Unconventional Reservoirs Require Unconventional Analysis ...
Primary funding is provided by
The SPE Foundation through member donations and a contribution from Offshore Europe The Society is grateful to those companies that allow their professionals to serve as lecturers Additional support provided by AIME
Society of Petroleum Engineers Distinguished Lecturer Program www.spe.org/dl
1
Unconventional Reservoirs Require Unconventional Analysis Techniques David Anderson
Society of Petroleum Engineers Distinguished Lecturer Program www.spe.org/dl
2
This Presentation… Introduction to rate transient analysis (RTA) The challenge of analyzing unconventionals
Current methodologies – how has the technology evolved? The future of production analysis and modeling Probabilistic approach Field examples 3
Rate Transient Analysis (RTA) is the science (and art) of extracting useful information about the reservoir, completion and/or surface operations based on the interpretation, analysis and modeling of continuous measurements of production volumes and flowing pressures from a single well.
4
Concept of Rate Transient Analysis Company: On Stream: 03/28/2013 Field: Current Status: Flowing
Gp: 1775 MMscf Np: 0.000 Mstb Wp: 0.000 Mstb Qcond: 0.000 Mstb
W ell 01
3600
5200
- Production occurs under changing constraints - Reservoir “signal” may be in rates or pressures (or both)
3200
2800
2400
4000
3600
3200 1600
2800 1200
2400 800
2000 400 1600 0 1200
-400
800
-800
400
-1200
0 0
2
4
6
8
10
12
14
16
18
20
22
24
26
28
Time (days) Normalized Time (month)
30
32
34
36
38
40
42
44
46
48
5
Run Depth Pressure (psi(a))
Op Gas Rate (Mscfd)
4400
pwf (psia)
q (Mscfd)
2000
4800
Concept of Rate Transient Analysis Comparison View 9 . 10-3
Legend
6
Normalized Gas Rate vs. Normalized Time Normalized Gas Rate vs. MBT (2)
4 3
Normalized Gas Rate (MMscfd/psi)
q/Dp (Mscfd/psi)
2
10-3
Instantaneous normalization Superposition (Material Balance Time)
6 4 3 2
10-4
6 4 3 2
10-5 0
10
20
30
40
50
60
70
80
90
100
110
120
130
140
150
160
130
140
150
160
Normalized Time (month)
0
10
20
30
Time, Material Balance Time (months) 40
50
60
70
80
90
100
110
120
MBT
6
Type Curve Analysis – Characterize Reservoir Comparison View 4 . 100
Legend q/D - TC Normalized Gas Rate vs. MBT
2
Log-Log Plot - Identify flow regimes Boundary Dominated Flow (connected HCPV)
1.0
4
10-1
4 2 10-2
4
Transient Flow (permeability, skin)
D
q/Dp (Mscfd/psi)
2
2 10-3
4 2 10-4
Adapted from Palacio and Blasingame: “Decline-Curve Analysis Using Type Curves” (SPE 25909) 1993
5 3 2 . 10-5 10-2
2
3 4 5 6 7 10-1
2
3 456
1.0
2
3 4 56
101
2
3 4 56
102
2
3 4 56
103
2
3 4 5 6 7 104
Material Balance Time (days)
2
3 456
105
2
3 4
7
8 . 105
Flowing Material Balance – Estimate HCPV Company: On Stream: 10/01/2002 Field: Apollo Current Status: Unknown
7000
30
6500
28
Legend Gas Rate Flowing Pressure
26
6000
24
Production Rate (Mscfd)
5500
Gp: 3409 MMscf Np: 224.268 Mstb Wp: 16.566 Mstb Qcond: 0.000 Mstb
Example 1
22
5000
Pressure (psi(a))
pwf (psia)
4000
3500
3000
2500
Operated Gas Rate (MMscfd)
20
4500
18
Measured flowing pressure
16
14
12
10
2000
8 1500
1000
4
500
2
0
Measured rate
6
0 0.00
0.50
1.00
1.50
2.00
2.50
3.00
3.50
4.00
4.50
5.00
5.50
6.00
6.50
7.00
7.50
Cumulative Production (bcf) Cumulative Gas Production (Bscf)
8.00
8.50
9.00
9.50
10.00
8
10.50
Flowing Material Balance – Estimate HCPV Company: On Stream: 10/01/2002 Field: Apollo Current Status: Unknown
7000
30
6500
28
Example 1
Legend Flowing p/Z** Gas Rate Flowing Pressure
26
6000
Calculated p/z
24
Production Rate (Mscfd)
