day 4 pm - simulations & reserve management

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


3/52

Bullmose Field Reservoir

Simulation


4/52

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


5/52


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


6/52


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



7/52


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%



8/52


Faulting Trench

might have formeda syncline dippinginto the transitionzone, creating twoseparate reservoirunits



9/52

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



10/52


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



11/52

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



12/52


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



13/52


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



14/52


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%



15/52

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-06-F


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-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


16/52

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



17/52

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


total recoverable gas: 40 bcf

cumulative gas: 17 bcf

remaining gas: 23 bcf



18/52

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



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



total recoverable gas: 55.4 bcf

cum production: 52 bcf

remaining 3.4 bcf

55.4 bcf



19/52


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)



20/52


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%



21/52


22/52


a-25-F

a-04-F

a-81-C




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%



23/52


a-25-F

a-04-F

a-81-C




Fourth Scenario


wellbore connectedto long crossed

fractures (5000 ft)

a-25-F: 40.3 bcfa-04-F: 23 bcfa-81-C: 26.1 bcf

Recovery: 57%



24/52


Fourth Scenario


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



25/52

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


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.



26/52

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


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



27/52

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



28/52


29/52

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



30/52

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



31/52


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



32/52

West Ojay Field Reserve

Progression


33/52

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



34/52

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



35/52


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



36/52




37/52




38/52




39/52




40/52




41/52


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



42/52


West Ojay d-41-E Triassic

10-3

10-2

10-1

100

101

102

105

106

Delta Pseudo-T (hr)

PD=1/2


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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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


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)


100 hrs into the buildup,the recorder sees a no-flowboundary, or pulling awayeffect.



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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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


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


Raw Gas Rate

WellHead Pressure

Flatting out?



47/52

estimated current averagereservoir pressure 2231 psi

estimated original reservoirpressure 3586 ~ 3703 psi

1250 psi line pressure


8.3 mmcfd

4 ~ 5 mmcfd (today)


7.8 mmcfd

pressure depletion

B-77-E




48/52

estimated current averagereservoir pressure 2645 psi

estimated original reservoirpressure 3701 ~ 3887 psi



13 mmcfd

9.5 mmcfd (today)

500 psi line pressure12.5 mmcfd

pressure depletion

A-65-E




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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




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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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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?)

day 4 pm - simulations & reserve management

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