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7/28/2019 Day 4 Pm - Simulations & Reserve Management
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7/28/2019 Day 4 Pm - Simulations & Reserve Management
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RESERVOIR SIMULATION RESERVES
Numerical Simulation/Reservoir Modeling
Forecast reservoir production performance and prognose recovery
factor and reserves
Limited or no well flow and performance data
Simplistic estimate methods of production and recovery unavailable
geological, geophysical, petrophysical and reservoir engineering data available for integration
Separate resource and reserve estimates from other methods
Performance History Matching & Forecasting
Constant update of reservoir tank unit/field pressure, production data
Reconciliation with other evaluations and identification of downside risk
and upside potentials
Cautions
Reservoir simulation modeling exercises do not evaluate OOIP/OGIP with
reservoir dimensions as an input
Not more accurate than other methodsPerformance & Reservoir Simulations2
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Bullmose Field Reservoir
Simulation
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BULLMOOSE FIELD RESERVOIR SIMULATION
RESERVOIR STRUCTURE MAPPING
Initial G&G Studies of Reservoir Tank Quality
HYDRODYNAMICS AND HYDROSTATICS
Constant Update of Reservoir Unit/Field Pressure Data
Compilation of Reservoir Fluid Properties
PRODUCTION PERFORMANCE
Well Performance Pattern
Historical Production Data
RESERVE DISTRIBUTION/RETENTION
Key Factors Controlling Recovery Factor/Reserves
Optimization of Reserve Development
Potential Economic Barrier to Proved ReservesPerformance & Reservoir Simulations4
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BULLMOOSE FIELD RESERVOIR SIMULATION
c-85-E
b-43-E
a-25-F
d-77-E
c-20-L
Well Distances
c-20-L c-85-E 4900md-77-E d-43-E 4400md-77-E a-39-F 7500ma-39-F a-25-F 3800ma-39-F a-06-F 3380 mc-85-E a-39-F 7250 ma-25-F d-15-F 1760 m
Production WellsC-20-L
D-77-E
C-85-E
A-39-F
A-06F
A-25-F
Monitor Well
B-43-E
Standing Wells
A-04-F
A-81-C
a-04-Fa-39-F
52 bcf
31 bcf
110 bcf
17 bcf
4 bcf
Monitor Well
a-06-F
2.2 bcf
a-81-C
Performance & Reservoir Simulations5
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BULLMOOSE FIELD RESERVOIR SIMULATION
East BullmooseReservoir
Bullmoose Reservoir
Triassic SandpackLow PermeabilityThrust FoldingNatural Fractures
(Type I & II)
Bullmoose Wells Gas Analysis
0%
10%
20%
30%
40%
50%
60%
H2
He
N2
CO2
H2S
C1
C2
C3
iC4
nC4
iC5
nC5
C6
C7
d-77-E
a-39-F
c-20-L
a-25-F
Performance & Reservoir Simulations6
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BULLMOOSE FIELD RESERVOIR SIMULATION
A-04-F Reserve/Resources Estimates:OGIP: 36 bcf(based on 741 acres, 5% p.u., 35% Sw, 32 m pay)
Recoverable: 23 bcf (65% RF, but capture isue)Sales Gas: 12.65 bcf (45% shrinkage)
Entire East Bullmoose Structure:
All Polygons Summed up 154 bcf GIP
Three Existing Wells: a-25-F (producing), a-04-F & a-81-C
Northern Polygon: 43 bcfa-25-F Polygon: 49 bcfSouthern Polygon: 26 bcf
Overall Recovery Factor: 60~85%
Performance & Reservoir Simulations7
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BULLMOOSE FIELD RESERVOIR SIMULATION
Faulting Trench
might have formeda syncline dippinginto the transitionzone, creating twoseparate reservoirunits
Performance & Reservoir Simulations8
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BULLMOOSE FIELD RESERVOIR SIMULATIONBullmoose/East Bulmoose Wells Pressure Depletion
0
500
1000
1500
2000
2500
3000
3500
4000
4500
