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SPE DISTINGUISHED LECTURER SERIES is funded principally through a grant of the SPE FOUNDATION The Society gratefully acknowledges those companies that support the program by allowing their professionals to participate as Lecturers. And
is funded principally through a grant of the
The Society gratefully acknowledges those companies that support the program by allowing their professionals to participate as Lecturers. And special thanks to The American Institute of Mining, Metallurgical, and Petroleum Engineers (AIME) for their contribution to the program.
Presented By: Larry K. Britt Presented By: Larry K. Britt NSI Technologies, Inc. NSI Technologies, Inc. 918 918-
496-
2071
History of Water Frac’s Frac’s
Water as a Fracturing Fluid
Clean vs vs Dirty Dirty
Residual Fracture Width
Development of Water Frac Guidelines
Reservoir Quality Considerations
Geomechanical Considerations
Fracture Design Considerations
Water Frac Application Review
The History Of Water Fracs Is As Long As The History Of Fracturing Itself!
1988 Paper On The Hugoton Field
Water Water Fracs Fracs In Hugoton Not Better Or Cheaper? In Hugoton Not Better Or Cheaper?
Nitrogen Foam 100 M-Gal 60Q foam pumped at 75 bpm Pad Volume was 36% of the Total Job 12/20 Sand Proppant pumped at 1 to 5 PPG Slick Water 140 M-Gal 20# Slick Water pumped at 100 bpm Pad Volume was 23% of the Total Job 12/20 Sand Proppant pumped at 0.5 to 2.5 PPG Borate X-Link Gel (30# HPG) 100 M-Gal 30 ppt HPG, borate X-Link gel at 60 bpm Pad Volume was 35% of the Total Job 12/20 Sand Proppant pumped at 1 to 5 PPG
N2 TW XL N2 TW XL
SPE 49104 “Water Frac Results From 50 Cotton Valley Wells”
Water Water Fracs Fracs Lower IP Shallower Decline Than Gel! Lower IP Shallower Decline Than Gel!
No Better Than Gel Fracs
100 200 300 400 500 500 1,000 1,500
TIME (days)
Water Frac 82,000 lb X-Link Frac 1,100,000 lb X-Link Frac 520,000 lb
MCFPD
0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 10 20 30 50 100 200 300 500 1,000
Cumulative Frequency
Water Fracs Gel Fracs
6-Month Cum, MMCF
SPE 60285 “Comprehensive Evaluation Of Fractured Gas Wells Utilizing Production Data”
Water Water Fracs Fracs In ETCV Not Better, Cheaper? In ETCV Not Better, Cheaper?
100 200 300 400 500 600
Area 1
Gel Fracs
Area 4 Area 3 Area 2 Area 6 Area 5 Area 7 Area 8
"Normalized" Production Data Water Fracs
MCFPD
Cost Reduction Results From Material Scheduling And Alliance Contracts!
Water Water Fracs Fracs In ETCV Cheaper? In ETCV Cheaper?
A Review Of Gel And Water Fracs:
Parameter Description Cross -linked Gel Fracs Treated Water
Average Pump Rate, BPM 29.0 25 Average Pad Fraction, % 34.9 41.5 Average ISIP, psi 2844 2604 Average Sand Pumped, mlbs 526.6 71.0
6.3 2.3 Average Treating Pressure, psi 2286 4245 Number of Stimulation Stages 3.3 3.5
Always Been Used In Naturally Fissured Reservoirs! Always Been Used In Naturally Fissured Reservoirs!
150 300 450 600
150 300
West-East (ft) North (ft)
MWX-3 MWX2 MONITOR N74W AT INTERSECTION HORIZONTAL WELL
150 300 450 600
150 300
West-East (ft) North (ft)
MWX-3 MWX2 MONITOR N74W AT INTERSECTION HORIZONTAL WELL
Multi-Well Site Mesaverde Formation
Summary: Summary:
Long History Of Application
Lower IP, Shallower Production Decline?