5500
Gp: 3409 MMscf Np: 224.268 Mstb Wp: 16.566 Mstb Qcond: 0.000 Mstb
22
Pressure, p/Z** (psi(a))
4500
4000
3500
3000
2500
2000
p p qbpss z z wf
20
Operated Gas Rate (MMscfd)
pwf and p/z (psia)
5000
18
16
14
12
10
8 1500
6
1000
4
500
2
0
0 0.00
- Mattar L., Anderson, D., Dynamic Material Balance – Oil or Gas
Original Gas-In-Place
In Place Without Shut-ins - 2, CIPC 2005-113 0.50
1.00
1.50
2.00
2.50
3.00
3.50
4.00
4.50
5.00
5.50
6.00
6.50
7.00
7.50
Cumulative Production (bcf) Cumulative Gas Production (Bscf)
8.00
8.50
9.00
9.50
10.00
9
10.50
Modeling – Validate and Forecast Results 11500
9.00
11000
10000
10500
9500
8.50 8.00
10000
7.50
9500
9000
Production Forecast
8500
9000
7.00
8000
8500 7500
6.50
7000
7500
5.50
7000
6500
6500
6000
6000
5500
5500
5000
5.00 4.50 4.00 3.50
Gas Cum (MMscf)
6.00
5000
4500
4500
4000
4000 3.00
3500 3500
2.50
Pressure match
3000
3000 2500
2.00
2500
1.50
2000
2000
1500
1500
1000
1000
500
500
1.00 0.50 0.00
0 2002
2003
2004
2005
2006
Pressure (psi(a))
Cal Gas Rate (MMscfd)
8000
Benefits of RTA Evaluation of reserves Reliable early evaluation- choked wells Scientific support for reserves auditors Dynamic reservoir characterization Estimate permeability and in-place hydrocarbons Estimate completion effectiveness Calibrate reservoir simulation models Reservoir surveillance Distinguish productivity fall-off from depletion Identify optimization candidates
The Challenge of Analyzing Unconventionals… Unconventional reservoirs are more complex Complex, non-uniform fracture networks Reservoir properties are significantly altered by completion Low permeability – long term transient flow Drainage area continually expands Difficult to distinguish clear drainage boundaries
Flow Characterization – Conventional vs. Unconventional Radial Flow - Conventional
Linear Flow - Unconventional
Fluid flows to the sandface Pressure drawdown localized at sandface
Fluid flows to the fracture(s) Pressure drawdown throughout fracture(s)
High Permeability Low Contact Area
Low Permeability High Contact Area
Unconventional Analysis Methods… Square Root Time Plot- Linear Flow Simple A = 4 nf xf h h 2 xf
A k Complex A
Dp q Skin
Dp m t b q t
A
f
Boundaries and Drainage – Conventional vs. Unconventional a) Conventional Reservoir
b) Unconventional Reservoir Horizontal Wells
Vertical Wells
Parallel Fractures
Fracture interference Stimulated Reservoir Volume (SRV)
Geological features
Parallel and Orthogonal Fractures
Well interference 15
Unconventional Analysis Methods… Flowing Material Balance Stimulated Reservoir Volume
h
2 xf Le
p wf z In-place hydrocarbons (SRV) Cumulative Productioni
Unconventional Analysis Methods… Simplified Approachtetf = SRV
A√k
Anderson et al 2010, Analysis of Production Data from Fractured Shale Gas Wells – SPE 131787
skin
SRV
Assume – uniform fractures Calculated- xf, k, skin, SRV
Illustrating the Challenge of Analyzing Unconventionals Simulation of flow into a complex fracture network in a gas shale Company: On Stream: 25/06/2013 Field: Current Status: Flowing
Gp: 705 MMscf Np: 0.000 Mstb Wp: 0.000 Mstb Qcond: 0.000 Mstb
W ell 02
3 . 104
540 520 500 480
2
460 440 420
360
9
340 8
320 7
300 6
280 260
5
240 4
220 200 180
3
2
103
Non-uniform frac length, spacing and conductivity Ultra low matrix permeability Six months production, constant pwf
160 140 120 100 80 60 40 20 0
June
July
August
September
October 2013
November
December
Run Depth Pressure (psi(a))
Op Gas Rate (Mscfd)
380 104
pwf (psia)
q (MMscfd)
400
tetf = SRV
A√k skin
Contacted HCPV