08-Mar-71 28-Aug-76 18-Feb-82 11-Aug-87 31-Jan-93 24-Jul-98 14-Jan-04 06-Jul-09
Date
DatumPressures(psia)
d-77-E
c-20-L
c-85-E
a-39-F
a-25-F
b-43-E
a-06-F
d-77-E
c-20-L
c-85-E
a-39-F
a-25-E
a-25-F on-production since Apr 2005
d-77-E on-production since Feb 1980
c-20-L on-production since Nov 1982
a-39-F on-production since Dec 2001
c-85-E on-production since Feb 2003
b-43-E
(monitor)
well cum reserve
d77E 110 132
c20L 52 56
c85E 31 64~69
a39F 17 40
a06F 1.7
a25F 4.0
d04F
a-06-F
a-06-F on-production since Apr 2006
Performance & Reservoir Simulations9
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BULLMOOSE FIELD RESERVOIR SIMULATION
Bullmoose Wells Initial Reservoir Static Pressure Profiles
(before production for each well)
-1600
-1500
-1400
-1300
-1200
-1100
-1000
20000 22000 24000 26000 28000 30000 32000 34000
Initial Reservoir Pressures (kPa)
SubseaDepth(m)
a-25-F
c-20-L
d-77-E
a-39-F
a-06-F
2.64 kPa/m
[2.11, 3.18] kPa/m
d-77-E
a-25-F
c-20-L
a-39-F
Oct 1991Sept 1991
Feb 1992
Dec 2004
Sept 1975
Nov 1976
July 1981
Feb 1978
July 1982Sept 1982
a-06-F
Jan 2006
Performance & Reservoir Simulations10
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BULLMOOSE FIELD RESERVOIR SIMULATIONBullmoose Wells Pressure Profile Over Development
-1700
-1600
-1500
-1400
-1300
-1200
-1100
-1000
0 5000 10000 15000 20000 25000 30000
Pressures (kPa)
SubseaDepth(m)
d-77-E
a-39-F
c-85-E
a-25-F
b-43-E
c-20-L
a-06-F
initial reservoir pressure line
depletion over time
d-77-E
a-25-F
c-20-L
a-39-F
c-85-E
b-43-E
a-06-F
Performance & Reservoir Simulations11
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BULLMOOSE FIELD RESERVOIR SIMULATION
Pressure Sources
Bottomhole PBU
DST
Wireline Testers
Static Gradient Survey
Permanent Downhole Gauges
Production Logging
Cullender & Smith
Fluid Sampling/Properties
Flow Test/DST/AOF
Wireline Testers
Surface Production
A-39-F on-stream Dec 2001
Sep-1991 3091.1 2997.9 28273 1586.1 -1505 BH Stat Grad
Oct-1991 3066.1 2973.1 27004 1586.1 -1480 BH Stat Grad
Feb-1992 2867.6 2777.9 26537 1586.1 -1281.5 BH Buildup
Jun-2001 2958.6 2958.6 26007 1586.1 -1372.5 BH Stat Grad
Feb-2004 3193.6 3198.8 22064 1586.1 -1607.5 BH Stat Grad
Sep-2004 2957.8 21794 1586.1 -1371.7 Cul & Smith
C-85-E on-stream 2004
Feb-2003 2196.3 20118 1073.5 -1122.8
Jun-2004 2196.3 17065 1073.5 -1122.8
A-25-F on-stream April 2005
Dec-2004 2504.5 26907 1309.5 -1195 BH Buildup
C-20-L on-stream Nov 1982
Feb-1978 2937 27820 1403 -1534 BH Buildup
Jul-1981 2779 27131 1403 -1376 BH Stat Grad
Jul-1982 2935 27589 1403 -1532 BH Stat Grad
Sep-1982 2935 27708 1403 -1532 BH Stat Grad
Aug-1983 2900 27280 1403 -1497 BH Stat Grad
Aug-1986 2900 26467 1403 -1497 BH Stat Grad
Jul-1988 2934 25905 1403 -1531 BH Stat Grad
Aug-1990 2929 24016 1403 -1526 BH Stat Grad
Jun-1995 2874.7 20161 1403 -1471.7 Cul & Smith
Sep-1997 2881.2 19665 1403 -1478.2 Cul & SmithJun-2004 2853.7 16368 1403 -1450.7 Cul & Smith
B-43-E
Oct-1985 3197 26629 1631 -1566 BH Stat Grad
Jul-1987 3000 24127 1631 -1369 BH Stat Grad
Jul-1988 3000 24935 1631 -1369 BH Stat Grad
Nov-1989 3048.2 24095 1631 -1417.2 BH Stat Grad
Oct-1990 3050 24041 1631 -1419 BH Stat Grad
a-06-F on-stream April 2006
Jan-2006 2629.4 26472 1308.9 -1320.5 BH Buildup
Performance & Reservoir Simulations12
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BULLMOOSE FIELD RESERVOIR SIMULATION
Pressure Sources
Bottomhole PBU
DST
Wireline Testers
Static Gradient Survey
Permanent Downhole Gauges
Production Logging
Cullender & Smith
Fluid Sampling/Properties
Flow Test/DST/AOF
Wireline Testers
Surface Production
PITFALLS OF EACH METHOD?
