FRAC FLUIDS AND WATER USAGE Evaluating The Commercial

FRAC FLUIDS AND WATER USAGE
Evaluating The Commercial Viability and Success
In Using Water-Free Fracs
Overview of Presentation
 
BlackBrush Oil & Gas
 
Natural Gas Liquids (NGLs) as frac fluid.
 
Advantages and limitations of using NGLs as frac fluid
 
Well flowback design & operations
 
Case Study of wells stimulated with NGLs vs Water fracs
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BlackBrush Oil & Gas
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BlackBrush is privately held and was formed in 2004.
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BlackBrush is located in San Antonio, Texas
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BlackBrush operations are primarily in South Texas
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Over 130,000 net acres
Operates over 200 wells
Current operated production of 10,000 BPDe
Very active drilling and completion program
200 plus employees including affiliates
BlackBrush Oil & Gas
BlackBrush development plans utilizes horizontal, multi-stage
completions. All are oil plays.
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Pearsall Shale
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Buda
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Eagleford
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Austin Chalk
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San Miguel
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Olmos
GasFrac Technology
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NGLs - propane, butane, and pentanes gelled using a
patented system allowing the fluid to carry proppant.
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Fluids are handled in pressurized vessels.
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Proppant blender is pressurized.
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Safety systems, including LEL, thermal cameras, and
Nitrogen system utilized to ensure safe operations
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Safety
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Closed, pressurized system
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Extensive monitoring equipment
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LEL sensors (lower explosive limit)
Cameras (visible spectrum and thermal)
Pressure transducers
Hazop reviews (Hazard and Operability)
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Nitrogen used to maintain pressure throughout operations
No exposure to atmosphere
Extensive hazop reviews have been performed internally and with expert
third-party consultants
Hot zone
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No people are in the “hot zone” during pumping operations
Advantages of NGL frac
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Provide energy to help lift frac fluid and reservoir fluids. It does this while
also remaining in liquid phase while treating the well.
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Does not cause clay swelling.
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Maintains higher relative perm for oil but not “water wetting formation”
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Low surface tension helps during flow-back
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NGL viscosity is .08 cps versus .66 cps for water
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Larger effective frac length vs water
Require less pressure drive to move fluid. 2000 psi to move water vs 200 psi for
NGL for a formation with a perm of .005md
Eliminates cost of obtaining, treating and disposing of water.
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Limitations of Gas Frac vs
Conventional Water Frac
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Job size – proppant and fluid volumes
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Pump rate
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Wellbore configuration – open-hole packers vs. plug and perf
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Logistics of NGL delivery
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Frac fluid availability
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Less forgiving system
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Propane Flowback
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Line heaters added to keep propane in the gas phase and
out of the oil tank.
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Options for handling propane
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Deliver directly to pipeline – high pressure lines take special
considerations
Use of JT or refrigeration gas plant to remove propane
Use of blending in natural gas to reduce percent of propane in
gas stream.
Must be able to recover propane as it is cost prohibitive
to flare propane during flow-back.
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NGL Phase Diagram
Pressure (PSIA)
650
600
550
500
450
400
350
300
250
200
150
100
50
0
NGL Liquid Phase
NGL Gas
Phase
-50
0
50
100
150
200
250
300
Temperature (oF)
NGL Mixture
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Propane
50% i-C4/50% n-C4
350
400
Modified Flowback For C4+ Fluid
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Goal is to keep recovered fluid in the liquid phase
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Blend with lease oil into pressurized frac tanks to keep stable
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Blended product is transported and sold as oil
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Residual or flash gas from separator is sent to sales
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Virtually 100% recovery
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Minimizes flowback equipment and reduces flowback time/cost.
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Compressing into a high pressure sales lines is no longer an issue
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Case Study Formation
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Depth 3,750 ft
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Bottom-hole pressure of 1650 psig (.44 psi/ft)
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Bottom-hole temperature 140 degree F
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Tight oil sand gross pay of 90 ft, high porosity pay section of 27 ft.
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Perm of .05 - .10 md
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Water saturation of 45%
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Oil gravity 45 degree API,
Gas is over 8 gpm
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Field has over 200 vertical wells. Average IP of 15 bpd and EUR of 15 Mbbl.
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Comparison of Water & NGL Fracs
Water
NGL
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4,797 bbls per stage
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85,569 lbs. per stage
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66,454 lbs. per stage
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Frac gradient .94 psi/ft
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Frac gradient .96 psi/ft
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Treating Rate 42 BPM
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Cost per stage of $165M
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Expected Future Cost per stage $87M
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9.5 stages per well
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Treating Rate 66 BPM
Cost per stage of $115M
9 stages per well
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1,233 bbls per stage
Average IP Rate
700
604
600
500
400
375
300
200
100
0
Avg. IP watr frac BPDe
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Avg. IP NGL frac BPDe
Average IP per stage
70
64
60
50
41
40
30
20
10
0
Avg. IP per stage water frac BPDe
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Avg IP per staqge NGL frac BPDe
Cumulative BOE vs Time
40000
35000
30000
25000
20000
15000
10000
5000
0
0
5
10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 90
Avg. Cum. BOE Water frac
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Avg. Cum BOE NGL frac
Cumulative BOE vs Time
14000
12000
10000
8000
6000
4000
2000
0
0
5
Avg. Cum. BOE Water frac
22
10
15
Avg. Cum BOE NGL frac
20
25
30
35
Avg. Cum BOE Butane Pentane frac
Rate vs Time
700
600
500
400
300
200
100
0
1
31
61
91
121
151
Avg. Rate water frac BPDe
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181
211
241
271
Avg. Rate NGL frac BPDe
301
331
Flowing Tubing Pressure
800
750
700
650
600
550
500
450
400
350
300
250
200
150
100
50
0
On gas lift
1
24
31
61
91
121
151
Avg. FTP Water frac psig
181
211
241
271
Avg. FTP NGL frac psig
301
331
Pump and fluid costs vs. 90 day cum
BOE
80
70
$/90 day Cum BOE
60
57
50
45
40
30
24
20
10
0
Water Cost
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NGL Cost
Future NGL Cost
Buda formation well
Rate vs Time BPDe
700
650
6 stage gas frac
600
550
Open-hole completion
500
450
400
350
300
250
200
150
100
50
0
1
6
11
16
21
26
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BPDe
26
36
41
46
51
56
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Buda formation well
Flowing tubing pressure
1600
1500
1400
6 stage gas frac
1300
1200
1100
1000
Open-hole completion
900
800
700
600
500
400
300
200
100
0
1
6
11
16
21
26
31
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Tubing Pressure
27
41
46
51
56
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Conclusion
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Use of NGL fracs has greatly increased reserve recovery for oil
formations.
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Future use of Butanes and Pentanes mix will greatly reduce the net
cost of NGL fracs.
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Continued added infrastructure will reduce costs of NGL fracs.
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NGL fracs should make many of the normal pressure oil windows in
shale plays viable.
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NGL fracs eliminate the problems associated with water fracs.
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BlackBrush plans to continue to utilize GasFrac in current areas and
expand the technology in other formations
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