Horizontal Fracturing in Shale Plays Matt McKeon
Shortening the learning curve Historically: a trial-and-error process Data acquisition USA analog fields can speed up evaluation and development Quantify Construct Complete Analyze Gas Rate Sim Gas Rate Oil Rate Oil rate Sim 2
Recent plays: fracture stimulations are evolving WaterFracs 8-10 Stages 80-100 BPM 1.5 MM lbs prop 100 Mesh, 40/70 1 ppg Max 7 MM Gal 40,000 HHP 350-450 /Stage Hybrid/Conv 12-15 Stages 40-60 BPM 3-4 MM lbs prop (total) 30/60, 20/40 3-4 ppg 4 MM Gal 25,000 HHP 250-300 /Stage 2008 2009 2010 Eagle Ford 3
Even Barnett stimulation is still changing Barnett Shale Completion Roadmap Barnett Shale Completion Roadmap 90 700 35000 4500 80 600 30000 4000 70 3500 500 25000 60 3000 Avg. BP M 50 40 400 300 bbl/stag e 20000 15000 2500 2000 30 1500 20 10 s p an ft. BPM Treatment span 200 100 10000 5000 sks/stag ge bbl/stage sks/stage 1000 500 0 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 0 0 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 0 year Year 4
Shale Gas Development Process Workflow Data Acquisition 5 5
Shale parameters to enhance commercial production Gas content : > 100 scf/ton Thermal maturity (Ro) : 0.7 to 2.5+ range; 1.2 typical Permeability : greater than 100 nanodarcies Porosity : > 4% Pressure : above normal TOC : > 2% Water saturation : < 45% Well bounded & thick zone : > 100 ft Moderate clay content : < 40% Well bounded : i.e. good frac barriers Brittle shale (fracability) : i.e. low Poisson s & high YM Natural fractures : moderate presence 6
Shale Prospect Woodford Barnett Haynesville Marcellus Eagleford Bakken Porosity (%) 5.5 1-8% ~1.5 6 (Avg. ~3.8) 8-15% 3 8% 3-15% 2-12 % TVD (ft) 4,100 4,300 6,000 14,000 5,400 9,500 10,500 14,000 4,500-8,500 5,000-13,000 8,000-11,000 Thickness (ft) 53 100-220 100-500 60-350 50-300 40-500 6-15ft & 80-145 ft BHT ( F) 160 150-225 150 280-380º F 100-150 150-350 190-240 TOC (%) 3.95 3-9% 4-8% 2-5% 3-10% 0.5-9% Upper-11%-40% Lower=8%-21% Press Grad (psi/ft) 0.48.45-.68 0.52 0.85-0.93 0.4-0.7 0.4 0.85 0.5-0.6 Frac Grad (psi/ft) 0.7.7-.9 ~0.6 0.75 >0.90 0.9 1.2.88-1.1 0.70 0.85 Avg Perm (μd) 0.1 0.05-0.4 0.05 0.4 <0.005 0.2-2 400-1200 20-500 Sw (%) 27 33% <35 no free water <25 10-30 25-60 Lithology (%) Silica rich Silica- Chert 30-60% Silica rich 35-50 v/v Shale is soft (ductile) Calcite rich-in areas silica rich (in areas) organic rich High clay mineral fraction Variable formation properties Illite clay-dominated Quartz/Plagioclase/ Feldspar Carbonates Siderite/Pyrite ~3-5% carbon content High Illite-dominate clays Looks like poker chips High in Calcites Silty, sandy, dolomite grading to laminated shaly interval. Some natural fractures. Below is Sanish YM (x10 6 psi) 3.48 4-8 6-10 2-3 2-5 1-4 Upper/Lower= 2-4 Middle=4-6 PR (%) 0.206 0.15-0.25 0.13-0.25 0.23 0.27 0.19 0.23 0.20-0.27 Upper/Lower=-0.25-0.28 Middle= 0.2 0.25 Quartz, wt % 54 25-54 40-60 25-52 10-40 1 30 15-70 Plagioclase 10 7-13 2-5 8-17 0 10 0-17 1-3 feldspar, wt % Calcite, wt % 37 3.7 7-20 5-30 13-44 5 20 25-95 15-65 Smectite,wt % 2-8 1-5 - < 2 0-23 2-6 Illite, wt % 11.9 17-46 5-25 12-20 25-60 1-50 1-13 Kaolinite wt % 8 0 0 - < 2 0-14 0-2 Chlorite, wt % 11.9 1 0 4-7 0 10 0-7 1-3 Ro (Maturity of 123 1.23 075 0.75 145 1.45 0616 0.6-1.6 1 12 1.2 08 0.8 30 3.0+ 075 0.75 216 2.16 045 0.45 060 0.60 Shale) Analog Analysis