Right Solutions
Data Reliability
Technology Advances
Environmental Issues
Operation Cost
Full-Cycle Consideration
Government Regulations
Performance & Reservoir Simulations13
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BULLMOOSE FIELD RESERVOIR SIMULATION
A-04-F Reserve/Resources Estimates:OGIP: 36 bcf(based on 741 acres, 5% p.u., 35% Sw, 32 m pay)
Recoverable: 23 bcf (65% RF, but capture isue)Sales Gas: 12.65 bcf (45% shrinkage)
Entire East Bullmoose Structure:
All Polygons Summed up 154 bcf GIP
Three Existing Wells: a-25-F (producing), a-04-F & a-81-C
Northern Polygon: 43 bcfa-25-F Polygon: 49 bcfSouthern Polygon: 26 bcf
Overall Recovery Factor: 60~85%
Performance & Reservoir Simulations14
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BULLMOOSE FIELD RESERVOIR SIMULATIONBullmoose Field Production
1,000
10,000
100,000
Aug-1976 May-1979 Feb-1982 Nov-1984 Aug-1987 May-1990 Jan-1993 Oct-1995 Jul-1998 Apr-2001 Jan-2004 Oct-2006 Jul-2009
Date
RawGasRate(mcfd)
d-77-E
c-20-L
a-39-F
c-85-E
a-25-F (East Bullmoose)
a-06-F
c-20-L finally drained
c-85-E still doing wella-39-F in decline
d-77-E the best well
Bullmoose Field Production
1,000
10,000
100,000
Ap r-2001 Dec-2001 Sep -2002 May-2003 Jan-2004 Sep-2004 May-2005 Feb-2006 O ct-2006 Jun-2007
Date
RawGasRate(mcfd)
d-77-E
c-20-L
a-39-F
c-85-E
a-25-F (East Bullmoose)
a-06-F
Performance & Reservoir Simulations15
Bullmoose Field Production
1,000
10,000
100,000
Ap r-2001 Dec-2001 Sep-2002 May-2003 Jan-2004 Sep-2004 May-2005 F eb -2006 O ct-2006 Jun-2007
Date
RawGasRate(mcfd)
a-39-F
a-25-F (East Bullmoose)
a-06-F
a-39-F
a-06-F
a-25-F
a-39-F produced 64 months beforea-06-Fonstream
a-39-F began a slow decline after 17 months
a-25-F production looks like
the current state ofa-39-F
and a-06-F
a-06-Fproduction
looks like it has notbeen affected by a-
39-F's drain
But this well can maintain high rates for long time
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BULLMOOSE FIELD RESERVOIR SIMULATIONa-39-F Material Balance Decline
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
0 5 10 15 20 25 30 35 40 45 50
Cum (bcf)
P/Z(kPaa)
Estimated Pressures
best Line Fitting
41 bcf EUReconomical/operational limit
Performance & Reservoir Simulations16
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BULLMOOSE FIELD RESERVOIR SIMULATIONa-39-F Arps Decline Analysis
0
5000
10000
15000
20000
25000
Apr-2001 Oct-2006 Apr-2012 Sep-2017 Mar-2023 Sep-2028
Date
GasRate(mcfd)
Raw Gas Rate
Arps Fitting
Forecast
economical/operational limit: 1200 mcfd
hyperbolic decline
n=0.5
b=13%
initial rate 18.4 mmcfd
initial forecast rate 7.7 mmcfd
final rate 1.2 mmcfd
a-39-F Cum-Rate Forecast
0
5000
10000
15000
20000
25000
0 5 10 15 20 25 30 35 40 45
Cumulative Gas (bcf)
GasRate(mmcfd)
Cum Production History
Cum Forecast
economical/operational limit: 1200 mcfd 40 bcf
hyperbolic decline
n=0.5
b=13%
initial rate 18.4 mmcfdinitial forecast rate 7.7 mmcfd
final rate 1.2 mmcfd
total recoverable gas: 40 bcf
cumulative gas: 17 bcf
remaining gas: 23 bcf
Performance & Reservoir Simulations17
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BULLMOOSE FIELD RESERVOIR SIMULATIONc-20-L Arps Decline Analysis
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
May-1979 Nov-1984 May-1990 Oct-1995 Apr-2001 Oct-2006 Apr-2012
Date
GasRate(mcfd)
Historical Gas Rate
Arps FittingForecast Gas Rate
exponential decline
initial rate 3.4 mmcfd
final rate 1.2 mmcfd
economical/operational limit
c-20-L Cum-Rate Forecast
