Hydraulic Fracture Complexity and Treatment Design in Horizontal Wells
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Hydraulic Fracture Complexity and Treatment Design in Horizontal Wells

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This presentation focuses on fracture complexity and proppant distribution as well as reservoir simulation.

This presentation focuses on fracture complexity and proppant distribution as well as reservoir simulation.

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Hydraulic Fracture Complexity and Treatment Design in Horizontal Wells Hydraulic Fracture Complexity and Treatment Design in Horizontal Wells Presentation Transcript

  • Hydraulic Fracture Complexity and Treatment Design in Horizontal Wells Craig Cipolla VP of Stimulation Technology Carbo Ceramics/StrataGen Engineering
  • Outline• Fracture complexity• Proppant distribution• Reservoir simulation (horizontal wells with complex fractures growth) – Effect of fracture conductivity • How much conductivity is needed? • Effect of modulus on network fracture conductivity – Effect of staging – Effect of network fracture complexity (i.e. – spacing) – Effect of permeability• Summary & conclusions
  • Simple Planar Fracture Growth Simple Fracture Complex Fracture Complex Fracture Complex FractureWith Fissure Opening Network
  • Predictable Proppant Distribution
  • Complex Planar Fracture GrowthComplex Fracture Complex Fracture Network
  • Complex Growth, Fissure Opening Complex Fracture Complex FractureWith Fissure Opening Network
  • UnpredictableFracture Growth Network Proppant Transport? Complex Fractureg Network
  • Fracture Complexity & Natural Fractures Natural Hydraulic Fractures Fractures
  • Grasshopper, Now You Must Choose! Simple or Complex?
  • Proppant Distribution (network fracture growth)Proppant volumes probably insufficient to effectively prop large networksNetwork fracture conductivity likely dominated by un-propped fracturesProppant may not be effectively transported into complex networksUn-propped fracture conductivity a key factor in well productivity reference SPE 115769
  • Proppant Distribution Vertical Proppant Distribution Arch dimensions and stress on proppant based on SPE 119350 (Warpinski)
  • Proppant Distribution Vertical Proppant Distribution in Primary Fracture C*fD-vertical = kfwf/khf-unpropped? CfD= kfwf/kxf C*fD-vertical = kfwf/khf-propped?*reference Britt SPE 102227 and SPE DL presentation 2007-2008 Series
  • Production Modeling in Shale-Gas Reservoirs
  • Comparison Wells Barnett Horizontal Completions• Well A  2,600 ft lateral  Four frac stages o 670 klbs (40/70-sand), 120,000 bbls o 700 ft between perforation clusters  SRV = 1,880x106 ft3 (Microseismic fracture mapping)• Well B  2,600 ft lateral  Two frac stages o 830 klbs (40/70-sand), 117,000 bbls o 500 ft between perforation clusters  SRV = 2,017x106 ft3 (Microseismic fracture mapping)
  • Stimulating Horizontal Wells½ Symmetry for Reservoir Simulation
  • Impact of Fracture ConductivityPressure distribution after 3 months Pressure distribution after 1 yr 100 mD-ft primary fracture conductivity 400 ft Pressure (psi) Pressure (psi) Insufficient fracture conductivity 2 mD-ft primary fracture conductivity Pressure (psi) Pressure (psi) 400 ft main fracture spacing, 100 ft network fracture spacing, 2 mD-ft network conductivity
  • Impact of Primary Fracture Conductivity 400 ft main fracture spacing and 100 ft network fracture spacing Barnett HZ well
  • Impact of Network Fracture Conductivity Well B Well A 300 ft primary fracture spacing, 100 ft network fracture spacing
  • How Much Fracture Conductivity is Needed? Network conductivity required to achieve 90% of90% of 1 -yearproduction Network Conductivity Required to Achieve maximum 1st Production st 1000 0.0001 mD 212 224 0.01 mD Fracture Conductivity (mD-ft) 100 71 25 22 10 3.5 2.8 1 0.4 0.1 Small Network Small Network Large Network Large Network Uniform Network Infinite Uniform Network Infinite Conductivity Conductivity Conductivity Conductivity Primary Fracture Primary Fracture Results for 50 ft fracture spacing
  • How Much Conductivity can be Achieved? Un-Propped & Partially Propped Fracture Conductivity 10000Reference Conductivity, md-ft 0.1 lb/sq ft bauxite 1000 100 Uniform Network Conductivity 10 Infinite Conductivity Primary Fracture 1 0.1 lb/sq ft Jordan sand, or displaced un-propped 0.1 0 2000 4000 6000 8000 Adapted from SPE 60236, 74138 Closure Stress, psi
  • Un-Propped Fracture Conductivity Effect of Modulus 1000 E=6E+6 psi E=4E+6 psiConductivity (mD-ft) 100 E=2E+6 psi E=1E+6 psi 10 1 0.1 0.01 0 2000 4000 6000 8000 Stress (psi)
  • Optimizing Proppant Selection Too big or Too small? Not strong enough? More proppant?