q/Dp (MMscfd/psi)
Dp/q (psi/MMscfd)
Simplified Approach – Bulk Reservoir Properties
Gpa/ceDp (bcf)
Square Root Time
q/Dp (MMscfd/psi)
SRV = 0.75 bcf
Time (d)
Contacted HCPV = 1.1 bcf
Simplified Approach – Comparison of Analyzed Reservoir Properties with Actual
As Analyzed Stimulated reservoir width = 120 ft k (stimulated zone) = 0.011 md k (matrix) = 0.0005 md Contacted OGIP = 2 bcf
Actual
Hz fractures – 250 ft, FCD=50 Vert fractures – 500 ft, FCD = 100 k (matrix) = 0.0001 md OGIP = 46 bcf (1 section)
Simplified Approach – Comparison of Analyzed SRV with Actual
As Analyzed
Actual
SRV = 0.75 bcf
SRV ~ 0.75 bcf
Simplified Approach – Comparison of 5 year Production Forecasts Comparison View
2 . 101
Gp = 1.8 bcf
101
Gp = 1.9 bcf
8 6
q (MMscfd)
Cal Gas Rate (MMscfd) / Rate Forecast 1 (MMscfd)
5 4 3
2
1.0 8 6 5 4 3
2
10-1 2013
2014
2015
2016
Time (years)
2017
2018
2019
Field Example - Bakken Oil Company: On Stream: 06/05/2008 Field: Undefined Field Current Status: Flowing
2 . 103
Gp: 72 MMscf Np: 98.451 Mstb Wp: 19.879 Mstb Qcond: 0.000 Mstb
Bakken Oil Bakken
103
5200 5000
7
4800
103
5 4600 4
7
4400 3
5
4200
4 2
4000
3 3800 2
3600 102 3400
3
Op Gas Rate (Mscfd)
Op Water Rate (stb/d)
Op Oil Rate (stb/d)
4
5
3000
4
2800
3
2600 2400
2 2200
2 2000 1800
101 101
1600 7 1400
7 5 5
1200
4
4
1000 3
3 2
800 600
2
400 200 1.0
1.0 0 04
05
06
07
08 2008
09
10
11
12
01
02
03
04
05
06
07 2009
08
09
10
11
12
01
02
03
04
05
06
07
08
09
10
2010
23
Casing Pressure (psi(a))
5
3200
Calculated Sandface Pressure (psi(a)) Run Depth Pressure (psi(a))
7
7
Tubing Pressure (psi(a))
102
Dp/q (psi/stb/d)
tetf = SRV
A√k FCD’
Contacted HCPV = 2,800 Mstb
SRV = 850 Mstb
Np/ceDp (Mstb)
q/Dp (stb/d/psi)
Square Root Time
q/Dp (stb/d/psi)
Field Example – RTA – Simplified
Time (d)
24
Field Example – RTA - Modeling High efficiency “short” fracs
Ozkan et al. 2009, “Tri-Linear Flow”
Low efficiency “long” fracs
Stalgorova et al, 2013, “Five Region Model”
Summary of Current Unconventional RTA Technology Provides a “bulk” reservoir interpretation Reliable estimation of stimulated and total connected HCPV Identification of effective system permeability and apparent skin damage No unique interpretation of fracture properties (orientation, distribution, density, length and conductivity) No unique interpretation of matrix permeability Analytical models with different geometries are available
The Future of Unconventional RTA – Probabilistic Approach Rate Transient Analysis: Deterministic
Data q, pwf
Modeling – Realizations of RTA results: Probabilistic 27
Probabilistic Well Performance Analysis Define ranges or distributions of input parameters Completion properties Reservoir properties
Run the reservoir model probabilistically using Monte Carlo simulation Keep only history matches that meet a minimum goodness of fit criteria Report reservoir characteristics and production forecasts as distributions, not single values
28
Probabilistic Well Performance Analysis – Forecasts Rate vs Time
Expected Ultimate Recovery
Rate vs Cumulative
Original Gas in Place
29
Conclusions RTA provides “bulk” reservoir interpretation Ideal for establishing connected HCPV Assists in understanding recovery mechanism Yields reliable production forecasts
Analyzing unconventional well production presents significant challenges Analysis and modeling technology has evolved Unconventional plays are statistical in nature – many wells must be analyzed to understand behavior A probabilistic approach will help to manage and communicate uncertainty 30
Thank-you… Questions?