0
2000
4000
6000
8000
10000
12000
14000
0 10 20 30 40 50 60
Cumulative Gas (bcf)
GasRate(mcfd)
Cumulative Production
Cumulative Forecast
economical/operational limit
exponential decline
initial rate 3.4 mmcfd
final rate 1.2 mmcfd
total recoverable gas: 55.4 bcf
cum production: 52 bcf
remaining 3.4 bcf
55.4 bcf
Performance & Reservoir Simulations18
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BULLMOOSE FIELD RESERVOIR SIMULATION
East Bullmoose a-04-F Properties
Gas Properties (analog from a-25-F; averaged):H2S: 28.38%CO2: 14.69%N2: 0.33%
C1: 56.48%
Pressure: TBT (prognosed at 26,900 kpa)Temperature: TBT (prognosed at 70 oC)
Gas PVT Properties:Specific Gravity: 0.87Compressibility Factor: 0.756FVF: 295 Scf/cfViscosity: 0.0328 cp
Economical Rate: >1200 mcfd (due to high shrinkage)
Performance & Reservoir Simulations19
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BULLMOOSE FIELD RESERVOIR SIMULATION
pay = 105 ftporosity = 4~5 %Sw = 35%
a-25-F flowing date: April 2005a-81-C will flow Oct 2007a-04-F will flow Oct 2008
Economical Rate = 1.2 mmcfdWellhead Pressure = 750 psi
a-25-F
a-04-F
a-81-C
Must honor:(1) Pore volume, or GIP=154 bcf)
(2) Spacings between wells
(3) Distances to effective reservoir boundaries
Basic Scenario:
vertical wellsk=0.1 md (homogeneous)
Results:
a-25-F: 17.8 bcfa-04-F: 10.4 bcfa-81-C: 15.1 bcf
Recovery: 28%
Performance & Reservoir Simulations20
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BULLMOOSE FIELD RESERVOIR SIMULATION
a-25-F
a-04-F
a-81-C
pay = 105 ftporosity = 4~5 %Sw = 35%
a-25-F flowing date: April 2005a-81-C will flow Oct 2007a-04-F will flow Oct 2008
Economical Rate = 1.2 mmcfdWellhead Pressure = 750 psi
Third Scenario
vertical wellsk = 0.1 md (matrix)
wellbore connectedto fractures (2500 ft)
plus a few fractures
a-25-F: 20.4 bcfa-04-F: 15.5 bcfa-81-C: 15.5 bcf
Recovery: 36%
Performance & Reservoir Simulations22
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BULLMOOSE FIELD RESERVOIR SIMULATION
a-25-F
a-04-F
a-81-C
pay = 105 ftporosity = 4~5 %Sw = 35%
a-25-F flowing date: April 2005a-81-C will flow Oct 2007a-04-F will flow Oct 2008
Economical Rate = 1.2 mmcfdWellhead Pressure = 750 psi
Fourth Scenario
vertical wellsk = 0.1 md (matrix)
wellbore connectedto long crossed
fractures (5000 ft)
a-25-F: 40.3 bcfa-04-F: 23 bcfa-81-C: 26.1 bcf
Recovery: 57%
Performance & Reservoir Simulations23
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BULLMOOSE FIELD RESERVOIR SIMULATION
Fourth Scenario
vertical wellsk = 0.1 md (matrix)
wellbore connectedto long crossed
fractures (5000 ft)
a-25-F: 40.3 bcfa-04-F: 23 bcfa-81-C: 26.1 bcf
Recovery: 57%
A-04-F
A-25-F
A-81-C
Performance & Reservoir Simulations24
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BULLMOOSE FIELD RESERVOIR SIMULATIONEast Bullmoose Field Production Predictions
0
5
10
15
20
25
30
35
0 1,000 2,000 3,000 4,000 5,000 6,000
Days
TotalRawGasRate(3Wells),mmcfd
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
AverageReservoirPressures(psi)
Three Wells Total Raw Gas Rates
a-25-F Field Data
Average Reservoir Pressures
a-25-F
onstream
Apr 2005
a-81-C
onstream
Oct 2007
(assumed)
a-04-F
onstreamOct 2008
(assumed March 2013
East Bullmoose Field Reserve Prediction
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
0 1,000 2,000 3,000 4,000 5,000 6,000
Days
Cumulative/Gas-in-
Place(mmcf)
Gas-In-Place
Cumulative Production
a-25-F Cum Production
Recovery Factor = 89/155 =57%
