Considerations for Infill Well Development in Low Permeability Reservoirs

Transcription

1 Considerations for Infill Well Development in Low Permeability Reservoirs George Waters Technical Manager Unconventional Completions September 9, 2014

2 Topics Continuous Improvement in Field Development What Drives Frac / Well Spacing? Field Development Workflow Bakken Shale Example Cana Woodford Shale Example

3 The Quest For The Optimized Completion

4 The Quest For The Optimized Completion

5 The Quest For The Optimized Completion

6 The Quest For Optimized Field Development

7 The Quest For Optimized Field Development

8 The Quest For Optimized Field Development

9 The Quest For Optimized Field Development

10 North American Horizontal Evolution Lateral Length Increase 86% 55% 31% 130% 37% 33% 82% 35% Average Stage Length 381 ft 411 ft 322 ft 589 ft 283 ft 493 ft 248 ft 249 ft 488 ft 593 ft 489 ft 813 ft 240 ft 364 ft 378 ft 420 ft

11 US Unconventional Production Unconventional Liquid Plays (best 3 months production bpd) Unconventional Gas Plays (best 3 months production mcfd) 1,800 1,600 1,400 Bakken 1,200 1, ,500 2,000 1,500 1, Best 3-month average ~ 340 bbl/d Eagle Ford Best 3-month average ~ 518 bbl/d 25,000 20,000 15,000 10,000 5, ,000 5,000 Haynesville Best 3-month avg ~ 7,650 Mscf/d Fayetteville 4,000 3,000 2,000 1, Best 3-month avg ~ 1,900 Mscf/d IHS Public Production Data

12 Topics Continuous Improvement in Field Development What Drives Frac / Well Spacing? Field Development Workflow Bakken Shale Example Cana Woodford Shale Example

13 Cleveland Sand Horizontal Well Development Vertical well development since 1980s Produces both oil and gas Revitalized with horizontal wells in 2000s Completion Techniques: One large frac with ball diversion Packers / Port Collars

14 Horizontal Hz Cost Well Compared Cost / Vertical to a Vt Well Cost Cleveland Sand Frac Spacing Optimization: 2005 Performance Improvement vs Cost Horizontal Well Productivity Improvement Versus Increase in Well Cost An economic optimum of 300 ft Conventional Drilling hydraulic fracture spacing 100 ft spacing 3.0 ~300 feet 250 ft spacing Vertical Well 500 ft spacing: Standard completion at the time Horizontal Production PIF / Vertical Production Schlumberger Internal Study: October, 2005

15 BP Results After Increasing Frac Stages: ft lateral, 9 fracs 444 ft spacing 277 ft spacing 2500 ft lateral, 9 fracs 500 ft spacing 2500 ft lateral, 5 fracs SPE

16 Hz Cum/ Vt Cum in 10 years Hz Cum/ Vt Cum in 10 years Cleveland Sand Fracture Spacing Optimization Fracture Spacing Limited xf = 250 ft, h = 20 ft and 4 fracs xf FCD = 250 = 1, ft, xf h = ft ft and 4 fracs 4.0 h = 50 ft FCD = 10, 7 fracs FCD = 1, 7 fracs FCD = 10 h = 20 ft, xf FCD h = = 10 ft ft h = 50 FCD ft, xf h = = ft ft h = 20 ft h = 40 ft FCD FCD = = 2 h = 30 ft FCD h = 50 = ft h = 40 FCD ft = Fracture Conductivity Limited k, md k, md Schlumberger Internal Study: October, 2005

17 Parameters That Control Well / Frac Spacing Matrix Perm Frac spacing and conductivity needs Natural Fractures Enhanced permeability, stimulation difficulty, stimulated geometry Faults Inefficient fracturing and unwanted fluid migration potential Reservoir Fluids Fluid viscosity impacts pressure transient Variability Along the Horizontal Well Quality of the reservoir will vary along the well Well may not stay within the reservoir Orientation of Well Relative to Stress Field Frac orientation and spacing

18 Topics Continuous Improvement in Field Development What Drives Frac / Well Spacing? Field Development Workflow Bakken Shale Example Cana Woodford Shale Example

19 Bakken Shale Field Development Strategy Field Development Challenges: Hydraulic fracture spacing Offset well placement Bakken / Three Forks development Well placement between Bakken and Three Forks

20 Single Well Optimization: How Many Fracs/Stages? Pressure History Match Pre Job ISIP Post Job ISIP Multiple Fractures Fracturing pressure responses indicate that the number of fractures varies from one to three, with one dominant frac most common (Uncemented Port Collar / Perforated Completions) SPE142388

21 Single Well Optimization: Frac Geometries Height growth and vertical communication between Bakken and Three Forks Large frac geometry infers fewer fractures SPE142388, SPE