Gels Generally As Good Or Better?
Water Fracs Fracs Cheaper Cheaper -
“More Economic?”
Good For Some Some Fissured Reservoirs! Fissured Reservoirs!
History of Water Fracs Fracs
Water as a Fracturing Fluid
Clean vs vs Dirty Dirty
Residual Fracture Width
Development of Water Frac Guidelines
Reservoir Quality Considerations
Geomechanical Considerations
Fracture Design Considerations
Water Frac Application Review
Breaking
Cheap
Cleanliness
Compatibility
Formation
Formation Fluid
Reservoir Pressure
Easy to Mix
Additive Sensitivity
Environmentally
Fluid Loss
Low Pump Pressure
Safety
Viscosity ???
Poor Proppant Transport
Height Containment
Poor Fracture Width
√ √ √ √ √ √ X X X/√/X
Residual Material in Fracture
Gel Residue
Damaged Proppant
Formation Fines
Degradation of Proppant
Flow/Reservoir Considerations
Viscosity
Capillary Pressure
Non-
Darcy Flow
Multi-
Phase Flow
Darcy versus Yield-
Power Law
What Affects Proppant Pack Permeability? What Affects Proppant Pack Permeability?
A 20% Porosity Reduction Results in a 60% Loss in Permeability!
Gel Residue
Damaged Proppant
Formation Fines
Proppant Degradation
The Effect of Residual Material in Fracture? The Effect of Residual Material in Fracture?
Typical East Texas Fracture Stimulation: Typical East Texas Fracture Stimulation:
(527 (527 mlbs mlbs 20/40 Jordan Sand, 138 20/40 Jordan Sand, 138 mgals mgals of 30# /mgal Guar)
Volume of Porosity Volume of Porosity = (527,000 lbs/22 lbs/gal) * (0.4/(1 = (527,000 lbs/22 lbs/gal) * (0.4/(1-
0.4)) = 15,970 gals = 15,970 gals Residual Polymer = 0.05 * 138,000 gals Residual Polymer = 0.05 * 138,000 gals = 6,900 gals = 6,900 gals Proppant Fines = 0.032 * (527,000 lbs/22 lbs/gal) = Proppant Fines = 0.032 * (527,000 lbs/22 lbs/gal) = 766 gals 766 gals Formation Fines = 0.0 Formation Fines = 0.0 = = 0 gals 0 gals Proppant Degradation = 0.0 Proppant Degradation = 0.0 = = 0 gals 0 gals Damage Volume = Damage Volume = 7,666 gals 7,666 gals
Fractional Reduction in Porosity= 0.48 Fractional Reduction in Porosity= 0.48
Why Does it Matter? Why Does it Matter?
Why Does it Matter? Why Does it Matter?
Because we are Paying for Length and Conductivity! Because we are Paying for Length and Conductivity!
A 48% Porosity Reduction Results in a 90% Loss in Permeability!
Reduced k kf
fw
w Increases $$! Increases $$!
Reduced k kf
fw
w Reduces Reduces x xf
f !
!
FCD
CD= 2 Optimum (
= 2 Optimum (Prats Prats) )
kf
fw
w Impact on Effective Impact on Effective x xf
f
What Affects Proppant Pack Permeability? What Affects Proppant Pack Permeability?
Residual Material in Fracture
Gel Residue
Damaged Proppant
Temperature Degradation of Proppant
Formation Fines
Flow/Reservoir Considerations
Viscosity
Capillary Pressure
Non-
Darcy Flow
Multi-
Phase Flow
Darcy versus Yield-
Power Law
The Effect of Flow/ Reservoir Considerations? The Effect of Flow/ Reservoir Considerations?
Viscosity
Capillary Pressure
Non-
Darcy Flow
Multi-
Phase Flow
Darcy versus Yield Power Law
Damage Mechanism Damage Mechanism
The Effect of Flow Reservoir Considerations? The Effect of Flow Reservoir Considerations?
