Post on 17-Jul-2018
Horizontal Fracturing in Shale Plays
Matt McKeon
Shortening the learning curve
• Historically: a trial-and-error processy p• Data acquisition• USA analog fields can speed up
evaluation and development
Quantify Construct Complete Analyze
Gas Rate SimGas RateOil RateOil rate Sim
2
Recent plays: fracture stimulations are evolving
WaterFracs 8-10 Stages
80 100 BPM
Hybrid/Conv 12-15 Stages
80-100 BPM 1.5 MM lbs prop 100 Mesh, 40/70 1 ppg Max
40-60 BPM 3-4 MM lbs prop
(total) 30/60 20/40
7 MM Gal 40,000 HHP 350-450’/Stage
30/60, 20/40 3-4 ppg 4 MM Gal 25,000 HHP 250-300’/Stage
2008 2009 2010
3
Eagle Ford
Even Barnett stimulation is still changing
Barnett Shale Completion Roadmap Barnett Shale Completion RoadmapBarnett Shale Completion Roadmap
80
90
600
700
Barnett Shale Completion Roadmap
30000
35000
4000
4500
50
60
70
PM
400
500
20000
25000
ge 2500
3000
3500
30
40Avg
. BP
200
300
10000
15000
bbl/s
tag
1500
2000
ge
0
10
20
0
100
0
5000
0
500
1000
span
ft.
BPMTreatment span sk
s/st
ag bbl/stagesks/stage
4
1999 2000 2001 2002 2003 2004 2005 2006 2007 2008
year1999 2000 2001 2002 2003 2004 2005 2006 2007 2008
Year
Shale Gas Development Process WorkflowData Acquisitionq
55
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 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 areassilica rich (in areas)
organic rich
Variable formation properties
Illite clay-dominatedQuartz/Plagioclase/
F ld
~3-5% carbon content
High Illite-dominate clays
L k lik “ k
Silty, sandy, dolomite grading to laminated shaly interval. Some
natural fractures.Below is Sanish
High clay mineral fraction
Feldspar Carbonates
Siderite/Pyrite
Looks like “poker chips”
High in Calcites
Below is Sanish
YM (x106 psi) 3.48 4-8 6-10 2-3 2-5 1-4 Upper/Lower= 2 - 4Middle=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=-0.25-0.280.28
Middle= 0.2 – 0.25
Quartz, wt % 54 25-54 40-60 25-52 10 - 40 1—30 15 - 70
Plagioclase feldspar, wt %
10 7-13 2-5 8-17 0 – 10 0-17 1 - 3
C l it t % 3 7 7 20 5 30 13 44 5 20 25 95 15 65Calcite, wt % 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
R (M t it f 1 23 0 75 1 45 0 6 1 6 1 1 2 0 8 3 0 0 75 2 16 0 45 0 60Ro (Maturity of Shale)
1.23 0.75 – 1.45 0.6-1.6 1 – 1.2 0.8 – 3.0+ 0.75 – 2.16 0.45 – 0.60
Analog Analysis
U.S. shale play: choose stimulation
Barnett Woodford Haynesville Eagle Ford MarcellusFrac System 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 15 10 14Stages 4-8 6-12 10 - 15 12-15 10-14
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 (2)BASS
(1) P&P(2) BASS
(1) P&P(2) BASS
(1) P&P(2) BASS
(1) P&P(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 42 4 ft
42 4 ft
4-61 2 ft
4-81 2 ft
3-52 4 ft2-4 ft. 2-4 ft. 1-2 ft. 1-2 ft. 2-4 ft.
Analog Analysis
Shale Analysis Log Where would you perforate? Where would you perforate?
What is the TOC and gas content?
Will it frac and what is the relativeReservoirPropertiesLithology Brittle
or Ductile?
Kerogen Content Natural
Fractures?
Unconfined Compressive
Strength
Mineralology
Will it frac and what is the relative fracture width and barriers?
What is the shale volumetric gas in place?Fractures?in place?
What is the shale porosity and permeability?
Where is the organic rich shale?