22 Oil/ Gas and Water Daily Production Rates (BOPD/ BWPD/ Mscfpd) Number of Fractures and Height Growth Validated via Fort Production Berthold 17D SWPM* Matching History 1600 qo qg qw OilProductionForecast STB/d WaterProductionForecast STB/d Elapsed Days History match early production Reconcile number of fractures (producing area) and fracture conductivity SPE152177

23 Calibrated Model used to Forecast Recovery Forecast EUR Gas Oil 10 years Early time

24 Calibrated Model Optimize Completions Low perm: md High perm: k > md 16 stages 32 stages 8 stages High Perm Low Perm 10 year NPV Economic sensitivity analyses to optimize the number of frac stages

25 Expanding to Field Development: Well Spacing SPE

26 Sustained Vertical Communication? M. Bakken M. Bakken M. Bakken TF1 TF1 Large Fracs Alternating Bakken and Three Forks Laterals Small Fracs SPE

27 The Impact of Production Pore pressure distribution after 600 days of production Closure stress reduction is directly proportional to drop in pore pressure Pore pressure reduction is inversely proportional to mechanical properties anisotropy in TIV rocks Closure stress does not fall as fast in TIV rocks as isotropic rocks SPE169003

28 Evolution of Frac Geometry with Time / Depletion Frac geometry pre Bakken depletion from offset well Frac length and height growth can vary with pore pressure depletion Can the Bakken and Three Forks be produced together? Frac geometry post Bakken depletion from offset well SPE142388

29 Asymmetric Fracture Geometry due to Depletion Fracture geometry for initial conditions Planar3D Fully 3D asymmetric hydraulic fracturing simulator Fracture geometry for infill wells SPE169003

30 What is the Impact on Infill Well Production? Pressure Profile for parent well evolves with time / depletion Optimum infill well distance from the parent well will vary with time SPE152177, SPE

31 Development Challenges due to Depletion Stimulation away from parent well can be adversely affected. Will alter infill development strategy SPE

32 Field Development Strategy due to Depletion Instead of having this Representation of pressure transient / depletion pattern SPE163855

33 Field Development Strategy due to Depletion We have this Best addressed with a calibrated reservoir model SPE163855

34 Anadarko Basin: Cana Woodford Shale

35 Woodford Shale Fracture Geometries Woodford horizontal stress anisotropy is ~ 1,500 psi from multiple 1D MEMs Result is Planar Fractures URTeC

36 Large Slickwater Fracs = Long Frac Lengths 1 mile Hydraulic lengths intersect offset wells Conductive lengths are much shorter than hydraulic lengths URTeC

37 Long Frac Lengths are Modeled URTeC

38 Long Frac Lengths are Measured Frac pressure communication with offset wells ,950 ft 3,990 ft URTeC

39 Woodford Pore Pressure Depletion URTeC

40 Woodford Shale Frac Assymetry URTeC

41 Woodford Producing Intervals URTeC

42 Woodford Shale Productive Intervals Only Woodford C E appear to be producing URTeC

43 Modeled Production Validates Productive Intervals URTeC

44 Woodford Shale Field Development Challenge WFD A WFD B Unrecovered hydrocarbons WFD C WFD D WFD E WFD F WFD G Unrecovered hydrocarbons URTeC

45 Woodford Shale Field Development Challenge URTeC Infill well development adversely impacts parent wells

46 Operational Solutions to Address Challenges Develop fracture designs to address loss of vertical fracture conductivity Evaluate reverse hybrid technique: Improve effective frac height and infill well proppant transport Reduced overall fluid volume for better infill well stimulation results Improved propped to unpropped fracture ratio Change perf design to improve injectivity into all perfs Reduced frac lengths by injecting into more clusters Provide flow back energy to flooded existing producers: Re-frac the existing producing well with an energized fluid, distributed along the entire lateral in the fracture system with degradable diverters Energized fluids in the new well stimulations Reservoir depletion management Temporal optimization of infill development URTeC

47 Summary Field development is controlled by reservoir and completion parameters: Reservoir Parameters Perm, natural fractures, geomechanical setting Completion Parameters Perf spacing, stage design, frac fluid type and volume, production management Infill well placement is a function of: Perm, pressure, and stimulated / drainage volume Time of infill well relative to parent well(s) Durability of fracture conductivity, especially vertically Parent wells will be impacted: Likely to be adverse on wells with large production volumes Options to protect parent wells: - Shut in parent wells - Aggressive drawdown of parent wells during infill well fracturing - Pressure up parent well with (energized) fluids - Refrac parent wells utilizing diversion technologies - Use energies fluids on infill wells