The performance of the field under three wells, a-
25-F, a-81-C, and a-04-F, is predominantly
controlled by each single well's access to natural
fracture network. If no access or limited access to
natural fractures, each well will recover 8-12 bcf
with the final recovery factor of 30~35 %, based
on the whole field. High pressure gradient was
observed between a-39-F and a-06F.
Performance & Reservoir Simulations25
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BULLMOOSE FIELD RESERVOIR SIMULATIONa-25-F Well Performance
0
2
4
6
8
10
12
14
16
0 1,000 2,000 3,000 4,000 5,000 6,000
Days
RawGasRate(mmcfd)
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
45,000
Pressues(psi)
Raw Gas Rate
Field Gas Rate
Cumulative Production
Field Cum Production
a-25-F Well Performance
0
2
4
6
8
10
12
14
16
0 1,000 2,000 3,000 4,000 5,000 6,000
Days
RawGasRate(m
mcfd)
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
Pressues(psi)
Raw Gas Rate
Field Gas Rate
BHP
Wellhead Pressure
Performance & Reservoir Simulations26
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BULLMOOSE FIELD RESERVOIR SIMULATIONa-81-C Well Performance
0
2
4
6
8
10
12
0 1,000 2,000 3,000 4,000 5,000 6,000
Days
RawGasRate(mmcfd)
0
5,000
10,000
15,000
20,000
25,000
30,000
CumulativeProduction(mmcf)
Raw Gas Rate
Cumulative Gas
a-81-C Well Performance
0
2
4
6
8
10
12
0 1,000 2,000 3,000 4,000 5,000 6,000
Days
Raw
GasRate
(mmcfd)
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
Pressures
(psi)
Raw Gas Rate
Wellhead Pressure
BHP
Performance & Reservoir Simulations27
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BULLMOOSE FIELD RESERVOIR SIMULATIONEast Bullmoose Wells
0
2
4
6
8
10
12
0 1,000 2,000 3,000 4,000 5,000 6,000
Days
IndividualWellRawGasRate(mmcfd)
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
PoolAveragePressure(psi)
a-25-F
a-81-C
a-04-F
Average Pool Pressure
initial pool pressure: 3900 psi
by the time a-81-C is on , thepool pressure is down to 3602
by the time a-04-F is
on, the pool pressure
will have come down to
3391 psi
East Bullmoose Wells Well-Head Pressures
0
500
1,000
1,500
2,000
2,500
3,000
0 1,000 2,000 3,000 4,000 5,000 6,000
Days
WellheadPressur
es(psi)
0
5
10
15
20
25
30
35
TotalRawGasProduction(mmcfd)
a-25-F
a-81-C
a-04-F
Total Raw Gas Production
Performance & Reservoir Simulations29
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BULLMOOSE FIELD RESERVOIR SIMULATIONEast Bullmoose Wells Bottomhole Pressures
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
0 1,000 2,000 3,000 4,000 5,000 6,000
Days
WellheadPressures(psi)
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
averagePoolPressure(psi)
a-25-F
a-81-C
a-04-F
Average Pool Pressure
average pool pressure
a-25-F
a-81-C
a-04-F
a-04-F Reserve/Resource Loss
0
5
10
15
20
25
30
35
40
45
50
0 500 1000 1500 2000 2500 3000 3500 4000
Days
a-04-FGasVolume(bcf)
0
20
40
60
80
100
120
140
160
180
TotalGas-In-Pl
ace(bcf)
a-04-F GIP
a-04-F Raw Recoverable
a-04-F GIP (after onstream)
a-04-F Raw Recoverable (after onstream)
Total East Bullmoose Gas-in-Place
a-25-F began to produce @ Apr 2005
a-81-C begins to
produce @ Oct 2007
a-04-F begins to
produce @ Oct 2008
21 bcf
32.4 bcf
22 bcf
34 bcf
23.5 bcf
36 bcf
Performance & Reservoir Simulations30
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BULLMOOSE FIELD RESERVOIR SIMULATION
A Proper Well Test in A-04-F Well Can Answer These Questions:
Current pressure at a-04-F location, whether it is still virgin or has been