U.S. shale play: choose stimulation Frac System Barnett Woodford Haynesville Eagle Ford Marcellus Waterfrac (WF) WF /Linear Gel WF, Hybrid, & X-Linked Hybrid WF and Hybrid TVD 5,400-9,500 ft. 6,000-14,000 ft. 10,500-14,000 5,000-13,000 ft. 4,500-8,500 ft. Lateral Length 4,000 ft. 4,000 ft. 4,500 ft. 4,000 ft. 3,000-5,000 ft. Stages 4-8 6-12 10-15 12-1515 10-1414 Fluid Volume 5.0 MM (8 stg) 6.5 MM (10 stg) 5.0 MM (10 stg) 4.0 MM (12 stg) 5.0 MM (12 stg) Proppant Vol. 3.5 MM lbs. 4.5 MM lbs 2.5 MM lbs 3.5 MM lbs 5.5 MM lbs Completion Type Cemented Csg. Cemented Csg. Cemented Csg. Cemented Csg. Cemented Csg. (1)P&P (1) P&P (1) P&P (1) P&P (1) P&P (2)BASS (2) BASS (2) BASS (2) BASS (2) BASS (3)Hydrajet (3) Hydrajet (3) Hydrajet (3) Hydrajet (3) Hydrajet Span/Stage 400 ft. 400 ft. 300 ft. 250-400 ft. 150-400 ft. Clusters/Length 4 4 4-6 4-8 3-5 2-4 ft. 2-4ft. 1-2ft. 1-2ft. 2-4ft. Analog Analysis
Shale Analysis Log Where would you perforate? What is the TOC and gas content? Mineralology Lithology Brittle or Ductile? Kerogen Content Will it frac and what is the relative fracture width and barriers? Reservoir Properties Natural What is the shale Fractures? in place? Unconfined Compressive volumetric gas Strength What is the shale porosity and permeability? Where is the organic rich shale? Where are the zones of highest kerogen content Shale Type Frac Ease TOC Hydrocarbon Content SPE 115258 9
Shale fracturing simulation Designed for complex fracturing Couple available data with microseismic to optimize fluid system and frac design Recalibrate model based on post job analyses and regional variations
OBJECTIVE Maximize stimulated reservoir volume (SRV) 11
Shale fracture characteristics To create complexity you must have: 1. Pre-existing natural fissures 2. Low differential horizontal stresses (net pressure > σ m m) 3. Brittleness Ductile Brittle Tight Gas Sands Haynesville Eagleford Woodford Bakken Marcellus Barnett 12
Shale Completion Strategy: Based on Formation Brittleness & Liquid Production SPE 115258 Fracture Fracture Width Brittleness Fluid System Geometry Closure Profile 70% Slick Water 60% Slick Water 50% Hybrid 40% Hybrid 30% X-Linked 20% X-Linked 10% X-Linked Proppant Fluid Proppant Liquid Brittleness Concentration Volume Volume Production 70% Low High Low Low 60% 50% 40% 30% 20% 10% High Low High High 13
Shale fluid decisions Shale Type Frac Type Fluid Type & Prop ppg Brittle & low clay Brittle & high clay Ductile & low clay Ductile & high clay Complex network No embedment Complex network Some embedment Less complex Moderate embedment Bi-Wing High embedment Water 0-2% KCL 0.1-2 ppg Water 2-7% KCL Linear gel. 0.1-3 ppg Water 0-2% KCL Linear gel. X-Link Tail 0.5 5 ppg Linear Gel 2-7% KCL X-Link 0.5-10 ppg 14 14
