Conductivity (md*ft)
HOW TO GET THE MOST OUT OF YOUR MULTI-STAGE UNCONVENTIONAL FRACTURE DESIGN Based on SPE-184816 Bob Shelley, PE Brian Davidson Koras Shah Amir Mohammadnejad, PhD Stanislav Sheludko
McGuire and Sikora Post Fracture Productivity Increase
π€ππππππ πππππ 2
β’
For high-permeability reservoirs, fracture conductivity is more important than fracture length.
β’
For low-permeability reservoirs, fracture length is more important than fracture conductivity.
β’
For a given fracture length, there is an optimum value of conductivity ratio
β’
For horizontal wellbores, the number of fractures propagated can multiply the stimulation ratio for the well.
3 Well Utica Pad, Monroe Co. OH - TVD 10,600 ft. β’
Direct Offsets β Similar Prod Start Dates β 220 Days Production
β’ β’
Similar Lateral Lengths Different Frac Designs β Proppant Volume & Selection β Frac Volume β Frac Stages Completed
3
Well
Prop Description
Prop. Wt. (Million Lb.)
Fluid Vol. (Million gal.)
Lateral Length (ft.)
Frac Stages Completed
Perf Clusters per Stage
A B C
Resin Coated Sand (RCS) - Sand Low Density Ceramic (LDC) - Sand Low Density Ceramic (LDC)
10.3 11.5 7.1
9.3 10.3 8.8
5,800 6,100 6,200
24 24 21
5 5 5
Well Production Comparison RCS-Sand LDC-Sand LDC
4
Well Performance Modeling Approach Production History Match
Drilling, Reservoir & Geology
Property (Unit)
FP1
FP2
FP3
Pore Pressure (psi)
9,074
9,074
9,074
Pore Pressure Gradient (psi/ft)
0.85
0.85
0.85
Reservoir Permeability (mD)
0.0035
0.0035
0.0035
Effective Fracture Half-length (ft)
170
135
100
Effective Fracture Height (ft)
110
75
75
# Fractures
114
114
114
Effective Fracture Conductivity (mD-ft)
11.0
6.0
3.0
Dimensionless Conductivity [FCD]
5.9
4.0
2.8
Frac Pressure Match
Calibrated Frac Model
Calibrated Reservoir Model Compare Fracture Characteristics
Frac Model Geometry - Wellbore Profile View RCS-Sand; 120 Fractures
LDC-Sand; 114 Fractures
LDC; 94 Fractures
Reservoir Model - Production History Match (Well B)
FP 1
7
FP 2
FP 3
Property (Unit)
FP1
FP2
FP3
Pore Pressure (psi)
9,074
9,074
9,074
Pore Pressure Gradient (psi/ft)
0.85
0.85
0.85
Reservoir Permeability (mD)
0.0035
0.0035
0.0035
# Fractures
114
114
114
Effective Fracture Half-length (ft)
170
135
100
Effective Fracture Height (ft)
110
75
75
Effective Fracture Conductivity (mD-ft)
11.0
6.0
3.0
Dimensionless Conductivity [Fcd]
5.9
4.0
2.8
Surface Flowing Pressure & Stress on Proppant (Well B) Actual Flowing Pressure (psi)
8000
6,800 psi
Stress on Proppant (psi)
7000 6000
4,500 psi
5000 4000 3000 2000 1000
Flow Period 1
Flow Period 3
Flow Period 2
0 0
20
40
60
80
100
120
Producing Time (Days) 8
140
160
180
200
220
Stress vs. Proppant Conductivity 20
-36%
-58% -60% -90%
Conductivity (md*ft)
LDC 30/50 White Sand 30/50
15 4,500 psi
6,800 psi
10
5
0 1000
3000
5000
7000
Stress (psi) 9
9000
11000
Source: Dynamic Conductivity from PredictK (StimLab)
Fracture Modeling RCS - Sand Most Degradation
LDC - Sand
Most Effective
LDC Most Efficient
Fracture Characteristics
RCSSand
LDCSand
LDC
Proppant (lb)
85,800
100,900
75,500
Fluid Volume (gal)
77,500
90,400
93,600
Avg Created Half-Length (ft)
650
730
680
Avg. Propped Half-Length (ft)
540
630
530
Avg Propped height (ft)
200
230
190
Effective Half-Length (ft)
150 - 75
170 - 100
165 - 100
Effective Height (ft)
85 - 60
110 - 75
65 - 60
Effective Cond. (md-ft)
10 - 2
11 - 3
10 - 5
Contributing Area (Msqft/frac) 25.5 β 9.0 37.4 β 15.0 21.5 β 12.0 Fracture Efficiency %
8
12.0 - 4.2
12.9 - 5.3
10.5 - 6.1
Fracture Efficiency vs. Conductivity Fracture Efficiency (FE) = Effective Area (Aeff)/Propped Area (Aprop)
LDC LDC-Sand RCS-Sand
r2=0.965