depleted as a result of a-25-F production
An extended bottomhole pressure gauge buildup can sense if a-25-F is effectively draining gas from
a-04-F area
Degree of pressure depletion, which can determine the natural fracture
access effectiveness
A-04-F well deliverability and AOF
Whether or not 2-3 more wells are required in order to produce the
remaining reserves of East Bullmoose
Economical/commercial parameters should be sensitized to determine
more drilling/completion/pipeline/plant/tie-in/operation cost of
additional 2-3 wells are justifiable
Performance & Reservoir Simulations31
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West Ojay Field Reserve
Progression
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PERFORMANCE RESERVES: WEST OJAY
d-11-I
d-41-E
d-
17
-F
a-65-E
b-77-E
Well
GWC
BasalFault
GasB
earin
gZon
e
FrontLimb
BackLimb
Schematic X-Section of Fault PropagationFold Structure
Well
GWC
BasalFault
GasB
earin
gZon
e
FrontLimb
BackLimb
Schematic X-Section of Fault PropagationFold Structure
Performance & Reservoir Simulations33
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PERFORMANCE RESERVES: WEST OJAYWest Ojay Triassic Production Wells
0
10,000
20,000
30,000
40,000
50,000
60,000
Mar-1999 Dec-1999 Aug-2000 Apr-2001 Dec-2001 Sep -2002 May-2003 Jan-2004 Sep -2004 May-2005 Feb -2006 Oct -2006
Date
Raw
gasrate(mmcfd)
a-65-E
d-41-E
b-77-E
d-11-I
three wells south
West Ojay Triassic Production Wells
0
10,000
20,000
30,000
40,000
50,000
60,000
0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000
Cum (mmcf)
Raw
gasrate(mmcfd)
a-65-E
d-41-E
b-77-E
d-11-I
three wells south
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PERFORMANCE RESERVES: WEST OJAY
Well OGIP
(bcf)
RF
(%)
Recoverable
(bcf)
PDP
(bcf)
PUD
(bcf)
Cum
(bcf)
Descriptions
D-11-I 27 80% 19 19 ? 12
Half way column than theSouth Structure; dualporosity/permeability feature;low decline rate (7%)
A-65-E 68 79% 54 42 12 17
Moderate rate; slow decline;fractured reservoir; exponentialdecline,; interference from b-77E
D-41-E 68 83% 57 42 15 23
Highly fractured reservoirconnectivity from PTA; highrates; production cape; largedrainage area; structurally high
B-77-E 37 81% 30 23 7 1.7
High IP rate; sharp decline,connected to a-65-E duringPBU; low late-time harmonicdecline
Initial Reserve/Resource Bookings
PUD reserves are compression reserves at lower operating wellhead pressure conditions
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PERFORMANCE RESERVES: WEST OJAY
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PERFORMANCE RESERVES: WEST OJAY
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PERFORMANCE RESERVES: WEST OJAY
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PERFORMANCE RESERVES: WEST OJAY
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PERFORMANCE RESERVES: WEST OJAY
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PERFORMANCE RESERVES: WEST OJAY
West Ojay d-11-I
10-3
10-2
10-1
100
101
102
103
104
105
106
107
Delta Pseudo-T (hr)
PD=1/2
2001/11/05-1843 : GAS (PSEUDO-PRESSURE)
Double-Porosity Reservoir(P.S.S.)** Simulation Data **well. storage = 0.0120 M3/KPA
Skin(mech) = -4.90permeability = 2.40 MDomega = 0.194lambda = 0.714E-05Perm-Thickness = 59.0 MD-METRETurbulence = 0.0000048 1/M3/D+x boundary = 209. METRE (1.00)-x boundary = 1300. METRE (1.00)+y boundary = 107. METRE (1.00)-y boundary = 1980. METRE (1.00)Initial Press. = 23604.7 KPAAverage Press. = 20471.8 KPASkin(mech)+DQ = -3.73Smoothing Coef = 0.,0.