Lateral design, stage intervals & well spacing Lateral Drilled in direction on minimum horizontal stress for transverse fracturing Greater than 90 degree deviation is common practice Stay in best portion of the reservoir while drilling Longer laterals yield more production to a point cost considerations Stage intervals Number of intervals varies by shale play most 300 to 400 ft Most often, shorter intervals increase SRV and production more cost Couple with perforation interval distribution for optimum SRV from frac Well Spacing 15
Perforation clusters Typically evenly spaced along stage interval good rock or bad Number of clusters varies by shale play, less perm & complexity closer Number of perfs affect limited entry diversion The more clusters placed, the less contribute to production Placement in better rock (fracs, brittle) may enhance SRV and production 16
Shale Fracture Characteristics Definition of Brittleness from Rock Mechanics SPE 115258 Haynesville Marcellus Eagle Ford Woodford o d Barnett 70.00 56.00 42.00 28.00 14.00 00.00 BRIT
Barnett example pump schedule 4000 ft laterals Span = ± 400 ft Stage size = 15,500 bbl/stage Prop volume = 4300 sks/stage Number of stages 6 8 Prop type: 60% 100 mesh, 40% 40/70 Rate = 70 BPM End sand conc = 125 1.25 15ppg 1.5 Treating pressure = 4000 psi SRV (ft 3 )= 4/3*π*ABC A=networkA width B=frac length C=height/2 gal ppg prop lbs rate time pad 100000 80 29.76 slurry 40000 0.3 100 mesh 12000 80 12.07 slurry 40000 0.5 100 mesh 20000 80 12.18 slurry 100000 0.6 100 mesh 60000 80 30.58 slurry 100000 0.7 100 mesh 70000 80 30.71 slurry 100000 0.8 100 mesh 80000 80 30.85 slurry 100000 1 40/70 100000 80 31.12 slurry 70000 1.25 40/70 87500 80 22.02 flush 12000 80 3.57 % 100 mesh 56.34% total lbs 429500 lbs % 40/70 43.66% total time hr 3.38 hr % pad 15.38% avg ppg 0.66 ppg lbs 100 mesh 242000 lbs lbs 40/70 187500 lbs total volume 650000 gal 15,476 BBL
Formation hardness and proppant embedment 90 80 70 60 50 BHN # 40 30 20 10 0 Woodford Marcellus Floyd Eagle Ford Haynesville Bossier Barnett CV Lime Ohio SS Coal 19
Haynesville - example pump schedule 6 perforation cluster - 72 BPM Stage Fluid Volume Prop Prop Concent Rate/cluster 1 Treated Water 36000 -- 12 2 Guar (R11) 15000 100 mesh 0.5 12 7500 lb 3 Guar (R11) 20000 100 mesh 0.75 12 15000 lb 4 Guar (R11) 25000 100 mesh 1 12 25000 lb 5 HYBOR G (R27) 20000 -- 12 6 HYBOR G (R27) 45000 Main Proppant 0.5 12 22500 lb 7 HYBOR G (R27) 45000 Main Proppant 1 12 45000 lb 8 HYBOR G (R27) 45000 Main Proppant 2 12 90000 lb 9 HYBOR G (R27) 36000 Main Proppant 3 12 108000 lb 10 HYBOR G (R27) 22500 Main Proppant 4 12 90000 lb 11 Guar (R11) flush 12 Total fluid volume per stage 309500 gal Total proppant per stage 47500 lb 100 mesh Pump Time per Stage 102 minutes 355500 lb Main Proppant 12 Stages per Well Main Proppant = 40/70 PowerProp or Volume / Well = 3,714,000 gal 40/80 HydroProp or 100 mesh / Well = 570,000 lb % pad = 37% 30/60 CarboProp or Main Proppant / Well = 4,266,000 lb 30/50 InterProp or 20/40 InterPorp Estimated Pipe Friction = 3300 psi Estimated Perf Friction = 1200 psi BHTP = 11500 psi 6 perf clusters Ph = 5000 psi Volume / Cluster = 51,583 gal Surface Treating Pressure = 11000 psi 100 mesh / Cluster = 7,917 lb Main Proppant / Cluster = 59,250 lb 20
Simultaneous fracturing results Simulfrac or Zipperfrac Typically more microseismic activity Overlapping microseismic behavior Still see general fracturing behavior SPE 119896 (Rimrock)