Viscosity
Capillary Pressure
Non-
Darcy Flow
Multi-
Phase Flow
Darcy vs. Yield Power Law
Damage Mechanism Damage Mechanism
The Effect of Flow Reservoir Considerations? The Effect of Flow Reservoir Considerations?
Viscosity
Capillary Pressure
Non-
Darcy Flow
Multi-
Phase Flow
Darcy vs. Yield Power Law
Damage Mechanism Damage Mechanism
0.01 0.1 1 10 100 1000 10000 100000 1000000 10000000 Cumulative Production (MCF) PI ratio (MCF/D/psi) Production spikes caused by changes in bottom hole pressure used to control well Gel Damage Multiphase Flow Effect Viscous Effects phi = 7.2% kg = .01 md h = 40 ft A = 160 acres pi = 5830 psi xf = 2500 ft kfw = 188 md-ft gel visc. = 9.56 cp
The Effect of Flow/ Reservoir Considerations? The Effect of Flow/ Reservoir Considerations?
Viscosity
Capillary Pressure
Non-
Darcy Flow
Multi-
Phase Flow
Darcy vs. Yield Power Law Damage Mechanism Damage Mechanism
Yield Yield-
Power Law Supported By:
Anecdotal Field Data
PTA in TFG Reservoirs
Limited Laboratory Data
Simulation Studies
Actual Well Performance
The Effect of Flow Reservoir Considerations? The Effect of Flow Reservoir Considerations?
Laboratory Data Supports Yield Stress Concept Laboratory Data Supports Yield Stress Concept
The Effect of Flow/ Reservoir Considerations? The Effect of Flow/ Reservoir Considerations?
Fracture Fluid Cleanup Fracture Fluid Cleanup
(Cotton Valley) Well (Cotton Valley) Well After 5 Years of Production After 5 Years of Production Darcy Cleanup Darcy Cleanup vs vs. . Yield Yield-
Power Law
Darcy Flow Yield-Power Law Wellbore Fracture Tip @ 2500’
Microsoft
The Effect of Flow Reservoir Considerations? The Effect of Flow Reservoir Considerations?
k kf
fw
w Critical to Fracture Cleanup for Yield Critical to Fracture Cleanup for Yield-
Power Law Flow!
200 400 600 800 1,000 1,200 500 1,000 1,500 2,000 2,500 3,000 Fracture Conductivity, mdft Effective Fracture Half Length, ft
East Texas Fracture: East Texas Fracture:
Only 40% (1000’) of Fracture Length Fracture Length Cleaned Up! Cleaned Up!
FCD of 8-
10 Needed to Cleanup Entire Cleanup Entire Fracture! Fracture!
Post Frac Buildups
The Effect of Flow Reservoir Considerations? The Effect of Flow Reservoir Considerations?
Operational Effects: Operational Effects: Pressure and Permeability Pressure and Permeability Matters! Matters! Tight Formation Gas Wells Tight Formation Gas Wells May Benefit From May Benefit From Systematic Shut Systematic Shut-
ins!
The Effect of Flow/ Reservoir Considerations? The Effect of Flow/ Reservoir Considerations?
Shut Shut-
ins Prior to Gas Breakthrough May Breakthrough May Improve Polymer Improve Polymer Recovery! Recovery!
The Effect of Flow/ Reservoir Considerations? The Effect of Flow/ Reservoir Considerations?
Systematic Shut Systematic Shut-
ins Can Improve Gas Recovery!
Productivity Polymer Returned
Polymer Recovery Polymer Recovery Results in Results in Improved Improved Productivity! Productivity!
The Effect of Flow/ Reservoir Considerations? The Effect of Flow/ Reservoir Considerations?
To Achieve Our Fracturing Objectives ! To Achieve Our Fracturing Objectives !