Static-Data and ConstantsVolume-Factor = 6.496 M3/KM3
Thickness = 24.60 METREViscosity = .1760E-04 PA.STotal Compress = .4273E-04 1/KPARate = 245300. M3/DStorivity = .6412E-04 METRE/KPADiffusivity = 185.9 METRE^2/HRGauge Depth = N/A METREPerf. Depth = N/A METREDatum Depth = N/A METREAnalysis-Data ID: DATA1Based on Gauge ID: GAU003
Linear Comp osite Model - d-11-I
Dual-Porosi ty Model
K = 2.4 mdSkin = -4.9
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PERFORMANCE RESERVES: WEST OJAY
West Ojay d-41-E Triassic
10-3
10-2
10-1
100
101
102
105
106
Delta Pseudo-T (hr)
PD=1/2
2003/06/17-2102 : GAS (PSEUDO-PRESSURE)
Linear-Composite 2-Zone** Simulation Data **well. storage = 0.149E-08 M3/KPASkin(mech) = -3.58permeability = 13.8 MDX-Interface(1) = 200. METREMob.ratio(1) = 0.500Stor.ratio(1) = 0.496Perm-Thickness = 524. MD-METRETurbulence = 0.24E-06 1/M3/D+x boundary = 665. METRE (1.00)-x boundary = 1000. METRE (1.00)+y boundary = 1900. METRE (1.00)-y boundary = 1900. METRE (1.00)Initial Press. = 26741.1 KPAAverage Press. = 26736.5 KPASkin(mech)+DQ = -3.48Smoothing Coef = 0.,0.
Static-Data and ConstantsVolume-Factor = 4.450 M3/KM3Thickness = 37.90 METREViscosity = 0.02100 CPTotal Compress = .2485E-04 1/KPARate = 394100. M3/DStorivity = .5980E-04 METRE/KPADiffusivity = 1483. METRE^2/HRGauge Depth = N/A METREPerf. Depth = N/A METREDatum Depth = N/A METREAnalysis-Data ID: DATA 1Based on Gauge ID: GAU001
Linear Composite Model - d-41-E
Linear Composite Model - Well in Fracture Corridor
K = 13.8 mdSkin = -3.6
K = 6.9 md
FractureCorridor
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PERFORMANCE RESERVES: WEST OJAY
West Ojay a-65-E Triassic
10-2
10-1
100
101
102
103
10-4
10-3
Delta Pseudo-T (hr)
PD=1/2
2001/05/08-0043 : GAS (PSEUDO-PRESSURE)
Linear-Composite 2-Zone** Simulation Data **well. storage = 0.0320 BBLS/PSISkin(mech) = -4.98permeability = 1.18 MDX-Interface(1) = 135. FEETMob.ratio(1) = 5.09Stor.ratio(1) = 0.687Perm-Thickness = 96.5 MD-FEETTurbulence = 0. 1/MSCF/D+x boundary = 2640. FEET (1.00)-x boundary = 2640. FEET (1.00)Initial Press. = 3886.63 PSISkin(mech)+DQ = -4.98Smoothing Coef = 0.,0.
