Microseismic Interpretations and Applications: Beyond SRV - PowerPoint PPT Presentation

Microseismic Interpretations and Applications: Beyond SRV Reference: SPE 168596 Craig Cipolla, Hess Corporation MicroSeismic, Inc. User Group Meeting Wednesday, February 19, 2014

Stimulated Reservoir Volume (SRV) • First introduced by Fisher et al. (2004), Barnett Shale. o Fracture growth may be much more complex in unconventional reservoirs. o Microseismic volume could be correlated to production in specific areas. Figure 4 from SPE 90051 Figure 22 from SPE 90051

Stimulated Reservoir Volume (SRV) • Further defined by Mayerhofer et al. (2008) o Drainage volume may be limited to SRV. o Fracture area is a key factor that controls productivity. Figure 11 from SPE 119890

SRV-based Production Models k srv k m x f k f w f Figure 4 from SPE 90051 The Missing Link The relationship between fracture geometry and conductivity and well productivity and drainage volume. Reference: SPE 168596

What is Stimulated Reservoir Volume (SRV)? Focus on Microseismic • Completion/Fracturing Engineers – Microseismic volume – Fracture geometry – Maximum drainage distance Focus on Production • Reservoir Engineers – Drainage volume or area – Stimulated region permeability, k srv – Effective fracture length

Beyond SRV Microseismic Image Natural Fractures (DFN) Complex Hydraulic Fractures Network Fracture Model Natural fracture Stress Regime (3D MEM) Hydraulic fracture calibration using microseismic data

Beyond SRV Complex Hydraulic Fractures • Discretely grid the complex hydraulic fracture • Propped and un-propped fractures • Stress sensitive fracture conductivity Numerical Reservoir Simulation Maintain the fidelity between the hydraulic fracture model and numerical reservoir simulation Pressure distribution at 10-years

Shale Gas Example: Microseismic ~4500 ft Lateral Cased & Cemented, Plug & Perf, 4 clusters/stage, 70 bpm Hybrid Treatment Design: 12% 100-mesh, 75% 30/50 ceramic, 13% 20/40 ceramic 15 stages P i = 7650 psi 109,000 bbls Ø= 4.7 % Gas GR= 0.65 4,400,000 lbs h= 132 ft o F T r = 180 Reference: SPE 168596

Shale Gas Example: Microseismic Volume SRV/ESV = 1800 MMft 3 Hydraulic fracture area = ? Fracture conductivity = ? Distribution of conductivity = ? Propped & un-propped fracture area = ?

Planar Fracture Model Total fracture area = 36 MM ft 2 Total propped area = 13 MM ft 2 Fracture area-pay = 14 MM ft 2 Propped area-pay = 5 MM ft 2 Microseismic observation well Fluid Efficiency ~ 76%

Planar Fractures Matched to MSM =17.9 MMft 2 Area Propped = 7.3 MMft 2 Area-Pay = 12.2 MMft 2 Prop-Pay = 5.4 MMft 2 Microseismic observation well Fluid Efficiency ~ 42%

Complex Fracture Modeling: 50 ft DFN Network 50 ft DFN Fracture Geometry

Complex Fracture Modeling: 50 ft DFN 50 ft DFN Total fracture area = 29.7MM ft 2 Total propped area = 8.4MM ft 2 Microseismic observation well Fracture area-pay = 16.1MM ft 2 Propped area-pay = 3.7MM ft 2 Average x f ~ 400 ft Proppant ~ 0.5 lb/ft 2 concentration Fluid Efficiency ~ 74%

Complex Fracture Modeling: 50 ft DFN

Production Modeling Shale Gas Example 15 stages, 4 clusters/stage 4,571 kgal, 4,430 klbs Reference: SPE 168596

Reservoir Simulation Model Grid: 50-ft DFN Discrete gridding of the hydraulic fracture maintains the fidelity between the fracture model and reservoir simulation Honor fracture model distribution of propped fracture conductivity and un-propped fractures

Un-Propped Conductivity 10 Current closure stress at 4000 psi FBHP Closure stress at Conductivity (md-ft) 1 1500 psi FBHP σ min 0.1 Reference : Suarez, R. 2013. “Fracture Conductivity Measurements on Small and Large Scale Samples – Rock proppant and Rock Fluid Sensitivity. ” Slides presented at the SPE Workshop on Hydraulic Fracture Mechanics Considerations for Unconventional Reservoirs, Rancho Palos Verdes, California, U.S.A., 11-13 September. 0.01 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 Closure Stress (psi)