Incorporate Cleanup Considerations in the Fracture Stimulation Design the Fracture Stimulation Design
Reduce/Eliminate Polymer
Reduce/Eliminate Proppant Damage
Increase Fracture Conductivity
Design For FCD >>10 In TFG Wells
Evaluate Operational Issues
Flow back
Systematic Shut-
ins
History of Water Fracs Fracs
Water as a Fracturing Fluid
Clean vs vs Dirty Dirty
Residual Fracture Width
Development of Water Frac Guidelines
Reservoir Quality Considerations
Geomechanical Considerations
Fracture Design Considerations
Water Frac Application Review
What Is The Effect Of Poor Proppant Coverage!
Single Layer Evaluation of Water Frac Productivity 60% of Zone Stimulated kv/kh Ratio Varied
Assumes 0 Un-Propped kfw!
20 % 100 % 80 % 60 % 40 % 20 % 100 % 80 % 60 % 40 %
Time, Days Productivity, MMCFPD
Full Vertical Frac 80% Vertical Frac, kv=0.01kh 60% Vertical Frac, kv=0.01kh 40% Vertical Frac, kv=0.01kh 20% Vertical Frac, kv=0.01kh 0.0001 0.0010 0.0100 0.1000 1.0000 10.0000 1 10 100 1000 10000 100000Time, Days Productivity, MMCFPD
Full Vertical Frac 80% Vertical Frac, kv=0.01kh 60% Vertical Frac, kv=0.01kh 40% Vertical Frac, kv=0.01kh 20% Vertical Frac, kv=0.01kh 100 200 300 400 500 600 700 800 900 1000 5 10 15 20 25 30 35 40 45 50Time, Years Cumulative Gas, MMCF
Full Vertical Frac 80% Vertical Frac, kv=0.01kh 60% Vertical Frac, kv=0.01kh 40% Vertical Frac, kv=0.01kh 20% Vertical Frac, kv=0.01khSingle Layer Evaluation of Water Frac Productivity
With Kv > 0 Limited Reserves Lost But Economics Impacted! Limited Proppant Coverage Results In Reduced IP And Shallower Decline!
Vertical Reservoir Permeability, And Incomplete Proppant Coverage Of The Fracture!
INLET Crack SEM EXIT FILTER FLUID COLLECTION Sand Core in Core Holder at Pressure
Sleeved Core Holder
Core Cracked with Masonry Splitter
2000 4000 6000 0.1 1 10 100 1,000
Effective Proppant Stress (psi)
Unpropped KfW Non-Aligned Cracks
Asperity Height Max Avg 0.26" 0.09" 0.19" 0.06"
A Residual kfw Of 1 mdft In The Un-Propped Fracture Is Likely In ETCV, However, It Depends:
What Is The Effect Of Poor Proppant Coverage!
Multiple Layer Evaluation of Water Frac Productivity 60% of Zone Stimulated kv/kh Ratio Varied
Assumes Un-Propped kfw!
20 % 100 % 80 % 60 % 40 % 20 % 100 % 80 % 60 % 40 %
Time, Years Cumulative Gas, MMCF
Full Vertical Frac 80% Vert Frac + 1 mdft 60% Vert Frac + 1 mdft 40% Vert Frac + 1 mdft 20% Vert Frac + 1 mdftWith Residual kfw In The Un-Propped Fracture No Reserves Are Lost!
Lower IP Shallower Decline!
Fw
KfW = ??
