Advances in GeoMechanics

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Presentation by Mark Zoback, given to SPWLA Abu Dhabi Chapter on 9th Dec 2009

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Advances in GeoMechanics

  1. 1. Determination of the State of Stress With Applications to Wellbore Stability and Fracture Flow in Reservoirs Mark Zoback Professor of Geophysics Stanford University 1
  2. 2. Geomechanics Through the Life of a Field E xploration A ppraisal D evelopment H arvest A bandonment P r Wellbore Stability o Pore Pressure Prediction Fault Seal/ Fracture Permeability d u Sand Production Prediction c Compaction t Casing Shear i Subsidence Coupled Reservoir Simulation o Fracture Stimulation/ Refrac n Depletion Geomechanical Model Time
  3. 3. Geomechanics Through the Life of a Field E xploration A ppraisal D evelopment H arvest A bandonment P r Wellbore Stability o Pore Pressure Prediction Fault Seal/ Fracture Permeability d u Sand Production Prediction c Compaction t Casing Shear i Subsidence Coupled Reservoir Simulation o Fracture Stimulation/ Refrac n Depletion Geomechanical Model Time
  4. 4. Middle East and Caspian Sea GMI Dubai LEGEND Wellbore Stability Fracture Permeability Fault Seal Pore Pressure Sand Production Stress Direction Last Update: 1/10/09
  5. 5. Topics  How to Determine the State of Stress in Oil and Gas Wells (and How Not To)  Wellbore Stability Applications  Fluid Flow in Fractured Reservoirs  3D/4D Geomechanics
  6. 6. Get the Stress Right! Principal Stresses at Depth Sv – Overburden SHmax – Maximum horizontal Sv principal stress Shmin – Minimum horizontal principal stress Additional Components of a Geomechanical Model UCS Pp – Pore Pressure Pp UCS – Rock Strength (from logs) Fractures and Faults (from Image Shmin SHmax Logs, Seismic, etc.) 7
  7. 7. Developing a Comprehensive Geomechanical Model Parameter Data z0 Vertical stress Sv (z0 ) = ∫ ρ g dz 0 Least principal stress Shmin ⇐ LOT, XLOT, minifrac Max. Horizontal Stress SHmax magnitude ⇐ modeling wellbore failures Stress Orientation Orientation of Wellbore failures Pore pressure Pp ⇐ Measure, sonic, seismic Rock Strength Lab, Logs, Modeling well failure Faults/Bedding Wellbore Imaging Planes
  8. 8. Compressional and Tensile Wellbore Failures Well A UBI Well A FMI Well B
  9. 9. Borehole Wall Stresses for a Particular Trajectory
  10. 10. Breakouts in Deviated Wells SHmax azimuth 145° 55º/235º 100º/280º vertical well tangential stress 100º/280º well inclined 70° at an azimuth of 280
  11. 11. Stereo Plot for Deviated Wells Easy and functional display of wellbore stability or risk for wells of any orientation.
  12. 12. Wellbore Failure Orientation in Deviated Wells
  13. 13. Pre-Salt, Brazil - SHMax Azimuth?
  14. 14. Wellbore Failures – South America
  15. 15. Geomechanics Through the Life of a Field E xploration A ppraisal D evelopment H arvest A bandonment P r Wellbore Stability o Pore Pressure Prediction Fault Seal/ Fracture Permeability d u Sand Production Prediction c Compaction t Casing Shear i Subsidence Coupled Reservoir Simulation o Fracture Stimulation/ Refrac n Depletion Geomechanical Model Time
  16. 16. Similar Diagrams for Nahr Umr Shale
  17. 17. Don’t Calculate Stress From Poisson’s Ratio Assumptions: However... •Sv applied instantaneously •Observations indicate that the •No other sources of stress exist horizontal stresses are not equal, •No horizontal strain (Bilateral •Model doesn't explain SH > Sh > Sv, Constraint) •Material is elastic, homogeneous •Global tectonic activity indicates that and isotropic from the time Sv is the crust is not tectonically relaxed applied to the present ν SH - Pp ~ 1− ν (Sv - Pp)α Utilizing an Effective Poisson’s Ratio and Adding Tectonic Stress Does Not Make Model Correct Lateral Constraint (horizontal strain = zero)
  18. 18. Don’t Calculate Stress from Poisson’s Ratio!
  19. 19. Topics  How to Determine the State of Stress in Oil and Gas Wells (and How Not To)  Wellbore Stability Applications  Fluid Flow in Fractured Reservoirs  3D/4D Geomechanics
  20. 20. The Key to Wellbore Stability is Controlling the Width of Failure Zones
  21. 21. Design for Variations in Strength Increase Mud Weight as Needed
  22. 22. Frac Gradient “Collapse Pressure” Pore Pressure
  23. 23. Tendency for Breakout Initiation for Different Stress Regimes 3 km Depth, Hydrostatic Pp
  24. 24. Mud Weight Needed to Maintain 30º Breakouts Normal Strike-Slip Reverse Stress States Same as Previous Slide Medium Strong Rock UCS = 7250 psi
  25. 25. Example - Stability of Uncased Multi-Laterals Key Questions: • Is it possible to leave short sections (~15’), of laterals uncased near the parent well? • Will such intervals be stable as the reservoir is produced? • Could producing too fast exacerbate sand production and stability problems?