Network Fractures and Planar Fractures Hydraulic fracture complexity can significantly impact recovery 8,000,000 8000 Planar: 32 nd History Forecast 7,000,000 7000 75 ft DFN: 20 nd 6,000,000 6000 50 ft DFN: 25 nd 5,000,000 5000 50 ft DFN, UPC~0: 275 nd Gas (MCF) BHP BHP (psi) 4,000,000 4000 3,000,000 3000 2,000,000 2000 BHP 1,000,000 1000 0 0 0 500 1000 1500 2000 2500 3000 3500 4000 Days Understanding matrix permeability is important

50-ft DFN – Base Case Forecast Un-propped conductivity may be a key factor when optimizing well spacing Pressures at 10 years 10-yr recovery = 6.0 BCF km = 25 nd Ø = 5% Sw=20% H=132 ft Pi= 7650

50 ft DFN (UPC~0) Un-propped conductivity may be a key factor when optimizing well spacing Pressure distribution at 10-years 10-yr recovery = 6.6 BCF km = 275 nd Ø = 5% Sw=20% H=132 ft Pi= 7650

Stage Spacing 15 stages, 4 clusters/stage 4,571 kgal, 4,430 klbs versus 8 stages, 4 clusters/stage 2285 bbls, 2,215 klbs Reference: SPE 168596

Effect of Stage Spacing: 10-yr Recovery 50 ft DFN, Network Hydraulic Fractures 7,000,000 15-stages 6,000,000 5,000,000 4,000,000 Gas (MCF) 8-stages 3,000,000 2,000,000 18% difference in production Almost twice the proppant, fluid, stages (1.875 X) 1,000,000 Over-lap and interference results in lower incremental production compared to planar fractures 0 0 500 1000 1500 2000 2500 3000 3500 4000 Days

Fracture Complexity & Stage Spacing 1-year 8 7 6 1-year Gas (BCF) Fracture morphology may 5 significantly impact optimum 4 stage spacing 8-stages 3 18% 24% 69% 15-stages 2 10-years 1 0 8 50-DFN 75-DFN Planar 38% 7 Fracture Geometry 17% 10-year Gas (BCF) 6 18% 5 4 8-stages More Incremental production 3 15-stages for planar fractures 2 1 0 50-DFN 75-DFN Planar Fracture Geometry

Tight Oil Example Microseismic Data: ~3000 ft section Un-cemented ball-drop completion with swell packers 45 bpm,1600 bbl XL-gel, 110,000 lbs 20/40 ceramic proppant (per stage) 500 ft 500 ft Reservoir Data k o = 600 nd Pi = 7030 psi Ø= 5.1 %  Microseismic data from ~3000 ft of lateral “adapted” from SPE B o = 1.82 STB/RB 166274 P BP = 3150 psi  Tight oil example incorporates: µ o = 0.37 cp psi -1 c o = 1.13E-05  Geomechanical study (3D MEM) h= 77 ft  Reservoir simulation history match (3-yrs production) R si = 1552 scf/bbl

333 ft spacing (30 stages/10,000 ft) Stage spacing changes fracture complexity and “apparent” system permeability ( k srv ) 42,000 bbls Pressure distribution at 10-years k o =0.0006 md Two phase flow : Oil and Gas

192 ft spacing (52 stages/10,000 ft) Stage spacing changes fracture complexity and “apparent” system permeability ( k srv ) 51,000 bbls Pressure distribution at 10-years k o =0.0006 md Two phase flow : Oil and Gas

Linear Flow Analysis: Network Fractures and Stage Spacing Fracture complexity and connectivity may change with different stage spacing 0.014 x f = 145 ft 0.012 x f = 150 ft 0.01 0.008 k (md) k srv x f = 190 ft 0.006 0.004 k srv could be a function of stage spacing 0.002 Actual: k o =0.0006 md, x f ~250 ft 0 100 150 200 250 300 350 400 450 500 Stage Spacing (ft)

Fracture Complexity and Permeability Assumptions Effect Optimum Stage Spacing 70 (Linear flow analysis, Planar Fractures) RTA results: k srv = 0.01 md, x f =150 ft 10 yr Oil (MSTB/1000 ft of lateral) 60 50 40 30 Network fracture model: k=600 nd 20 10 0 0 100 200 300 400 500 600 700 Stage Spacing (ft)

Conclusions • The interpretation and application of microseismic images should include mass balance and fracture mechanics. • Integrating fracture modeling, microseismic data, and production modeling may be required for completion optimization. • RTA and LFA can provide important insights into well performance, but k srv and x f may not be appropriate for completion optimization. • Changes in stage spacing and fracture treatment design will likely result in different “apparent” permeability or k srv .