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Overview

2 reservoirs (Convection Center, Santa Monica)

Convection Center reservoir to be developed

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Objective

DETERMINE:

Cumulative oil production

Cumulative gas production

GOR and pressure depletion

Optimum number of wells

Total Revenue and rate of return

MAKE MONEY!!!!

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4 Scenarios Investigated

Case 0: No secondary recovery

Case 1: Returning 50% of produced gas from beginning

Case 2: Returning 50% of produced gas after reservoir pressure declinesto 1000 psia

Case 3: Returning all of produced gas into the reservoir

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Assumptions

1. Gas-Oil Contact remains constant and the gas resulting from gas-capexpansion diffuses throughout the oil column.

2. Injection wells are to be considered separate from production wells;however producing wells can be converted to gas injection if needed.

3. The reservoir will be blown-down to recover the gas upon completion

of the primary recovery.4. Rig constrain Maximum of 4 wells can be drilled at one time

5. Drilling time is averaging about 30 days.

6. The gas is separated from the oil at surface separator pressure of 400psig.

7. The estimated cost of gas compression is $1/Mscf. (includes facilities)8. Non-Darcy effects for gas injection are negligible.

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Volumetrics

Reservoir with gas cap

Volume based on frustum of pyramid

Calculated with

Area of the reservoir 2400 acres

Area of Oil-Gas Contact 600 acres

Area of Top of Gas Cap 300 acres

Average Thickness 55 ft in the oil zone

5 ft in the gas cap

Volume occupied by oil 77,000 ft-acresVolume occupied by gas 7,000 ft-acres

=31+2+ 12

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Reservoir with gas cap

To calculate Oil-In-Place

To calculate Gas-In-Place

To calculate m

Reservoir Volume

Initial Oil in Place (N) 83.304 MMSTB

Initial Gas in Place (G) 26,041.82 MMSCF

m 0.5104

=

7758 1

= 43,560 1

=

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Excel

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Designing Excel Macro Steps

Step 1: Set Initial conditions (which is at bubble point at Pb =

1,580 psia )

Step 2: Material balance equation

= + + 1

12

0

+

12

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Production Model

Limitations

Number of years = 10 Economic limit = 5 STB/day

Minimum Spacing = 10 acres

Maximum Allowable Rate per well = 300 STB/day

Modeled Production based on Hyperbolic Decline model

D = 0.61 year-1

b = 0.8

=

11 1

= 1 + 1

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Forecasting

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Cumulative Production against time

Npvs. t

Gpvs. t

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Graph of Pressure decline & GOR

GOR vs. t

P vs. t

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Summary of production and NPV (after-tax)

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Results: Optimum number of wells &Recovery Factor

Optimum number of wells

Recovery Factor

Case # Case Well #

0 No gas injection 89

1 50% gas injection at all P 112

2 50% gas injection below 1,000 psia 99

3 100% gas injection 164

Case # Case Recovery Factor

0 No gas injection 26.71%1 50% gas injection at all P 31.08%

2 50% gas injection below 1,000 psia 28.23%

3 100% gas injection 40.82%

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NPV

ROR

Results: NPV and ROR comparisons

Case # Case

no stimulation stimulation

0 No gas injection 110.83 69.72

1 50% gas injection at all P 277.91 226.82

2 50% gas injection below 1,000 psia 165.03 119.52

3 100% gas injection 569.94 497.30

NPV ($ Million)

Case # Case

no stimulation stimulation

0 No gas injection 2.28% 1.41%1 50% gas injection at all P 5.34% 4.28%

2 50% gas injection below 1,000 psia 3.32% 2.36%

3 100% gas injection 9.72% 8.33%

ROR

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Results: Payback Time

Case # Case

no stimulation stimulation

0 No gas injection 7.93 8.63

1 50% gas injection at all P 6.34 6.85

2 50% gas injection below 1,000 psia 7.29 7.91

3 100% gas injection 5.13 5.55

Payback time (years)

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Conclusions and Recommendations

Based on the assumptions made, our management recommend Scenario 3

(which is to inject all the produced gas back to the reservoir). Why?

1. Shortest payback time

2. Highest NPV at 10 years

3. Highest Rate Of Return (ROR)

4. Highest Recovery Factor

Number ofwells: 164

NPV = $569.94Million

No Stimulation

NPV = $497.3 Million

Stimulation

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Any Questions?

THANK YOU!!!!!