Where are the zones of highest kerogen content
ShaleType
Frac“Ease”
TOCHydrocarbon
Content
kerogen content
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SPE 115258
Shale fracturing simulation
• Designed for complex g pfracturing
• Couple available data with microseismic to optimize fluid system
d f d iand frac design • Recalibrate model based
on post job analyses andon post job analyses and regional variations
OBJECTIVEMaximize stimulated reservoir volume (SRV)( )
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Shale fracture characteristics
To create complexity you must have:1. Pre-existing natural fissures
2. Low differential horizontal stresses (net pressure > σm)
Ductile Brittle
( p m)3. Brittleness
•Woodford• Bakken
• Barnett• Haynesville• Eagleford
• Tight Gas Sands
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a e•Marcellus
Eagleford
Shale Completion Strategy: Based on Formation Brittleness & Liquid Production
Brittleness Fluid SystemFracture
GeometryFracture Width Closure Profile
SPE 115258
Brittleness Fluid System Geometry Closure Profile70% Slick Water
60% Slick Water
50% Hybridy
40% Hybrid
30% X-Linked
20% X-Linked20% X Linked
10% X-Linked
Proppant Fluid Proppant LiquidBrittleness
Proppant Concentration
FluidVolume
Proppant Volume
Liquid Production
70% Low High Low Low
60%
50%
40%
30%
20%
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20%
10% High Low High High
Shale fluid decisions
Shale Type Frac Type Fluid Type & Prop ppg
Brittle & low clay
•Complex network•No embedment
•Water 0-2% KCL•0.1-2 ppg
Brittle & high clay
•Complex network•Some embedment
•Water 2-7% KCL•Linear gel. •0.1- 3 ppg
Ductile & low clay
•Less complex•Moderate embedment
•Water 0-2% KCL•Linear gel. X-Link Tail•0 5 5 ppg•0.5 – 5 ppg
Ductile & high clay
•Bi-Wing•High embedment
•Linear Gel 2-7% KCL•X-Link
1414
High embedment•0.5-10 ppg
Lateral design, stage intervals & well spacing
• Lateral• Drilled in direction on minimum horizontal stress for transverse fracturing• 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 intervalsg• 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
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• Well Spacing
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
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The more clusters placed, the less contribute to production• Placement in better rock (fracs, brittle) may enhance SRV and production
Shale Fracture CharacteristicsDefinition of Brittleness from Rock Mechanics
SPE 115258
Haynesville
Marcellus Eagle Ford
Woodford
Marcellus g
Barnett
ood o d
70.00 56.00 42.00 28.00 14.00 00.00
BRIT
Barnett – example pump schedule
4000 ft laterals Span = ± 400 ft gal ppg prop lbs rate time
pad 100000 80 29.76 Stage size = 15,500 bbl/stage Prop volume = 4300 sks/stage Number of stages 6 → 8
P t 60% 100 h
pad 100000 80 29.76slurry 40000 0.3 100 mesh 12000 80 12.07slurry 40000 0.5 100 mesh 20000 80 12.18slurry 100000 0.6 100 mesh 60000 80 30.58slurry 100000 0.7 100 mesh 70000 80 30.71
Prop type: 60% 100 mesh, 40% 40/70
Rate = 70 BPM End sand conc = 1 25 – 1 5 ppg
yslurry 100000 0.8 100 mesh 80000 80 30.85slurry 100000 1 40/70 100000 80 31.12slurry 70000 1.25 40/70 87500 80 22.02flush 12000 80 3.57
End sand conc = 1.25 – 1.5 ppg Treating pressure = 4000 psi SRV (ft3)= 4/3*π*ABC
A=network width
% 100 mesh 56.34% total lbs 429500 lbs% 40/70 43.66% total time hr 3.38 hr% pad 15.38%A network width
B=frac lengthC=height/2
avg ppg 0.66 ppg
lbs 100 mesh 242000 lbslbs 40/70 187500 lbstotal volume 650000 gal 15,476 BBL
Formation hardness and proppant embedment
90
70
80
50
60B
HN
#
30
40
B
10
20
19
0Woodford Marcellus Floyd Eagle Ford Haynesville Bossier Barnett CV Lime Ohio SS Coal