For “Downward” Flow
FCD-Vert > 2.0
Unpropped F Unpropped f Vert CD
− −
Equivalent FCD
Fw
10 20 50 100 200 500 1000 2000 5000 0.2 0.3 0.5 1 2 3 5
Time (days) Rate (MCFD)
Cases with H-Prop = 20 to 100 ft All F = 3
Hf = 100' All = 5 k = 0.01 md Xf = 750' 80 Acres
CD
F
CD - Vert
As Long As FCD-Vert > 2 The Propped Fracture Height Doesn’t Matter! For (kfw)Un-propped = 1 mdft HF-Un-propped < 50 feet
Unpropped F Unpropped f Vert CD
− −
fw
0.01 0.02 0.05 0.1 0.2 0.5 1 20 40 60 80
k (md) Max Unpropped H (ft)
KfW (UnPropped) 5 md-ft 1 md-ft 0.1 md-ft
Application: Low k, and Limited h!
History of Water Fracs Fracs
Water as a Fracturing Fluid
Clean vs vs Dirty Dirty
Residual Fracture Width
Development of Water Frac Guidelines
Reservoir Quality Considerations
Geomechanical Considerations
Fracture Design Considerations
Water Frac Application Review
v/k
h > 0.0.
1 10 100 1000 10000 100000 0.001 0.01 0.1 1 10 100
Perm eability, m d Fracture Conductivity, mdft F CD =10 F CD = 2
Upper Bound on W ater Frac k fw Low er Bound on W ater Frac k fw
History of Water Fracs Fracs
Water as a Fracturing Fluid
Clean vs vs Dirty Dirty
Residual Fracture Width
Development of Water Frac Guidelines
Reservoir Quality Considerations
Geomechanical Considerations
Fracture Design Considerations
Water Frac Application Review
1/2
MUST MUST Have Height Confinement & Zonal Coverage?
Have Height Confinement & Zonal Coverage?
Proppant Settling Below Pay! Proppant Settling Poor Perforation Coverage!
Fw
KfW = ??
For “Downward” Flow
FCD-Vert > 2.0
Unpropped F Unpropped f Vert CD
− −
Equivalent FCD
0.01 0.03 0.1 0.3 1 3 0.002 0.003 0.005 0.01 0.02 0.03 0.05 0.07 0.09
k (md) 'C' (ft/√min)
Calculated Fluid Loss Coef.
k-rel = 0.5 , φ = 0.105 Ct = 200e-6 1/psi μ-gas = 0.02 cp
μ = 0.5 cp Δp = 3,000 psi No Filter Cake
filtrate
"Expected" Range
25 50 75 100 125 150 175 500 1,000 1,500 2,000 2,500 3,000
Volume (M-Gal) XF (ft)
30 bpm "Reasonable" H Confinement C = 0.001 C = 0.002 C = 0.005 0.01
Low Permeability! Reservoir Controlled Leak-Off Gel Leak-Off = Water Leak-Off !
History of Water Fracs Fracs
Water as a Fracturing Fluid
Clean vs vs Dirty Dirty
Residual Fracture Width
Development of Water Frac Guidelines
Reservoir Quality Considerations
Geomechanical Considerations
Fracture Design Considerations
Water Frac Application Review
Un-
propped (hydraulically created) fracture conductivity must be greater than 0.1 mdft ( conductivity must be greater than 0.1 mdft (F
FCD
CD-
Vert > 2
> 2),
),
Pump Rate required to provide fracture width three times the proppant diameter without violating fracture times the proppant diameter without violating fracture containment, containment,
Stimulation design should achieve at least 1,200 gallons and 660 pounds per foot of gross pay stimulated (50% and 660 pounds per foot of gross pay stimulated (50% Fill Fill-
Up).