  26. 26. Calibrated Rock Strength Log C o, K psi 0 5 10 15 20 9500 • Triaxial tests in laboratory 9600 • Relate strength to P-wave modulus 9700 • Use ∆T and density to compute UCS 9800 • Caution - should not be used in hydrocarbon zones 9900 10000
  27. 27. Wellbore Stability Plot N Less stable Required mud weight Required Strength Breakout Width W E More stable S S H m ax Lower hemisphere stereographic projection of well orientation
  28. 28. Previously Unknown Drilling Experience M O NO PO D K-2 6 -9 80 0' 0' 70 -9 0' 60 -9 in g B ay Fa u lt -9 00 0' Well X ' 00 ad -92 ' 00 Tr 0' -94 -960 0' -980 -9800' Drilled at 335 degrees, KING SALMON -9 60 0' G-1 5 RD -9 -9600' 40 0' -9400' maximum deviation 108 degrees. -94 00 ' -9200' -96 00' 00 ' -92 -920 0' 0' 60 -9 Successfully drilled and 0' -900 -9600' -940 M-3 1 0' 0' -940 0' -920 completed 0' GRAYLING -900 00' -94 0' 20 -9 STEELHEAD -920 0' -940 0' -920 0' -9 60 0' 0' -940 Well Y 0' 60 -9 0' 80 -9 Drilled at 31 degrees, 0' 20 -9 DOLLY VARDEN deviation 88 degrees. -9 40 0' -9 60 -9400' 0' 0' -960 0' -980 Wellbore collapsed in open-hole section
  29. 29. Moderate Drawdown / Damage • Decreased pressure drop • Damage zone less important Pore pressure distribution during drawdown
  30. 30. Moderate Drawdown / No Damage Smaller pressure drop 10000 Uniaxial compressive strength [psi] Lower stress at wellbore 8000 6000 →Relatively more stable 4000 →Total BO’s ~ 100o 2000 0
  31. 31. Rapid Drawdown / Damage • Large pressure drop near the well • Exacerbated by damage zone Pore pressure distribution during drawdown
  32. 32. Rapid Drawdown / Damage Large pressure drop 10000 Increased stress at wellbore Uniaxial compressive strength [psi] 8000 →Unstable well 6000 →Total BO’s > 180o 4000 2000 0 Strength required to prevent failure is too high → excessive breakouts
  33. 33. Example 2 • Severe wellbore instabilities in the Fortune Bay shale led to abandonment of original PG-2 Side track well and required drilling a side track • The side track was completed abandoned successfully by switching to oil PG-2 based mud and raising the mud weight to 12 ppg in the Fortune Bay shale. Objective for future wells • Optimization of wellbore stability in deviated and horizontal wells • Feasibility of drilling highly deviated wells with a maximum mud weight of ~11.5 ppg
  34. 34. Orientation of SHmax Hibernia World stress map data superimposed with mean SHmax Newfoundland orientation (red arrow) derived from St. John’s 4-arm caliper and UBI breakout analysis in vertical wells of the Terra Nova field Terra Nova
  35. 35. Pore Pressure and Stress in the Terra Nova Field Pressure/Stress [bar] 0 200 400 600 800 1000 0 Pp[bara] wet sand Pp water 500 Pp[bara] sand Pp oil wet LOT (C-09) Hydrostatic Hydrost. [bara] Overburden Sv [bara] 1000 Test Pres.[bara] FIT LOT X-LOT 1500 SSTVD [m] 2000 2500 1.117 Sv = 0.0848*SSTVD 3000 X-LOT (GIG-3) X-LOT (PG-2) 3500 Pp = 0.098*SSTV LOT (C-23) 4000 Shmin = -15.889 + 0.19416*SSTVD
  36. 36. Breakouts from UBI log in PG-2 Azimuth [deg] Fortune 0 90 180 270 360 Shale • 3800 Total breakout Bay no data Low er FBS 3850 E sand ED shale length: 32 m Dc sand 3900 • Db shale Da sand D congl. Mean breakout 3950 UC2 sand width: 40° (±11°) LC2 shale Jeanne d’Arc Reservoir 4000 LC2 sand C2C1 shale 4050 C1 sand 4100 C1B shale 4150 B sand B Rank shale no data Rankin Mbr. 4200 Breakout azimuth Azimuth (deg) Breakout (deg) Width width
  37. 37. Breakouts from UBI log in PG-2 N Lc2 shale within the W E Jeanne d’Arc reservoir S Isotropic compressive failure C1 sand within the Jeanne d’Arc reservoir
  38. 38. Breakouts from EMS 6-arm caliper log in PG-2 Jeanne d’Arc reservoir Fortune Bay shale Isotropic failure Anisotropic failure The difference in failure behavior between the Fortune Bay shale and the Jeanne d’Arc reservoir is similar to the UBI images
  39. 39. Breakouts from UBI log in PG-2 Lowermost Fortune Bay shale Anisotropic compressive failure