31
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32
The SPE Foundation through member donations and a contribution from Offshore Europe The Society is grateful to those companies that allow their professionals to serve as lecturers Additional support provided by AIME
Society of Petroleum Engineers Distinguished Lecturer Program www.spe.org/dl
1
Unconventional Reservoirs Require Unconventional Analysis Techniques David Anderson
Society of Petroleum Engineers Distinguished Lecturer Program www.spe.org/dl
2
This Presentation… Introduction to rate transient analysis (RTA) The challenge of analyzing unconventionals
Current methodologies – how has the technology evolved? The future of production analysis and modeling Probabilistic approach Field examples 3
Rate Transient Analysis (RTA) is the science (and art) of extracting useful information about the reservoir, completion and/or surface operations based on the interpretation, analysis and modeling of continuous measurements of production volumes and flowing pressures from a single well.
4
Concept of Rate Transient Analysis Company: On Stream: 03/28/2013 Field: Current Status: Flowing
Gp: 1775 MMscf Np: 0.000 Mstb Wp: 0.000 Mstb Qcond: 0.000 Mstb
W ell 01
3600
5200
- Production occurs under changing constraints - Reservoir “signal” may be in rates or pressures (or both)
3200
2800
2400
4000
3600
3200 1600
2800 1200
2400 800
2000 400 1600 0 1200
-400
800
-800
400
-1200
0 0
2
4
6
8
10
12
14
16
18
20
22
24
26
28
Time (days) Normalized Time (month)
30
32
34
36
38
40
42
44
46
48
5
Run Depth Pressure (psi(a))
Op Gas Rate (Mscfd)
4400
pwf (psia)
q (Mscfd)
2000
4800
Concept of Rate Transient Analysis Comparison View 9 . 10-3
Legend
6
Normalized Gas Rate vs. Normalized Time Normalized Gas Rate vs. MBT (2)
4 3
Normalized Gas Rate (MMscfd/psi)
q/Dp (Mscfd/psi)
2
10-3
Instantaneous normalization Superposition (Material Balance Time)
6 4 3 2
10-4
6 4 3 2
10-5 0
10
20
30
40
50
60
70
80
90
100
110
120
130
140
150
160
130
140
150
160
Normalized Time (month)
0
10
20
30
Time, Material Balance Time (months) 40
50
60
70
80
90
100
110
120
MBT
6
Type Curve Analysis – Characterize Reservoir Comparison View 4 . 100
Legend q/D - TC Normalized Gas Rate vs. MBT
2
Log-Log Plot - Identify flow regimes Boundary Dominated Flow (connected HCPV)
1.0
4
10-1
4 2 10-2
4
Transient Flow (permeability, skin)
D
q/Dp (Mscfd/psi)
2
2 10-3
4 2 10-4
Adapted from Palacio and Blasingame: “Decline-Curve Analysis Using Type Curves” (SPE 25909) 1993
5 3 2 . 10-5 10-2
2
3 4 5 6 7 10-1
2
3 456
1.0
2
3 4 56
101
2
3 4 56
102
2
3 4 56
103
2
3 4 5 6 7 104
Material Balance Time (days)
2
3 456
105
2
3 4
7
8 . 105
Flowing Material Balance – Estimate HCPV Company: On Stream: 10/01/2002 Field: Apollo Current Status: Unknown
7000
30
6500
28
Legend Gas Rate Flowing Pressure
26
6000
24
Production Rate (Mscfd)
5500
Gp: 3409 MMscf Np: 224.268 Mstb Wp: 16.566 Mstb Qcond: 0.000 Mstb
Example 1
22
5000
Pressure (psi(a))
pwf (psia)
4000
3500
3000
2500
Operated Gas Rate (MMscfd)
20
4500
18
Measured flowing pressure
16
14
12
10
2000
8 1500
1000
4
500
2
0
Measured rate
6
0 0.00
0.50
1.00
1.50
2.00
2.50
3.00
3.50
4.00
4.50
5.00
5.50
6.00
6.50
7.00
7.50
Cumulative Production (bcf) Cumulative Gas Production (Bscf)
8.00
8.50
9.00
9.50
10.00
8
10.50
Flowing Material Balance – Estimate HCPV Company: On Stream: 10/01/2002 Field: Apollo Current Status: Unknown
7000
30
6500
28
Example 1
Legend Flowing p/Z** Gas Rate Flowing Pressure
26
6000
Calculated p/z
24
Production Rate (Mscfd)
5500