πΉπΈ = 0.01 β πΉπ + 0.02
9
Frac Design Production Forecasts 4
Cumulative Gas (BCF)
3.5 3 2.5 2 1.5 1 0.5 0 0
0.1
0.2
0.3
0.4
Case
Lateral Length (ft)
Frac Cost (Millon $)
Frac Stages
Total Proppant (Million lb)
Fluid Volume (Thousand BBL)
1Y Cum Gas (BCF)
Resin Coated Sand-Sand
5,800
$1.91
24
10.3
221
2.8
Sand
5,800
$1.51
24
10.3
221
2.3
Large Sand
5,800
$2.50
24
21.3
389
3.2
Low Density Ceramic-Sand
5,800
$2.64
24
12.1
258
3.7
0.5
Time (Years) 10
0.6
0.7
0.8
0.9
1
Frac Design Economic Forecasts
11
Case
1 Year NPV (Million $)
Fracturing Cost Total Proppant Fluid Volume (Million $) (Million lb) (Thousand BBL)
Low Density Ceramic-Sand
$7.92
$2.64
12.1
Trk Loads Proppant
1 Y Cum Gas (BCF)
258
270
3.7
Large Sand
$6.69
$2.50
21.3
389
473
3.2
Resin Coated Sand-Sand
$6.20
$1.91
10.3
221
229
2.8
Sand
$5.03
$1.51
10.3
221
229
2.3
2 Well Utica Pad, Belmont Co. OH - TVD 8,600 ft. o
o
Each Well used Different Frac Designs o
Large volume 100% sand
o
Smaller volume 100% ceramic
Frac Stage Cost Neutral
Parameter (Unit) Horizontal Length (ft) # of Stages # of Clusters/Stage Cluster Spacing (ft) Total Proppant (MMlb) Total Fluid (Mbbl) 2017 Frac Cost (MM$)
Ceramic 6,840 27 5 48 5.6 143 2.6
Sand 9,110 38 5 48 17.0 258 3.5
Well Production Comparison
Fracture Modeling Sand Frac
100 Day Production History Match Frac Type
Sand Well Frac Stages Leff β 188β
Sand 38
27
8,100
5,400
5
5
Created Half Length (ft)
469
342
Prop HalfLLength (ft) β 206β
447
332
Prop Height (ft)
212
202
πΉππ =
Fcd = 2.1
Prop Wt (lb)/Stage
Leff
Frac Vol (bbl)/Stage
Lprop
Ceramic
Fractures/Stage
πππππβπ€π 450,000 200,000 πβπβπΏ
Ceramic Well
Ceramic Frac
eff
πΏ
Fcd = 3.6 Leff
Lprop
Frac Conductivity (md-ft) πππ
β
πππππ 103 βπ€π 158 πβπβπΉππ
Fracture Effectiveness over Time 230 Day Production History Matches Sand Leff β 140 ft
Formation Pressure Frac Type Perm Gradient (mD) (psi/ft) Sand Ceramic
0.0087 0.0087
0.8 0.8
Ceramic Leff β 190 ft
100 day 100 Day 100 day Est Stress 230 Day Leff (ft) md-ft On Prop Leff (ft) (psi) 188 206
11 20
3,383 3,745
140 190
230 Day Change Change md-ft Leff md-ft 2.25 5.00
-26% -8%
-80% -75%
230 day Est Stress On Prop (psi)
Cum Gas per Frac Stage (MCF)
4,517 4,985
56,157 78,351
40% More
Proppant Characteristics Comparison Laboratory Conductivity Measurements at 1 lb/ft2 Concentration
Day 0
Day 100 Day 230
Conductivity (md-ft)
Fc Ratioβ1.5 Fc Ratioβ2.1 Fc Ratioβ2.8
Stress (psi)
Utica Operator Perspective β’
β’
Consol Energy, September 2016, SPE 184078, Dry Utica Proppant and Frac Fluid Design Optimization; βfor the ceramic well to be cost effective, between 20% to 30% uplift in production is needed to justify the incremental capex in todays markets. Based on the current production data and BHFP, the ceramic well is on the path to reaching those expectations.β EQT, February 2017, World Oil Shaletech; βWe had a view that maybe sand would work, and at the time would be significantly cheaper than ceramics, so we switched over,β says new CEO Steven T. Schlotterbeck. βThose next couple of wells were significant underperformers from the Scotts Run. And then we switched back to ceramics for the last couple of wells, and they were significantly better than the wells with sand. Those two wells have gotten us much closer to the target recoveries that we think we need. Our current plans is to use ceramics for all wells in the future.β
5 Well Eagle Ford Pad, McMullen Co. TX - TVD 10,600 ft. β’ β’
β’
Significant fracture inefficiency. Apparent fracture degradation with aggressive production drawdown. Data indicates that there is a positive relationship between fracture conductivity and efficiency.
