npv_gas_apr 1_2011

WellWell NumberEngineerDate

Economic DataFrac Fluid Unit CostProppant Unit CostFixed Equipment CostWorkover CostUnit Revenue for Production Oil/GasRevenue Escalation RateDiscount RateTime Period

Frac CostsFrac Fluid Frac PropSize Volume Cost

(Tonnes) (m³) (€)Base 0 0 0Scenario 1 T 0.00Scenario 2 T 0.00Scenario 3 T 0.00Scenario 4 T 0.00Scenario 5 T 0.00Scenario 6 T 0.00Scenario 7 T 0.00Scenario 8 T 0.00Scenario 9 T 0.00Scenario 10 T 0.00

USER GRAPH

0 2 4 6 8 10 120.00

2.00

4.00

6.00

8.00

10.00

12.00 years

Frac Size (tonnes)

NP

V

CHART 1

0 2 4 6 8 10 120.00

2.00

4.00

6.00

8.00

10.00

12.00 years

Frac Size (tonnes)

NP

V

Economics 1170 ron / t Merisani Oil Adrian M. Feb 10, 2011Net Price 500 ron / 1000 m3 Merisani Gas

Reservoir Data€/m³ Formation€/kg Reservoir Fluid€ Bottomhole Temp€ Reservoir Btm Pressure€/m³ Reservoir Drainage area% Porosity% Permeabilityyears Water Saturation

Gas Specific Gravity

Frac Fluid Frac Cost Initial Propped Upper ProppedCost Investment Length Height(€) (€) (€) (m) (m)0 0 0 0 0

0.00 0.00 0.000.00 0.00 0.000.00 0.00 0.000.00 0.00 0.000.00 0.00 0.000.00 0.00 0.000.00 0.00 0.000.00 0.00 0.000.00 0.00 0.000.00 0.00 0.00

0 2 4 6 8 10 120.00

2.00

4.00

6.00

8.00

10.00

12.00 years

Frac Size (tonnes)

NP

V

0 2 4 6 8 10 120

2

4

6

8

10

12 Net Present Value Tonnes

Days

NP

V

CHART 1

0 2 4 6 8 10 120.00

2.00

4.00

6.00

8.00

10.00

12.00 years

Frac Size (tonnes)

NP

V

0 2 4 6 8 10 120

2

4

6

8

10

12 Net Present Value Tonnes

Days

NP

V

Top BottomPerforation Intervals

Oil/Gas/Water°Cbarha% TVD Top PerforationmD Net Pay Height%

Lower Propped Avg. Propped Fcd Cumulative Net Height Width Production Production

(m) (mm) (m³) (m³)0 0 0 0 0

0 00 00 00 00 00 00 00 00 00 0

Recommended frac size (tonnnes):Time to Recover Initial Investment (days):

NPV Rt/(1+i)^twheret = the time of the cash flowi = the discount rate (the rate of return that could be earned on an investment in the financial markets with similar risk)Rt = the net cash flow (the amount of cash, inflow minus outflow) at time t. For educational purposes, Ro is commonly placed to the left of the sum to emphasize its role as (minus) the investment

0 2 4 6 8 10 120

2

4

6

8

10

12 Net Present Value Tonnes

Days

NP

V

Net Present Value Tonnes

CHART 2

0 2 4 6 8 10 120

2

4

6

8

10

12 Net Present Value Tonnes

Days

NP

V

m Fluid Systemm Gel Loading kg/m3m Proppantm Proppant Size Mesh

mm

Net NPVValue years

(€) (€)0 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.00

i = the discount rate (the rate of return that could be earned on an investment in the financial markets with similar risk)Rt = the net cash flow (the amount of cash, inflow minus outflow) at time t. For educational purposes, Ro is commonly placed to the left of the sum to emphasize its role as (minus) the investment

0 2 4 6 8 10 120

2

4

6

8

10

12 Net Present Value Tonnes

Days

NP

V

CHART 2

0 2 4 6 8 10 120

2

4

6

8

10

12 Net Present Value Tonnes

Days

NP

V

Rt = the net cash flow (the amount of cash, inflow minus outflow) at time t. For educational purposes, Ro is commonly placed to the left of the sum to emphasize its role as (minus) the investment

BASETime Flow Rate Cum. Prod. Cum. Prod.

(d) (sm^3/d) (10^6 m^3) (%GIP) (bar) (bar) (J/Jo(t)) (J/Jo|avg)

Average Pressure

Flowing Pressure

Prod. Ratio Q/Qbase

Prod. Ratio V/Vbase

0

BASE

1Time Flow Rate Cum. Prod. Cum. Prod.

(d) (sm^3/d) (10^6 m^3) (%GIP) (bar) (bar) (J/Jo(t))

Average Pressure

Flowing Pressure

Prod. Ratio Q/Qbase

0

1

1 2Time Flow Rate Cum. Prod. Cum. Prod.