Gp: 3409 MMscf Np: 224.268 Mstb Wp: 16.566 Mstb Qcond: 0.000 Mstb
22
Pressure, p/Z** (psi(a))
4500
4000
3500
3000
2500
2000
p p qbpss z z wf
20
Operated Gas Rate (MMscfd)
pwf and p/z (psia)
5000
18
16
14
12
10
8 1500
6
1000
4
500
2
0
0 0.00
- Mattar L., Anderson, D., Dynamic Material Balance – Oil or Gas
Original Gas-In-Place
In Place Without Shut-ins - 2, CIPC 2005-113 0.50
1.00
1.50
2.00
2.50
3.00
3.50
4.00
4.50
5.00
5.50
6.00
6.50
7.00
7.50
Cumulative Production (bcf) Cumulative Gas Production (Bscf)
8.00
8.50
9.00
9.50
10.00
9
10.50
Modeling – Validate and Forecast Results 11500
9.00
11000
10000
10500
9500
8.50 8.00
10000
7.50
9500
9000
Production Forecast
8500
9000
7.00
8000
8500 7500
6.50
7000
7500
5.50
7000
6500
6500
6000
6000
5500
5500
5000
5.00 4.50 4.00 3.50
Gas Cum (MMscf)
6.00
5000
4500
4500
4000
4000 3.00
3500 3500
2.50
Pressure match
3000
3000 2500
2.00
2500
1.50
2000
2000
1500
1500
1000
1000
500
500
1.00 0.50 0.00
0 2002
2003
2004
2005
2006
Pressure (psi(a))
Cal Gas Rate (MMscfd)
8000
Benefits of RTA Evaluation of reserves Reliable early evaluation- choked wells Scientific support for reserves auditors Dynamic reservoir characterization Estimate permeability and in-place hydrocarbons Estimate completion effectiveness Calibrate reservoir simulation models Reservoir surveillance Distinguish productivity fall-off from depletion Identify optimization candidates
The Challenge of Analyzing Unconventionals… Unconventional reservoirs are more complex Complex, non-uniform fracture networks Reservoir properties are significantly altered by completion Low permeability – long term transient flow Drainage area continually expands Difficult to distinguish clear drainage boundaries
Flow Characterization – Conventional vs. Unconventional Radial Flow - Conventional
Linear Flow - Unconventional
Fluid flows to the sandface Pressure drawdown localized at sandface
Fluid flows to the fracture(s) Pressure drawdown throughout fracture(s)
High Permeability Low Contact Area
Low Permeability High Contact Area
Unconventional Analysis Methods… Square Root Time Plot- Linear Flow Simple A = 4 nf xf h h 2 xf
A k Complex A
Dp q Skin
Dp m t b q t
A
f
Boundaries and Drainage – Conventional vs. Unconventional a) Conventional Reservoir
b) Unconventional Reservoir Horizontal Wells
Vertical Wells
Parallel Fractures
Fracture interference Stimulated Reservoir Volume (SRV)
Geological features
Parallel and Orthogonal Fractures
Well interference 15
Unconventional Analysis Methods… Flowing Material Balance Stimulated Reservoir Volume
h
2 xf Le
p wf z In-place hydrocarbons (SRV) Cumulative Productioni
Unconventional Analysis Methods… Simplified Approachtetf = SRV
A√k
Anderson et al 2010, Analysis of Production Data from Fractured Shale Gas Wells – SPE 131787
skin
SRV
Assume – uniform fractures Calculated- xf, k, skin, SRV
Illustrating the Challenge of Analyzing Unconventionals Simulation of flow into a complex fracture network in a gas shale Company: On Stream: 25/06/2013 Field: Current Status: Flowing
Gp: 705 MMscf Np: 0.000 Mstb Wp: 0.000 Mstb Qcond: 0.000 Mstb
W ell 02
3 . 104
540 520 500 480
2
460 440 420
360
9
340 8
320 7
300 6
280 260
5
240 4
220 200 180
3
2
103
Non-uniform frac length, spacing and conductivity Ultra low matrix permeability Six months production, constant pwf
160 140 120 100 80 60 40 20 0
June
July
August
September
October 2013
November
December
Run Depth Pressure (psi(a))
Op Gas Rate (Mscfd)
380 104
pwf (psia)
q (MMscfd)
400
tetf = SRV
A√k skin
Contacted HCPV
q/Dp (MMscfd/psi)
Dp/q (psi/MMscfd)