2000 4000 6000 0.1 1 10 100 1,000
Effective Proppant Stress (psi)
Unpropped KfW Non-Aligned Cracks
Asperity Height Max Avg 0.26" 0.09" 0.19" 0.06"
A Residual kfw Of 1 mdft In The Un-Propped Fracture Is Likely In ETCV, However, It Depends:
y = 187.39x
R
2 = 0.9886y = 238.54x
R
2 = 0.9769y = 230.31x
R
2 = 0.95760.0 20.0 40.0 60.0 80.0 100.0 120.0 20 40 60 80 100 120
Pump Rate, BPM Propped Height, % Fill Up
10' >50' 20'
Width limit << BPM <<Height growth<< % Fill Up
20 40 60 80 100 120 20 40 60 80 100 120
Pump Rate, BPM Propped Height, % Fill Up
400 gals/ft 800 gals/ft 1,200 gals/ft 1,600 gals/ft 2,000 gals/ft
Water Frac Design: % ppg 50.0 0.0 15.0 0.5 15.0 1.0 15.0 1.5 5.0 2.0 Per Foot of Pay: Fluid Prop (gals) (lbs) 400 220 800 440 1,200 660 1,600 880 2,000 1,100
Fluid Volume>1,200 gals/ft and Prop Volume >660 lbs/ft
Water Can Be An Excellent Inexpensive Fracturing Fluid Provided: Fracturing Fluid Provided:
1. 1.
Used in Low Permeability Applications, Used in Low Permeability Applications,
K h
h < 0.1 md and
< 0.1 md and K K v
v > 0.0 md
> 0.0 md
2. 2.
Some Fracture Containment Achieved, Some Fracture Containment Achieved,
σ >>> 0.0 psi
>>> 0.0 psi
3. 3.
Unpropped Unpropped k kf
fw
w > 0.1 mdft, and F > 0.1 mdft, and FCD
CD-
Vert > 2
> 2
4. 4.
Up Achieved,
1200 gals/ft of gross pay
660 lbs/ft of gross pay
Introduction
History of Water Fracs Fracs
Water as a Fracturing Fluid
Clean vs vs Dirty Dirty
Residual Fracture Width
Development of Water Frac Guidelines
Reservoir Quality Considerations
Geomechanical Considerations
Fracture Design Considerations
Water Frac Application Review
6000 7000 8000 8,550 8,600 8,650 8,700 8,750 8,800 8,850 8,900 8,950 9,000 9,050 9,100 9,150 9,200 9,250 9,300 9,350 9,400 9,450 9,500 9,550 9,600 9,650
P-Closure Gamma Ray
50 100
Corrected Log Using Veatch Corr.
C-Lime Stress Test Bossier Shale Stress Test Taylor Stress Test Taylor Sand
Log Data
Well Defined Geomechanical Profile!
22-9 Pcl Bossier Sh (0.83 psi/ft) WHD(psi) 3000 3500 4000 4500 5000 5500 6000 6500 sqrt(dt) 1 2 3 4 5 6 dP/d[sqrt(dt)] Isip Pext Blessed Pc 3799.855 Tc 3.227 EFFc 0.510124 Isip 6461.539 dPs 2661.6842 4 6 8 10 2 4 6 8 10
Dynamic Modulus (MM psi)
Drained Tests for Dynamic E
E = 0.924 X E - 1.09
Static Dynamic
Static Modulus (MM psi)
2 4 6 8 10 2 4 6 8 10
Dynamic Modulus (MM psi)
Drained Tests for Dynamic E
E = 0.924 X E - 1.09
Static Dynamic
Static Modulus (MM psi)
60 120 180 240 300 360 500 1,000 1,500 2,000 2,500 3,000 3,500 10 20 30 40 50 60 70
TIME (min) Pressure (psi)
Micro-Seismic Events
Dead String Pressure
Rate (bpm) / PPG
Rate PPG Slick Water Mini-Frac X-Link Gel Frac Step Rate Test
1 2 5 10 20 50 100 50 100 200 500 1,000
Pump Time (min) Net Pressure (psi)
Taylor Zone Mini-Frac - Nolte-Smith Plot
Data Simulation 1 2 5 10 20 50 100 50 100 200 500 1,000 2,000
Pump Time (min) Net Pressure (psi)
Taylor Zone Frac - Nolte-Smith Plot
Slick Water Data Simulation
500 1000 1500 9,550 9,600 9,650 9,700 9,750 9,800
Xf (ft)
Simulation
21-10 Taylor Propped Frac
Seismic Events w/Error Depth Bars
Mini-Frac Net Pressure Match Frac Net Pressure Match w/ Micro-Seismic
Fracture Penetration (ft) 1000 2000 3000 4000 5000 74.29 min 9580 ft TVD 9610 9640 9670 Stress (psi) 6450 7550 Shale Silty 0.000 0.086 0.172 0.258 0.344 0.430 0.515 0.601 0.687 0.773 0.859 PSF psf
Vol., m ga ls Conc., p p g Ra te (BPM) Fluid Typ e Prop Type 40.0 0.0 30 TW
0.5 30 TW 20/40 Ottawa 12.0 1.0 30 TW 20/40 Ottawa 12.0 1.5 30 TW 20/40 Ottawa 4.0 2.0 30 TW 20/40 Ottawa
Hydraulic Height Proppant Coverage Perforation Coverage!