  • Impact of Primary Fracture SpacingPressure distribution after 3 months Pressure distribution after 1 yr 600 ft main fracture spacing Pressure (psi) Pressure (psi) 200 ft main fracture spacing Pressure (psi) Pressure (psi) 200 mD-ft primary frac and 2 mD-ft network, 100 ft network fracture spacing
  • Impact of Primary Fracture Spacing Well B Well A 100 ft network fracture spacing
  • Impact of Network Fracture SpacingPressure distribution after 1 month Pressure distribution after 1 yr 300 ft network fracture spacing 600 ft Pressure (psi) Pressure (psi) 50 ft network fracture spacing 600 ft Pressure (psi) Pressure (psi) 200 mD-ft primary frac and 2 mD-ft network, 600 ft primary fracture spacing
  • Impact of Network Fracture Spacing Well B Well A 2 mD-ft network fracture conductivity
  • Impact of Network Fracture Spacing Well B Well A 2 mD-ft network fracture conductivity
  • Impact of Matrix Permeability (1 x 10-5 mD) 50 ft spacing, k = 1 e-4 md 100 ft spacing, k = 1 e-4 md Well B Well A 2 mD-ft network fracture conductivity
  • Conclusions Characterizing Fracture Growth leads to: Better understanding well & fracture performance More reliable reservoir modeling and better reservoir characterization Resolution of created and effective fracture length Better estimates of In situ fracture conductivity Improved completion & stimulation strategies Stimulation fluid & proppant selection Well placement and spacing Number of stages (both vertical & horizontal wells)OptimumOptimized designs (volume, rate) Field Development Fracture Treatment Designs and Strategies Tailored to Specific Geologic Environments
  • Are we applying the rightcombination of technologies?
  • Fracture & Completion Strategy (horizontal gas wells, network fracture growth) Conductivity of the primary fracture is likely a critical parameter (~50-100 mD-ft required) Fracture complexity/network fracture spacing key to well productivity and gas recovery  If network fracture spacing is on order 50 ft, then the effect of matrix permeability on production is significantly reduced  High relative conductivity primary fracture reduces the impact of network fracture spacing
  • Fracture & Completion Strategy (horizontal gas wells, network fracture growth) Actual production profiles suggests that primary fracture conductivity is low? Understanding matrix permeability and un-propped fracture conductivity is important when optimizing treatment designs in unconventional gas reservoirs Un-cemented horizontal completions, more difficult to create a high relative conductivity primary fracture?