(J/Jo|avg) (d) (sm^3/d) (10^6 m^3) (%GIP) (bar) (bar)

Prod. Ratio V/Vbase

Average Pressure

Flowing Pressure

0

1 2

2 3Time Flow Rate Cum. Prod. Cum. Prod.

(J/Jo(t)) (J/Jo|avg) (d) (sm^3/d) (10^6 m^3) (%GIP) (bar)

Prod. Ratio Q/Qbase

Prod. Ratio V/Vbase

Average Pressure

0

2 3

3 4Time Flow Rate Cum. Prod. Cum. Prod.

(bar) (J/Jo(t)) (J/Jo|avg) (d) (sm^3/d) (10^6 m^3) (%GIP)

Flowing Pressure

Prod. Ratio Q/Qbase

Prod. Ratio V/Vbase

0

3 4

4 5Time Flow Rate Cum. Prod.

(bar) (bar) (J/Jo(t)) (J/Jo|avg) (d) (sm^3/d) (10^6 m^3)

Average Pressure

Flowing Pressure

Prod. Ratio Q/Qbase

Prod. Ratio V/Vbase

0

4 5

5 6Cum. Prod. Time Flow Rate

(%GIP) (bar) (bar) (J/Jo(t)) (J/Jo|avg) (d) (sm^3/d)

Average Pressure

Flowing Pressure

Prod. Ratio Q/Qbase

Prod. Ratio V/Vbase

5 6

6 7Cum. Prod. Cum. Prod. Time

(10^6 m^3) (%GIP) (bar) (bar) (J/Jo(t)) (J/Jo|avg) (d)

Average Pressure

Flowing Pressure

Prod. Ratio Q/Qbase

Prod. Ratio V/Vbase

0

6 7

7Flow Rate Cum. Prod. Cum. Prod.

(sm^3/d) (10^6 m^3) (%GIP) (bar) (bar) (J/Jo(t)) (J/Jo|avg)

Average Pressure

Flowing Pressure

Prod. Ratio Q/Qbase

Prod. Ratio V/Vbase

0

7

8Time Flow Rate Cum. Prod. Cum. Prod.

(d) (sm^3/d) (10^6 m^3) (%GIP) (bar) (bar) (J/Jo(t)) (J/Jo|avg)

Average Pressure

Flowing Pressure

Prod. Ratio Q/Qbase

Prod. Ratio V/Vbase

0

8

9Time Flow Rate Cum. Prod. Cum. Prod.

(d) (sm^3/d) (10^6 m^3) (%GIP) (bar) (bar) (J/Jo(t))

Average Pressure

Flowing Pressure

Prod. Ratio Q/Qbase

0

9

9 10Time Flow Rate Cum. Prod. Cum. Prod.

(J/Jo|avg) (d) (sm^3/d) (10^6 m^3) (%GIP) (bar) (bar)

Prod. Ratio V/Vbase

Average Pressure

Flowing Pressure

0

9 10

10 Choosen TonnesTime Flow Rate Cum. Prod. Cum. Prod.

(J/Jo(t)) (J/Jo|avg) (d) (sm^3/d) (10^6 m^3) (%GIP) (bar)

Prod. Ratio Q/Qbase

Prod. Ratio V/Vbase

Average Pressure

10 Choosen

Choosen Tonnes Net Cumulative ProductionCum. Prod.

(bar) (J/Jo(t)) (J/Jo|avg) (10^6 m^3)

00000000000000000000000000000000000000000

Flowing Pressure

Prod. Ratio Q/Qbase

Prod. Ratio V/Vbase

000000000000000000000000000000000000000000000

000000000000000000000000000000000000000000000

000000000000000000000000000000000000000000000

000000000000000000000

Choosen Net Choosen

Net Cumulative ProductionNet Cash Flow

€ Initial Investment for Tonne Frac

0 0.000 Input000000000000000000000000000000000000000

000000000000000000000000000000000000000000000

000000000000000000000000000000000000000000000

000000000000000000000000000000000000000000000

000000000000000000000

Net Choosen

RESERVOIR DATA:

FORMATION: 0

RESERVOIR FLUID: 0

BOTTOMHOLE TEMPERATURE: 0

RESERVOIR BOTTOMHOLE PRESSURE: 0

RESERVOIR DRAINAGE AREA 0.0

POROSITY: 0

PERMEABILITY: 0.000

WATER SATURATION: 0

GAS SPECIFIC GRAVITY 0.000

NET PAY THICKNESS: 0.0

PERFORATIONS: 0.0 - 0.00.0 - 0.00.0 - 0.00.0 - 0.0

TVD TOP PERFORATION: 0.0

OBJECTIVES:

1. Predict post fracture geometry in formation for well .

2. Determine optimum frac size using Net Present Value (NPV) analysis.

PROCEDURE:

1. Determine rock properties from customer supplied logs and information. Create model in Meyers Fracture Simulator.

2. Use Meyers Fracture Simulator (MFRAC) to predict fracture geometry.

3. Use Meyers Production Simulator (MPROD) to predict post fracture production.

4. Perform NPV analysis and report results.

ECONOMIC INPUTS:

Frac Fluid Unit Cost 0Proppant Unit Cost 0Fixed Equipment Cost 0Workover Cost 0Unit Revenue for Production Gas (Net) 0Revenue Escalation Rate 0Discount Rate 0Time Period 0

MISCELLANEOUS INPUTS:

Fluid System 0Gel Loading 0Proppant Type 0Proppant Size 0

FRAC COSTS:

Frac Size Fluid Volume Frac Cost Initial Investment(Tonne) (m³) (€) (€)

Scenario 1 0 0.0 0 0Scenario 2 0 0.0 0 0Scenario 3 0 0.0 0 0Scenario 4 0 0.0 0 0Scenario 5 0 0.0 0 0Scenario 6 0 0.0 0 0Scenario 7 0 0.0 0 0Scenario 8 0 0.0 0 0Scenario 9 0 0.0 0 0Scenario 10 0 0.0 0 0

FRAC GEOMETRY:

Propped Upper Lower Average Fcd EstimatedLength Propped Propped Propped (Dim. Net Cumulative

Height Height Width Frac Production(m) (m) (m) (mm) Cond.) (m³)

Scenario 1 0.0 0.0 0.0 0.0 0.0 0Scenario 2 0.0 0.0 0.0 0.0 0.0 0Scenario 3 0.0 0.0 0.0 0.0 0.0 0Scenario 4 0.0 0.0 0.0 0.0 0.0 0Scenario 5 0.0 0.0 0.0 0.0 0.0 0Scenario 6 0.0 0.0 0.0 0.0 0.0 0Scenario 7 0.0 0.0 0.0 0.0 0.0 0Scenario 8 0.0 0.0 0.0 0.0 0.0 0Scenario 9 0.0 0.0 0.0 0.0 0.0 0Scenario 10 0.0 0.0 0.0 0.0 0.0 0

0 2 4 6 8 10 120.00

2.00

4.00

6.00

8.00

10.00

12.00Initial Investmest vs. Frac Size

Frac Size (tonnes)

Init

ial

Inv

es

tme

st

(€)

0 2 4 6 8 10 120

2

4

6

8

10

12Propped Length vs. Frac Size

Frac Size (tonnes)

Pro

pp

ed

Le

ng

th (

m)

0 2 4 6 8 10 120

2

4

6

8

10

12Production Rate vs. Time

Base

T

T

T

T

T

T

T

T

T

TTime (days)

Flo

w R

ate

(m

³/d

ay

)

CONCLUSIONS:

Various sized fracture treatments were modeled in Meyers Fracture Simulator. In conjuctionwith Meyers Production Simulator, net present value analysis was performed for the formation at . Based on the year NPV the optimum treatment sizewould be in the tonne range. The initial investment is estimated to be recovered in days.

Reported by:0

0 2 4 6 8 10 120

2

4

6

8

10

12Net Present Value Tonnes

Time (days)

NP

V (

€)

0 2 4 6 8 10 120.00

2.00

4.00

6.00

8.00

10.00

12.00Net Present Value vs. Time

Frac Size (tonnes)

NP

V (

€)

? tonnes

0

0

0 °C

0 bar

0.0 ha

0 %

0.000 mD

0 %

0.000

0.0 m

0.0 - 0.0 m0.0 - 0.0 m0.0 - 0.0 m0.0 - 0.0 m

0.0 m

Determine rock properties from customer supplied logs and information. Create

Use Meyers Production Simulator (MPROD) to predict post fracture production.

0 €/m³0 €/kg0 €0 €0 €/m³0 %0 %0 years

00 kg/m³00 mesh

Initial Investment(€)0000000000

EstimatedNet Cumulative

Production(m³)

0000000000

0 2 4 6 8 10 120.00

2.00

4.00

6.00

8.00

10.00

12.00Initial Investmest vs. Frac Size

Frac Size (tonnes)

Init

ial

Inv

es

tme

st

(€)

0 2 4 6 8 10 120

2

4

6

8

10

12Propped Length vs. Frac Size

Frac Size (tonnes)

Pro

pp

ed

Le

ng

th (

m)

0 2 4 6 8 10 120

2

4

6

8

10

12Production Rate vs. Time

Base

T

T

T

T

T

T

T

T

T

TTime (days)

Flo

w R

ate

(m

³/d

ay

)

0

0 2 4 6 8 10 120

2

4

6

8

10

12Net Present Value Tonnes

Time (days)

NP

V (

€)

0 2 4 6 8 10 120.00

2.00

4.00

6.00

8.00

10.00

12.00Net Present Value vs. Time

Frac Size (tonnes)

NP

V (

€)

? tonnes