Static-Data and ConstantsVolume-Factor = 0.7925 RB/MSCFThickness = 81.70 FEETViscosity = 0.02100 CPTotal Compress = 0.0001718 1/PSIRate = 22250. MSCF/DStorivity = 0.0009261 FEET/PSIDiffusivity = 1309. FEET^2/HRGauge Depth = 9852. FEETPerf. Depth = 8975. FEETDatum Depth = N/A FEETAnalysis-Data ID: DATA 1Based on Gauge ID: GAU001
Linear Composite Model - a-65-E
Composite Linear Model - Fracture Corridor
Proximal to well
K = 1.18 mdSkin = -4.9
K = 6.0 mdFractureCorridor
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10-3 10-2 10-1 100 101 102 103106
107
108
109
1010
1011
Delta Pseudo-T (hr)
2005/08/16-0336 : GAS (PSEUDO-PRESSURE)
100 hrs into the buildup,the recorder sees a no-flowboundary, or pulling awayeffect.
PERFORMANCE RESERVES: WEST OJAY
Performance & Reservoir Simulations45
a-65-E, b-77-E, d-41-E, and D-11-I Production Data
10
100
1000
10000
17-Feb-05 28-May-05 5-Sep-05 14-Dec-05 24-Mar-06 2-Jul-06 10-Oct-06
date
gasrate(e3m3d)
a-65-E
b-77-E
d-41-E
d-11-I
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PERFORMANCE RESERVES: WEST OJAY
b-77-E Production Decline History
0
2
4
6
8
10
12
14
16
18
7/17/05 9/5/05 10/25/05 12/14/05 2/2/06 3/24/06 5/13/06 7/2/06 8/21/06 10/10/06
Date
RawGasRate(mmcfd)
0
500
1,000
1,500
2,000
2,500
3,000
WellheadPressures(psi)
Raw Gas Rate
WellHead Pressure
Flatting out?
b-77-E Production Decline History
0
2
4
6
8
10
12
14
16
18
7/17/05 9/5/05 10/25/05 12/14/05 2/2/06 3/24/06 5/13/06 7/2/06 8/21/06 10/10/06
Date
RawGasRate(mmcfd)
0
500
1,000
1,500
2,000
2,500
3,000
WellheadPressures(psi)
Raw Gas Rate
WellHead Pressure
Flatting out?
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estimated current averagereservoir pressure 2231 psi
estimated original reservoirpressure 3586 ~ 3703 psi
1250 psi line pressure
250 psi line pressure
8.3 mmcfd
4 ~ 5 mmcfd (today)
500 psi line pressure
7.8 mmcfd
pressure depletion
B-77-E
PERFORMANCE RESERVES: WEST OJAY
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estimated current averagereservoir pressure 2645 psi
estimated original reservoirpressure 3701 ~ 3887 psi
1250 psi line pressure
250 psi line pressure
13 mmcfd
9.5 mmcfd (today)
500 psi line pressure12.5 mmcfd
pressure depletion
A-65-E
PERFORMANCE RESERVES: WEST OJAY
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D-41-E
1250 psi linepressure
3800 psi initial Pi
500 psi linepressure
current reservoir pressure:
2200 ~ 2500 psi
pressure depletion
20 mmcfd
30 mmcfd
today
PERFORMANCE RESERVES: WEST OJAY
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PERFORMANCE RESERVES: WEST OJAY
West Ojay reservoir initial pressures, 41.4 /31 MPa
(6000/4500 psi), respectively. The gas plant line pressure,
back pressure on the reservoirs ~8.27 Mpa (1200 psi). Without
compression we leave about 20 to 27% of the pressure energy
in the reservoir.
Need for compression to
Maximize the reserve (a-65-E and d-41-E)
Maximize rate and value of the resource
Increase the ability of our well to compete with competitors
Minimize flow assurance problem (b-11-I)
Standardize Compressors, to simplify maintenance
400 HP for smaller wells
1000 HP for larger projects
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PERFORMANCE RESERVES: WEST OJAY
Forecasting Future Like A Long Shot
will these wells continue to produce gas and send a profit-
sharing pension cheque to my grandson after his
retirement?)