  • General GuidelinesIn low modulus rock, it may not be possible to exploit complexity. (Haynesville?)In reservoirs that are prone to fracture complexity, design goals should target: – Large networks for k~0.0001 md (E>4e6 psi) • Supplemented with infinite conductivity primary fractures – Small networks for k~0.01 md (E>4e6 psi) • Supplemented with infinite conductivity primary fractures – Simple fractures for k~1.0 md (E<2e6 psi)
  • Strategy• Evaluate the impact of operational changes upon fracture complexity o Low viscosity fluids generally promote fracture complexity and minimize damage o High viscosity fluids reduce fracture complexity (Haynesville?) o Pump rates, completion strategy, diversion, 100- mesh, etc.• Evaluate hybrid treatments to promote small networks with infinite conductivity primary fractures
  • Strategy• Evaluate higher strength, smaller mesh, and lower density propping agents that can significantly improve the conductivity of partially propped network fractures Deeper penetration, better proppant transport Possibly enter and prop secondary network fractures• Evaluate larger proppant volumes Increased primary fracture conductivity Increase network fracture conductivity
  • Questions?
  • Backup Slides
  • Reservoir Simulation Study Goal: Evaluate the relationship between fracture complexity, fracture conductivity, and proppant distribution on well productivity Cases: Single fracture, complex planar growth, small networks, and large networks  This presentation focuses on Small and Large Networks Reservoirs: Gas with permeability of 0.0001, 0.01, and 1 md Proppant distribution: Two limiting cases  Proppant is concentrated in a single primary fracture with infinite conductivity (case 2)  Proppant is evenly distributed within the fracture network (cases 1 & 3)  Evaluate the effect of network fracture conductivity on well productivity for the two limiting cases
  • Example Fracture Treatments • Barnett Shale (SPE 95568) – k = 0.0001 mD (est.) – hf = 300 ft – xf = 1500 ft – xn = 2000 ft – Δxs = 50-300 ft (est.) • Treatment – 60,000 bbl – 385,000 lbsNote: Fracture dimensions and complexity from microseismic mapping
  • Important Assumptions Cased and cemented wellbore  Primary fracture spacing controlled by distance between perforation clusters  Gas flow into wellbore at perforation clusters only Fracture complexity (network fracture spacing) is not affected by primary fracture spacing (distance between perforation clusters)  Pre-existing natural fracture system or rock fabric is present and can be equally stimulated for the range of primary fracture spacings evaluated Network fracture conductivity is not affected by primary fracture spacing Stimulated Reservoir Volume (SRV) is equal for all cases (2000 x 106 ft3)
  • Barnett Example 3000 2500 2000 1500South-North (ft) 1000 500 0 -500 -1000 -1000 -500 0 500 1000 1500 2000 2500 West-East (ft)
  • Proppant Distribution, 150 ft Network Fracture Spacing: Barnett Shale Example (385,000 lbs prop) 150 ft 0.015 lb/ft2150 ft 2000 ft 2000 ft Evenly Distributed (Case 1) 3000 ft Note: Dimensions not to scale
  • Proppant Distribution, 150 ft Network Fracture Spacing: Barnett Shale Example (385,000 lbs prop) 150 ft 0.43 lb/ft2150 ft Concentrated in a 2000 ft 2000 ft dominant fracture (Case 2) 3000 ft Note: Dimensions not to scale
  • Proppant Distribution & Network Fracture Growth Summary If proppant is evenly distributed in network fractures, concentrations are probably too small to materially affect conductivity If proppant is concentrated in a primary fracture, concentrations may provide adequate conductivity for k<0.01 md Un-propped fracture conductivity will likely be a key factor in exploiting fracture complexity
  • Effect of Modulus & Stress on Embedment 1.60 1E+6 psiEmbedment (grain diameters) 1.40 2E+6 psi 4E+6 psi 1.20 6E+6 psi 1.00 0.80 0.60 0.40 0.20 0.00 0 2000 4000 6000 8000 10000 12000 Stress (psi)
  • FindingsFracture complexity can be estimated by integrating microseismic mapping, reservoir & fracture modeling, core data, and well performanceIn some reservoirs, fracture complexity has been shown to improve production. In other reservoirs, complex growth has been shown to damage productivity.
  • FindingsIf proppant is evenly distributed throughout large fracture networks, the resulting concentrations are inadequate to materially affect conductivityTo capitalize on the potential of unpropped and partially propped regions, these networks should be contacted by infinite conductivity primary fractures