Fracture Efficiency (FE) = Effective Area (Aeff)/Propped Area (Aprop)
20
3 Well Eagle Ford Pad, McMullen Co. TX - TVD 11,600 ft. β’ β’
β’
Significant fracture inefficiency Apparent fracture degradation with aggressive production drawdown. Data indicates that there is a positive relationship between fracture conductivity and efficiency.
Fracture Efficiency (FE) = Effective Area (Aeff)/Propped Area (Aprop)
21
Summary ο§ All of the cases presented indicate significant hydraulic fracture inefficiency. ο§ Due to stranding of large portions of the propped fracture area which consequently do not contribute to well performance.
ο§ Increasing fracture conductivity appears to mitigate this issue resulting in improved fracture effectiveness, greater effective frac length and area.
ο§ Proppant placement difficulties which reduce cluster efficiency, proppant and treatment volumes placed; decrease fracture effectiveness and well production. ο§ These issues can be caused by formation and/or completion/frac design issues.
ο§ This data indicates that a hydraulic fractureβs effectiveness degrades over time. It was necessary to incorporate fracture degradation to match the production performance of these wells. ο§ Pressure drawdown due to production which increases the stress on proppants appears to reduce fracture conductivity and effective fracture area. 22
Thank You!
McGuire and Sikora Post Fracture Productivity Increase
π€ππππππ πππππ 2
β’
For high-permeability reservoirs, fracture conductivity is more important than fracture length.
β’
For low-permeability reservoirs, fracture length is more important than fracture conductivity.
β’
For a given fracture length, there is an optimum value of conductivity ratio
β’
For horizontal wellbores, the number of fractures propagated can multiply the stimulation ratio for the well.
3 Well Utica Pad, Monroe Co. OH - TVD 10,600 ft. β’
Direct Offsets β Similar Prod Start Dates β 220 Days Production
β’ β’
Similar Lateral Lengths Different Frac Designs β Proppant Volume & Selection β Frac Volume β Frac Stages Completed
3
Well
Prop Description
Prop. Wt. (Million Lb.)
Fluid Vol. (Million gal.)
Lateral Length (ft.)