Barnett - refrac potential Barnett Shale: Gel Frac Barnett Shale: Refrac Water Frac 1600 SRV vs. 6-month Average Gas Flow Ra ate (Mcf/d) 1400 1200 1000 800 600 400 Gel Frac Water Frac SPE 115771 (MCFD) 6-Month Average 3500 3000 2500 2000 1500 1000 y = 20.284x + 319.3 R 2 = 0.5571 200 500 0 0 180 360 540 720 900 1080 1260 1440 Time (days) 0 0 20 40 60 80 100 120 140 SRV (10 6 m3) 22
Marcellus - more height growth & planar vs. Barnett Experiment Lite frac 3000 ft lateral 6 stages 550,000 gal/stg Barnett 97 bpm rate 100,000 lb/stg Slickwater Typical More planar than Barnett Complexity More stages More perf clusters SPE 131783 Range Resources Corp
Haynesville - significant height growth Haynesville GMX fracture treatment 3,000 5,000 ft laterals 7 10 stages 300 ft spacing 2 perf clusters/stage Stimulation 300 to 500 K gal/stage 65 bpm rate 270,000 lb proppant/stage Slickwater, hybrid, & X-link SPE 12507 GMX Resources
Woodford - containment Fracture Lengths Stage 1: 2500 Stage 2: 3300 Stage 2 RF: 1400 Stage 4: 1200 Obs Carr Well Estate #113-1H Pettigrew 19-1H Obs Well #2 Treatment Pettigrew Well 18-1H Fracture Heights Stage 1: 250 Stage 2: 280 Stage 2 RF: 280 Stage 4: 280 Well contained Woodford FM SPE 110029 Antero Stage 1 events Stage 2 events Stage 2RF events Stage 3 events Looking NW
Utica Woodford Barnett Haynesville Marcellus Eagleford Bakken Porosity (%) 1-8% ~1.5 6 (Avg. ~3.8) 8-15% 3 8% 3-15% 2-12 % TVD (ft) 6,000 14,000 5,400 9,500 10,500 14,000 4,500-8,500 5,000-13,000 8,000-11,000 Thickness (ft) 100-220 100-500 60-350 50-300 40-500 6-15ft & 80-145 ft BHT ( F) 150-225 150 280-380º F 100-150 150-350 190-240 TOC (%) 3-9% 4-8% 2-5% 3-10% 0.5-9% Upper-11%-40% Lower=8%-21% Press Grad (psi/ft).45-.68 0.52 0.85-0.93 0.4-0.7 0.4 0.85 0.5-0.6 Frac Grad (psi/ft).7-.9 ~0.6 0.75 >0.90 0.9 1.2.88-1.1 0.70 0.85 Avg Perm (μd) 0.05-0.4 0.05 0.4 <0.005 0.5-2 400-1200 20-500 Sw (%) 33% <35 no free water <25 10-30 25-60 Lithology (%) Silica- Chert 30-60% Silica rich 35-50 v/v Shale is soft (ductile) Calcite rich-in areas? silica rich (in areas) organic rich High clay mineral fraction Variable formation properties Illite clay-dominated Quartz/Plagioclase/ Feldspar Carbonates Siderite/Pyrite ~3-5% carbon content High Illite-dominate clays Looks like poker chips High in Calcites Silty, sandy, dolomite grading to laminated shaly interval. Some natural fractures. Below is Sanish YM (x10 6 psi) 4-8 6-10 2-3 2-5 1-4 Upper/Lower= 2-4 Middle=4-6 PR (%) 0.15-0.25 0.13-0.25 0.23 0.27 0.19 0.23 0.20-0.27 Upper/Lower=-0.25-0.28 Middle= 0.2 0.25 Quartz, wt % 25-54 40-60 25-52 10-40 1 30 15-70 Plagioclase 7-13 2-5 8-17 0 10 0-17 1-3 feldspar, wt % Calcite, wt % 7-20 5-30 13-44 5 20 25-95 15-65 Smectite,wt % 2-8 1-5 - < 2 0-23 2-6 Illite, wt % 17-46 5-25 12-20 25-60 1-50 1-13 Kaolinite wt % 0 0 - < 2 0-14 0-2 Chlorite, wt % 1 0 4-7 0 10 0-7 1-3 Ro (Maturity of 075 0.75 145 1.45 0616 0.6-1.6 1 12 1.2 08 0.8 30 3.0+ 075 0.75 216 2.16 045 0.45 060 0.60 Shale)
Marcellus shale frac height vs aquifer depth
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