270 2339 2609 0.62 0.843 12500 0.58 2294 0.28 2364 0.34 2728 0.42 0.89 0.89 0.67 0.45 0.42 0.51 6841 7570 0.71 0.62 Pnet psi Description tests 400 SPE 84212 954 SPE 21848 720 SPE 27927 350 SPE 14513 600 SPE 29186 1559 GRI-Staged Field Experiment 3 1020 SPE 8405, 8297, 1195 SPE 8405, 8297, 1564 Moxa Arch GRI Technology Application CSM 2000 thesis 300 SPE 71341 934 SPE 16402 100 SPE 60321 1700 SPE 8297, 8341 350 SPE 29448 383 SPE 29448 667 SPE 21811-Northwest 371 GRI-Staged Field Experiment 1 368 GRI-Staged Field Experiment 1 1409 GRI-Staged Field Experiment 1 831 GRI-Staged Field Experiment 1 855 GRI-Staged Field Experiment 2 883 GRI-Staged Field Experiment 2 796 GRI-Staged Field Experiment 2 657 SPE 26187 SPE 6870 SPE7924 637 SPE 20706 1424 SPE 60314 - Depleted 477 SPE 60314 - Normal 1053 SPE Paper 386 ? 187 ? 235 ? 750 SPE 84212 9 11 4 1 1 1 20 34 3 11 1 27 1 2 2 3 2 4 1 2 3 3 3 4 4 14 6 2 3 1 3 1 1 1 6 754 195 Average Difference between shale and sand is ~ 0.1 psi/ft Best # Formation 400 954 720 350 600 1020 1195 1564 445 1700 467 788 657 477 1053 386 187 235 750 734 Shale-Sand Stress Contrasts Average ∆ σ– 0.026 bar/m, Mean – 0.023 bar/m Stress Differences Control The Existence & Nature of Secondary Fractures Vertical + Horizontal Difference Between Minimum Horizontal Stress and Overburden Stress Treating Pressure In a Well Confined Vertical Fracture Can Become High Enough To Lift The Overburden and Open a Horizontal Fracture Horizontal Stress Differences Control Natural Fracture Effects SECONDARY AND “T” FRACTURES INJECTION 6C NORTH (ft) AFTER 15 MIN 200 DEPTH (ft) MWX-3 150 1290 100 1320 50 0 MWX-2 1350 -70 MONITOR WELL -150 -100 -50 0 50 100 150 END OF TREATMENT 0 70 NORMAL TO FRAC (m) WEST - EAST (ft) Secondary Fractures Pnet = 1500 psi Pnet = (SHmax - SHmin)/(1-2ν) 1300 psi Nolte-Smith Horizontal Fracture P = 4800 psi Overburden = 4600 psi Horizontal + Vertical Perforation Friction Due To Limited Wellbore/Fracture Comunication Can Cause A Small, Narrow, Near Wellbore Vertical Fracture To Open Deviated Well Problems Controlled By Stress Differences Deviated Wells Multiple Fractures Possible These May Interfere Causing - Narrow Fracture Width - Pre-mature Screenout Poor Wellbore Communication May Limit Post-Frac Production Stress Measurement Injection Tests • Advantages • Definitive data (though can be hard to interpret) • Averages data over several feet/meters • Disadvantages • Limited vertical coverage • Leaves undesired perforations • Operationally difficult Stress Measurement Special Logs • Advantages • Complete vertical coverage • Averages data over several feet • No extra perforations • Simple operations • Disadvantages • NO theoretical basis (logs may LIE) • Needs “calibration” • Normal logging problems (washouts, etc.) Shear Sonic Logs “Useful Engineering Data” Mesa Verde Real Stress (psi) 10,000 9,000 8,000 7,000 Canyon Sand Frontier 6,000 5,000 4,000 3,000 East Texas Cotton Valley 3,000 4,000 5,000 6,000 7,000 8,000 9,000 Log Stress (psi) The End Do FrcSkl 1) Stress/Pressure Estimates
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