Frac Stages Completed
Perf Clusters per Stage
A B C
Resin Coated Sand (RCS) - Sand Low Density Ceramic (LDC) - Sand Low Density Ceramic (LDC)
10.3 11.5 7.1
9.3 10.3 8.8
5,800 6,100 6,200
24 24 21
5 5 5
Well Production Comparison RCS-Sand LDC-Sand LDC
4
Well Performance Modeling Approach Production History Match
Drilling, Reservoir & Geology
Property (Unit)
FP1
FP2
FP3
Pore Pressure (psi)
9,074
9,074
9,074
Pore Pressure Gradient (psi/ft)
0.85
0.85
0.85
Reservoir Permeability (mD)
0.0035
0.0035
0.0035
Effective Fracture Half-length (ft)
170
135
100
Effective Fracture Height (ft)
110
75
75
# Fractures
114
114
114
Effective Fracture Conductivity (mD-ft)
11.0
6.0
3.0
Dimensionless Conductivity [FCD]
5.9
4.0
2.8
Frac Pressure Match
Calibrated Frac Model
Calibrated Reservoir Model Compare Fracture Characteristics
Frac Model Geometry - Wellbore Profile View RCS-Sand; 120 Fractures
LDC-Sand; 114 Fractures
LDC; 94 Fractures
Reservoir Model - Production History Match (Well B)
FP 1
7
FP 2
FP 3
Property (Unit)
FP1
FP2
FP3
Pore Pressure (psi)
9,074
9,074
9,074
Pore Pressure Gradient (psi/ft)
0.85
0.85
0.85
Reservoir Permeability (mD)
0.0035
0.0035
0.0035
# Fractures
114
114
114
Effective Fracture Half-length (ft)
170
135
100
Effective Fracture Height (ft)
110
75
75
Effective Fracture Conductivity (mD-ft)
11.0
6.0
3.0
Dimensionless Conductivity [Fcd]
5.9
4.0
2.8
Surface Flowing Pressure & Stress on Proppant (Well B) Actual Flowing Pressure (psi)
8000
6,800 psi
Stress on Proppant (psi)
7000 6000
4,500 psi
5000 4000 3000 2000 1000
Flow Period 1
Flow Period 3
Flow Period 2
0 0
20
40
60
80
100
120
Producing Time (Days) 8
140
160
180
200
220
Stress vs. Proppant Conductivity 20
-36%
-58% -60% -90%
Conductivity (md*ft)
LDC 30/50 White Sand 30/50
15 4,500 psi
6,800 psi
10
5
0 1000
3000
5000
7000
Stress (psi) 9
9000
11000
Source: Dynamic Conductivity from PredictK (StimLab)
Fracture Modeling RCS - Sand Most Degradation
LDC - Sand
Most Effective
LDC Most Efficient
Fracture Characteristics
RCSSand
LDCSand
LDC
Proppant (lb)
85,800
100,900
75,500
Fluid Volume (gal)
77,500
90,400
93,600
Avg Created Half-Length (ft)
650
730
680
Avg. Propped Half-Length (ft)
540
630
530
Avg Propped height (ft)
200
230
190
Effective Half-Length (ft)
150 - 75
170 - 100
165 - 100
Effective Height (ft)
85 - 60
110 - 75
65 - 60
Effective Cond. (md-ft)
10 - 2
11 - 3
10 - 5
Contributing Area (Msqft/frac) 25.5 β 9.0 37.4 β 15.0 21.5 β 12.0 Fracture Efficiency %
8
12.0 - 4.2
12.9 - 5.3
10.5 - 6.1
Fracture Efficiency vs. Conductivity Fracture Efficiency (FE) = Effective Area (Aeff)/Propped Area (Aprop)
LDC LDC-Sand RCS-Sand
r2=0.965
πΉπΈ = 0.01 β πΉπ + 0.02
9
Frac Design Production Forecasts 4
Cumulative Gas (BCF)
3.5 3 2.5 2 1.5 1 0.5 0 0
0.1
0.2
0.3
0.4
Case
Lateral Length (ft)
Frac Cost (Millon $)
Frac Stages
Total Proppant (Million lb)
Fluid Volume (Thousand BBL)
1Y Cum Gas (BCF)
Resin Coated Sand-Sand
5,800
$1.91
24
10.3
221
2.8
Sand
5,800
$1.51
24
10.3
221
2.3
Large Sand
5,800
$2.50
24
21.3
389
3.2
Low Density Ceramic-Sand
5,800
$2.64
24
12.1
258
3.7
0.5
Time (Years) 10
0.6
0.7
0.8
0.9
1
Frac Design Economic Forecasts
11
Case
1 Year NPV (Million $)
Fracturing Cost Total Proppant Fluid Volume (Million $) (Million lb) (Thousand BBL)
Low Density Ceramic-Sand
$7.92
$2.64
12.1
Trk Loads Proppant
1 Y Cum Gas (BCF)
258
270
3.7
Large Sand
$6.69
$2.50
21.3
389
473
3.2
Resin Coated Sand-Sand
$6.20
$1.91
10.3
221
229
2.8
Sand
$5.03
$1.51
10.3
221
229
2.3
2 Well Utica Pad, Belmont Co. OH - TVD 8,600 ft. o
o
Each Well used Different Frac Designs o
Large volume 100% sand
o
Smaller volume 100% ceramic
Frac Stage Cost Neutral
Parameter (Unit) Horizontal Length (ft) # of Stages # of Clusters/Stage Cluster Spacing (ft) Total Proppant (MMlb) Total Fluid (Mbbl) 2017 Frac Cost (MM$)
Ceramic 6,840 27 5 48 5.6 143 2.6