Haynesville - example pump schedule
6 perforation cluster - 72 BPM
Stage Fluid Volume Prop Prop Concent Rate/cluster1 Treated Water 36000 -- 122 Guar (R11) 15000 100 mesh 0.5 12 7500 lb3 Guar (R11) 20000 100 mesh 0.75 12 15000 lb4 Guar (R11) 25000 100 mesh 1 12 25000 lb5 HYBOR G (R27) 20000 -- 126 HYBOR G (R27) 45000 Main Proppant 0.5 12 22500 lb7 HYBOR G (R27) 45000 Main Proppant 1 12 45000 lb8 HYBOR G (R27) 45000 Main Proppant 2 12 90000 lb( ) pp9 HYBOR G (R27) 36000 Main Proppant 3 12 108000 lb
10 HYBOR G (R27) 22500 Main Proppant 4 12 90000 lb11 Guar (R11) flush 12
Total fluid volume per stage 309500 gal Total proppant per stage 47500 lb 100 mesh355500 lb Main Proppant355500 lb Main Proppant
Pump Time per Stage 102 minutes
12 Stages per Well Main Proppant = 40/70 PowerProp orVolume / Well = 3,714,000 gal 40/80 HydroProp or100 mesh / Well = 570,000 lb % pad = 37% 30/60 CarboProp orMain Proppant / Well = 4,266,000 lb 30/50 InterProp or
20/40 InterPorpEstimated Pipe Friction = 3300 psiEstimated Perf Friction = 1200 psiBHTP = 11500 psi 6 perf clusters
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p pPh = 5000 psi Volume / Cluster = 51,583 galSurface Treating Pressure = 11000 psi 100 mesh / Cluster = 7,917 lb
Main Proppant / Cluster = 59,250 lb
Simultaneous fracturing results
• Simulfrac or Zipperfracpp
– Typically more microseismicmicroseismicactivity
– Overlapping microseismicmicroseismicbehavior
– Still see general fracturing behaviorfracturing behavior
SPE 119896 (Rimrock)
Barnett - refrac potential
Barnett Shale: Gel Frac Barnett Shale: Refrac – Water Frac
1000
1200
1400
1600
ate
(Mcf
/d)
Gel Frac Water Frac
SPE 115771
SRV vs. 6-month Average
2500
3000
3500
(MC
FD)
0
200
400
600
800
Gas
Flo
w R
a
y = 20.284x + 319.3R2 = 0.5571
0
500
1000
1500
20006-
Mon
th A
vera
ge
22
00 180 360 540 720 900 1080 1260 1440
Time (days)
0 20 40 60 80 100 120 140
SRV (106 m3)
Marcellus - more height growth & planar vs. Barnett
• Experiment– Lite fracLite 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– 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
Carr Estate 13-1H Pettigrew 19-1HObs Well #1 Obs Well #2 Obs Well #1Fracture Lengths•Stage 1: 2500’
Pettigrew 18-1HTreatment Well
•Stage 2: 3300’ •Stage 2 RF: 1400’
•Stage 4: 1200’
WoodfordFM
WoodfordFM
Fracture Heights•Stage 1: 250’
FMFM•Stage 2: 280’
•Stage 2 RF: 280’•Stage 4: 280’Well contained
Stage 1 events
Stage 2RF eventsSt 3 t
Stage 2 eventsStage 1 events
Stage 2RF eventsSt 3 t
Stage 2 eventsStage 1 events
Stage 2RF eventsSt 3 t
Stage 1 events
Stage 2RF eventsSt 3 t
Stage 2 events
•Well contained
Stage 3 events Looking NWStage 3 eventsStage 3 eventsStage 3 events Looking NWSPE 110029Antero
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 areassilica rich (in areas)
organic rich
Variable formation properties
Illite clay-dominatedQuartz/Plagioclase/
F ld
~3-5% carbon content
High Illite-dominate clays
L k lik “ k
Silty, sandy, dolomite grading to laminated shaly interval. Some
natural fractures.Below is Sanish? High clay mineral
fractionFeldspar
CarbonatesSiderite/Pyrite
Looks like “poker chips”
High in Calcites
Below is Sanish
YM (x106 psi) 4-8 6-10 2-3 2-5 1-4 Upper/Lower= 2 - 4Middle=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
?0.28
Middle= 0.2 – 0.25
Quartz, wt % 25-54 40-60 25-52 10 - 40 1—30 15 - 70
Plagioclase feldspar, wt %
7-13 2-5 8-17 0 – 10 0-17 1 - 3
C l it t % 7 20 5 30 13 44 5 20 25 95 15 65Calcite, 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
R (M t it f 0 75 1 45 0 6 1 6 1 1 2 0 8 3 0 0 75 2 16 0 45 0 60Ro (Maturity of Shale)
0.75 – 1.45 0.6-1.6 1 – 1.2 0.8 – 3.0+ 0.75 – 2.16 0.45 – 0.60
Marcellus shale – frac height vs aquifer depth
Thank You