Simplified Approach – Bulk Reservoir Properties
Gpa/ceDp (bcf)
Square Root Time
q/Dp (MMscfd/psi)
SRV = 0.75 bcf
Time (d)
Contacted HCPV = 1.1 bcf
Simplified Approach – Comparison of Analyzed Reservoir Properties with Actual
As Analyzed Stimulated reservoir width = 120 ft k (stimulated zone) = 0.011 md k (matrix) = 0.0005 md Contacted OGIP = 2 bcf
Actual
Hz fractures – 250 ft, FCD=50 Vert fractures – 500 ft, FCD = 100 k (matrix) = 0.0001 md OGIP = 46 bcf (1 section)
Simplified Approach – Comparison of Analyzed SRV with Actual
As Analyzed
Actual
SRV = 0.75 bcf
SRV ~ 0.75 bcf
Simplified Approach – Comparison of 5 year Production Forecasts Comparison View
2 . 101
Gp = 1.8 bcf
101
Gp = 1.9 bcf
8 6
q (MMscfd)
Cal Gas Rate (MMscfd) / Rate Forecast 1 (MMscfd)
5 4 3
2
1.0 8 6 5 4 3
2
10-1 2013
2014
2015
2016
Time (years)
2017
2018
2019
Field Example - Bakken Oil Company: On Stream: 06/05/2008 Field: Undefined Field Current Status: Flowing
2 . 103
Gp: 72 MMscf Np: 98.451 Mstb Wp: 19.879 Mstb Qcond: 0.000 Mstb
Bakken Oil Bakken
103
5200 5000
7
4800
103
5 4600 4
7
4400 3
5
4200
4 2
4000
3 3800 2
3600 102 3400
3
Op Gas Rate (Mscfd)
Op Water Rate (stb/d)
Op Oil Rate (stb/d)
4
5
3000
4
2800
3
2600 2400
2 2200
2 2000 1800
101 101
1600 7 1400
7 5 5
1200
4
4
1000 3
3 2
800 600
2
400 200 1.0
1.0 0 04
05
06
07
08 2008
09
10
11
12
01
02
03
04
05
06
07 2009
08
09
10
11
12
01
02
03
04
05
06
07
08
09
10
2010
23
Casing Pressure (psi(a))
5
3200
Calculated Sandface Pressure (psi(a)) Run Depth Pressure (psi(a))
7
7
Tubing Pressure (psi(a))
102
Dp/q (psi/stb/d)
tetf = SRV
A√k FCD’
Contacted HCPV = 2,800 Mstb
SRV = 850 Mstb
Np/ceDp (Mstb)
q/Dp (stb/d/psi)
Square Root Time
q/Dp (stb/d/psi)
Field Example – RTA – Simplified
Time (d)
24
Field Example – RTA - Modeling High efficiency “short” fracs
Ozkan et al. 2009, “Tri-Linear Flow”
Low efficiency “long” fracs
Stalgorova et al, 2013, “Five Region Model”
Summary of Current Unconventional RTA Technology Provides a “bulk” reservoir interpretation Reliable estimation of stimulated and total connected HCPV Identification of effective system permeability and apparent skin damage No unique interpretation of fracture properties (orientation, distribution, density, length and conductivity) No unique interpretation of matrix permeability Analytical models with different geometries are available
The Future of Unconventional RTA – Probabilistic Approach Rate Transient Analysis: Deterministic
Data q, pwf
Modeling – Realizations of RTA results: Probabilistic 27
Probabilistic Well Performance Analysis Define ranges or distributions of input parameters Completion properties Reservoir properties
Run the reservoir model probabilistically using Monte Carlo simulation Keep only history matches that meet a minimum goodness of fit criteria Report reservoir characteristics and production forecasts as distributions, not single values
28
Probabilistic Well Performance Analysis – Forecasts Rate vs Time
Expected Ultimate Recovery
Rate vs Cumulative
Original Gas in Place
29
Conclusions RTA provides “bulk” reservoir interpretation Ideal for establishing connected HCPV Assists in understanding recovery mechanism Yields reliable production forecasts
Analyzing unconventional well production presents significant challenges Analysis and modeling technology has evolved Unconventional plays are statistical in nature – many wells must be analyzed to understand behavior A probabilistic approach will help to manage and communicate uncertainty 30
Thank-you… Questions?
31
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