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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