Sand 9,110 38 5 48 17.0 258 3.5
Well Production Comparison
Fracture Modeling Sand Frac
100 Day Production History Match Frac Type
Sand Well Frac Stages Leff β 188β
Sand 38
27
8,100
5,400
5
5
Created Half Length (ft)
469
342
Prop HalfLLength (ft) β 206β
447
332
Prop Height (ft)
212
202
πΉππ =
Fcd = 2.1
Prop Wt (lb)/Stage
Leff
Frac Vol (bbl)/Stage
Lprop
Ceramic
Fractures/Stage
πππππβπ€π 450,000 200,000 πβπβπΏ
Ceramic Well
Ceramic Frac
eff
πΏ
Fcd = 3.6 Leff
Lprop
Frac Conductivity (md-ft) πππ
β
πππππ 103 βπ€π 158 πβπβπΉππ
Fracture Effectiveness over Time 230 Day Production History Matches Sand Leff β 140 ft
Formation Pressure Frac Type Perm Gradient (mD) (psi/ft) Sand Ceramic
0.0087 0.0087
0.8 0.8
Ceramic Leff β 190 ft
100 day 100 Day 100 day Est Stress 230 Day Leff (ft) md-ft On Prop Leff (ft) (psi) 188 206
11 20
3,383 3,745
140 190
230 Day Change Change md-ft Leff md-ft 2.25 5.00
-26% -8%
-80% -75%
230 day Est Stress On Prop (psi)
Cum Gas per Frac Stage (MCF)
4,517 4,985
56,157 78,351
40% More
Proppant Characteristics Comparison Laboratory Conductivity Measurements at 1 lb/ft2 Concentration
Day 0
Day 100 Day 230
Conductivity (md-ft)
Fc Ratioβ1.5 Fc Ratioβ2.1 Fc Ratioβ2.8
Stress (psi)
Utica Operator Perspective β’
β’
Consol Energy, September 2016, SPE 184078, Dry Utica Proppant and Frac Fluid Design Optimization; βfor the ceramic well to be cost effective, between 20% to 30% uplift in production is needed to justify the incremental capex in todays markets. Based on the current production data and BHFP, the ceramic well is on the path to reaching those expectations.β EQT, February 2017, World Oil Shaletech; βWe had a view that maybe sand would work, and at the time would be significantly cheaper than ceramics, so we switched over,β says new CEO Steven T. Schlotterbeck. βThose next couple of wells were significant underperformers from the Scotts Run. And then we switched back to ceramics for the last couple of wells, and they were significantly better than the wells with sand. Those two wells have gotten us much closer to the target recoveries that we think we need. Our current plans is to use ceramics for all wells in the future.β
5 Well Eagle Ford Pad, McMullen Co. TX - TVD 10,600 ft. β’ β’
β’
Significant fracture inefficiency. Apparent fracture degradation with aggressive production drawdown. Data indicates that there is a positive relationship between fracture conductivity and efficiency.
Fracture Efficiency (FE) = Effective Area (Aeff)/Propped Area (Aprop)
20
3 Well Eagle Ford Pad, McMullen Co. TX - TVD 11,600 ft. β’ β’
β’
Significant fracture inefficiency Apparent fracture degradation with aggressive production drawdown. Data indicates that there is a positive relationship between fracture conductivity and efficiency.
Fracture Efficiency (FE) = Effective Area (Aeff)/Propped Area (Aprop)
21
Summary ο§ All of the cases presented indicate significant hydraulic fracture inefficiency. ο§ Due to stranding of large portions of the propped fracture area which consequently do not contribute to well performance.
ο§ Increasing fracture conductivity appears to mitigate this issue resulting in improved fracture effectiveness, greater effective frac length and area.
ο§ Proppant placement difficulties which reduce cluster efficiency, proppant and treatment volumes placed; decrease fracture effectiveness and well production. ο§ These issues can be caused by formation and/or completion/frac design issues.
ο§ This data indicates that a hydraulic fractureβs effectiveness degrades over time. It was necessary to incorporate fracture degradation to match the production performance of these wells. ο§ Pressure drawdown due to production which increases the stress on proppants appears to reduce fracture conductivity and effective fracture area. 22
Thank You!