  40. 40. Modeling anisotropic breakouts in the Fortune Bay shale with the given in situ stress state Anisotropic failure Anisotropic failure Bedding plane properties: • dip = 8° (from core data) • Azi = 23° (from core data) • S0 = 4.8 MPa (from lab data) • µs = 0.21 (from lab data) MW = 10.5 ppg MW = 12 ppg Result: The in situ stress tensor Isotropic failure Observed derived in this study and the bedding plane properties measured in the lab can account for the anisotropic breakouts seen in the Fortune Bay shale
  41. 41. Predicting stability in the Fortune Bay shale for well GIG-3 C0 = 55 MPa wBO = 75° MW = 12 ppg Assuming anisotropic behavior • There exists a steep stability gradient for deviations between 25° and 45 ° • Well PG-2 is oriented less favorably in the current stress field • Well GIG-3 is oriented more favorably in the current stress field • Severe stability problems can be avoided for GIG-3 with a maximum mud weight of 11.5 ppg if deviation < 30 °
  42. 42. Business impact • Petro-Canada successfully drilled well GIG-3 through the Fortune Bay Shale successful by limiting deviation to 27° and mud weights to 10.5 ppg – 11 ppg abandoned • Petro-Canada avoided costly stability PG-2 problems by following GMI’s recommendations for this well successful GI G- 3 Graben structure at base of reservoir
  43. 43. Topics  How to Determine the State of Stress in Oil and Gas Wells (and How Not To)  Wellbore Stability Applications  Fluid Flow in Fractured Reservoirs  3D/4D Geomechanics
  44. 44. Characterizing Hydraulically-Permeable Fractures and Faults But which ones control fluid flow and how do we take advantage of this?
  45. 45. Hydraulically Conductive Fractures are Shear Faults Active (or Activated) in the Current Stress Field From Townend and Zoback (2001)
  46. 46. Active Faults Maintain Permeability Through Time Faulting is key to maintaining permeability
  47. 47. Temperature Anomalies and Permeable Faults in the KTB Borehole Zoback and Townend (2001) Ito and Zoback (2000)
  48. 48. Mechanical Lithosphere Zoback, Townend and Grollimund (2002) High Stress, Critically-Stressed Crust Ductile Lower Crust and Upper Mantle Is This Model Quantitatively Correct?
  49. 49. Broad-Scale Stresses and Distributed Seismicity
  50. 50. Gas Leakage Along Faults
  51. 51. Active Strike-Slip Faults Conduct Fluids
  52. 52. ~5cm/yr Examples -Critically-Stressed Faults in Damage Zones
  53. 53. Fault Damage Zones and Directional Permeability Damage zone
  54. 54. Strong Directional Flow Near Dormant Normal Faults Preferential flow along the faults from interference and tracer test
  55. 55. Current Strike-Slip Stress State Stratigraphic Permeability Model Paul, Zoback and Hennings (2009)
  56. 56. Need For a Better Model to Match Reservoir Flow Permeability Model Does Not Match Pressure Data in Producers or Injectors
  57. 57. No Wells Directly in Damage Zones Dynamic Rupture Propagation to Calculate Damage Zones Depth ~2700m 0 2000 N m Origin point of rupture 8 x 10 Damage Intensity 1 .5 sxx Damage zone sxy syy 1 szy szx s t r e s s m a g n it u d e ( P a ) Rock strength szz Horizontal Plane 0 .5 S1 S2 S3 oct shear 0 to ta l o c t s h e a r Fault Plane -0 .5 Cross Section View Along -1 0 50 100 150 200 250 300 Strike of Normal Fault d is t a n c e f r o m r u p t u r e f r o n t ( m )
  58. 58. Calculated Damage Zone Width At reservoir depths from 100 simulations: Simulation 1 Mean of DZ width ~50-90m Simulation 2 Process Zone Width, m Simulation 3 Fault Zone Length, m Simulation 4 Vermilye and Scholz (1998) 2km
  59. 59. Utilizing the Dynamic Rupture Model to Predict Width of Damage Zone and Anisotropic Permeability
  60. 60. Improved Damage Zone Model Matches Model Pressure Data in Producers and Injectors Base Model
  61. 61. Breakout Orientation Fluctuations Due to Fault Slip Shamir and Zoback (1992)
  62. 62. Geomechanics Through the Life of a Field E xploration A ppraisal D evelopment H arvest A bandonment P r Wellbore Stability o Pore Pressure Prediction Fault Seal/ Fracture Permeability d u Sand Production Prediction c Compaction t Casing Shear i Subsidence Coupled Reservoir Simulation o Fracture Stimulation/ Refrac n Depletion Geomechanical Model Time

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