Typical Water Frac Design
Modified Water Frac Design
Vol., m ga ls Conc., p p g Ra te (BPM) Fluid Typ e Prop Typ e 85.0 0.0 30 TW
0.5 30 TW 20/40 Ottawa 15.0 1.0 30 TW 20/40 Ottawa 15.0 1.5 30 TW 20/40 Ottawa 15.0 2.0 30 TW 20/40 Ottawa 15.0 3.0 30 TW 20/40 Ottawa 10.0 4.0 30 TW 20/40 Ottawa
Fracture Penetration (ft) 2000 4000 6000 8000 152.61 min 9580 ft TVD 9610 9640 9670 Stress (psi) 6450 7550 Shale Silty 0.000 0.086 0.172 0.258 0.344 0.430 0.515 0.601 0.687 0.773 0.859 PSF psf
Hydraulic Height Proppant Coverage Perforation Coverage!
Why Not TW & Linear Gel?
Fracture Penetration (ft) 500 1000 1500 2000 2500 105.01 min 9575 ft TVD 9600 9625 9650 9675 Stress (psi) 6450 7550 Shale Silty 0.000 0.086 0.172 0.258 0.344 0.430 0.515 0.601 0.687 0.773 0.859 PSF psf
Vol., m ga ls Conc., p p g Ra te (BPM) Fluid Typ e Prop Typ e 25.0 0.0 30 TW
0.5 30 TW 20/40 Ottawa 10.0 1.0 30 TW 20/40 Ottawa 10.0 1.5 30 TW 20/40 Ottawa 10.0 2.0 30 TW 20/40 Ottawa 10.0 3.0 30 LG 20/40 Ottawa 10.0 4.0 30 LG 20/40 Ottawa 5.0 5.0 30 LG 20/40 Ottawa
Hydraulic Height Proppant Coverage Perforation Coverage!
Hybrid Water Frac Design
Summary: Summary:
Long History Of Application
Works Well In East Texas Cotton Valley
Guidelines Can Be Used For Other Applications
Hybrid TW Design Mitigates TW Frac Risks
Hybrid TW Fracs Fracs Have Broad Application! Have Broad Application!
Spacers Can Aid Proppant Proppant Placement Placement
Smaller Proppant Proppant Transports Further Transports Further
Fw
100 200 300 400 500 600 700 1 2 3 4
Time (days) Rate (MCFD)
Hf = 100' All = 5 k = 0.01 md Xf = 750' 80 Acres
CD
F Fully Propped Frac 20% Propped, F = 1.0
CD - Vert
10 20 50 100 200 500 1000 2000 5000 0.2 0.3 0.5 1 2 3 5
Time (days) Rate (MCFD)
Hf = 100' All = 5 k = 0.01 md Xf = 750' 80 Acres
CD
F Fully Propped Frac 20% Propped, F = 2.5
CD - Vert
20% Propped, F = 1.0
CD - Vert
Unpropped F Unpropped f Vert CD
− −