Reservoir Modeling & Simulation at EORI · PDF fileReservoir Modeling & Simulation at...

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

Reservoir Modeling & Simulation at EORI Shaochang Wo

Jackson, Wyoming September 12-13, 2011

The 3rd Wyoming IOR/EOR Conference

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

Outline

• EOR potential in Wyoming

• Typical questions from Wyoming producers

• How we evaluate IOR/EOR options

• Reservoir modeling & simulation team at EORI

• Computer hardware and software capability

• Case study examples

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

Wyoming Oil & Gas Fields

Powder River Basin

Greater Green River Basin

Bighorn Basin

Wind River Basin

Overthrust Belt

Hanna Basin

Laramie Basin

Jackson Hole

Denver Basin

Shirley Basin

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

Wyoming Oil Producing Fields

• By the end of 2010, 7232 million barrels of oil (MMBO) have been produced from 1237 oil producing fields

• Top 400 fields with cumulative production of one MMBO or more

• Top 400 fields account for ~98% of the total produced oil

• In 2010, the average water cut from Wyoming oil producing fields is 97.6%

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

2010 Average Water Cut from Wyoming Oil Producing Reservoirs is 97.6%

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Oil Production Water Cut

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Oil API Gravity vs. Reservoir Depth (from 853 Wyoming Oil Samples)

Likely Candidates for Miscible CO2 Flooding

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

CO2-EOR Candidate Reservoirs by Basins

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

CO2 EOR Potential in Bighorn Basin

• 63 reservoirs pass the screening criteria for miscible CO2 flood

• 42 reservoirs are identified as potential candidates for immiscible CO2 flood

• CO2 EOR could recover 500 to 800 million barrels of additional oil from historically produced oil reservoirs

• It is estimated that between 800 and 1,200 million barrels of oil in the thick transition-residual oil zones of the Tensleep reservoirs in the basin could also be recovered by using CO2 EOR

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

Oil Gravity vs. EOR Methods

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Alkaline/Surfactant/Polymer

Polymer Flooding

Gel Treatments

In situ Combustion

Steam Flooding

Mining

(Modified from J.J. Taber, F.D. Martin & R.S. Seright, 1997)

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

• What is the best IOR/EOR option for our field?

• What is the CO2 EOR potential of the reservoir?

• What is the ASP flooding (or chemical flooding in general) potential of the reservoir?

• Where will be the best locations for infill drilling?

• How do we rework the production/injection patterns to offset the fracture effect?

• Can you estimate the aquifer influx, from where and how much, in the reservoir?

• Where is the remaining oil?

Typical Questions from Wyoming Producers

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

• Screening

– A first-pass assessment based on given screening criteria and reservoir parameters from EORI database

• Scoping (e.g. Kinder Morgan Model of CO2 flood)

– Based on dimensionless curves to estimate incremental oil

– Including profitability estimation

• Simulation

– Full field or sector models simulated by using Eclipse or CMG simulators

– Usually requires a time frame of 6~18 months

Evaluation of IOR/EOR Options

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

Typical Workflow in Reservoir Modeling & Simulation

Geologic Model (Petrel)

Simulation Model (Eclipse, CMG)

History Matching

Evaluation of EOR/IOR Floods

Description of Reservoir Structure & Faults Rock Facies & Flow Units Fracture Network & Connection

Well Logs Well Completions Core ɸ, K, Sw, So Seismic Survey

3D Grid System ɸ & K of Grids Initial So, Sg, Sw

Remaining oil Distribution in Reservoir

Reports & Recommendations

Operator Requests

Laboratory Data Fluid & Rock Properties: PVT, Kro, Krw, Krg, …

Production & Injection History

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

Peigui Yin

Nick Jones

Matthew Johnson

Scott Cooper (consultant)

John Lorenz (consultant)

Gene George (consultant)

Reservoir Characterization & Modeling Team

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

Shaochang Wo

Reza Barati

Shuiquan Li

Mao Velasquez

Reservoir Modeling & Simulation Team

IT Support Team

Allen Tanner

Jeffrey Lang

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

• Computers – 4 high-performance PC work stations

– One 15-node HP cluster

– A new cluster will be purchased in 2011 (funded by the School of Energy Resources)

• Petrel package (Schlumberger) for building static reservoir models

• Eclipse simulation package with parallel option (Schlumberger donation)

• CMG simulation package (donation of the Computer Modelling Group Ltd)

Computer Hardware and Software

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

Simulation Models for EOR

• Black-Oil Model

– Pressure Depletion, Water flooding, Solution-Gas injection, Polymer Flooding

• Compositional Model

– Miscible/Immiscible Gas (CO2) Injection

• Thermal Model

– Steam Flooding, In-situ Combustion

• Chemical-Flooding Model

– Alkaline, Surfactant, Polymer Flooding

– Mostly Research Models

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

Tensleep and Minnelusa Sandstones

(Figure from Peigui Yin of EORI)

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

Aquifer Influx and Fracture Effects on Tensleep Reservoirs

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

Dual Porosity/Permeability Models Are

Needed for Most Tensleep Reservoirs

• Single porosity model (SPM) is unable to accommodate the difference of multi-phase flow in matrix and fracture

• Difficult for SPM to match the early breakthrough of injected water or aquifer water influx via fracture networks

• Difficult for SPM to model wellbore connections with open fracture conduits

• SPM is unable to simulate Imbibition-dominated matrix-fracture fluid transfer

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E 0.00001

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Fracture Permeability as a Function of Fracture Porosity and Width

Kf = ɸf 𝑒2/12

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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

Evaluation of IOR/EOR Options for Minnelusa Reservoirs

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

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Correlations between Core Permeability and Porosity by Sand Units

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

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E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

Initial Oil Saturation

Current Oil Saturation after History Matching

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

• Case 1 (base case): 40-year production under current production-injection scheme

• Case 2: drill a vertical production well

• Case 3: drill a horizontal production well

• Case 4: increase injection volume

• Case 5: reactivate WX #3

• Case 6A: convert CX #1, CX #4 and WX #1 to injectors

• Case 6B: Case 6A + converting CX #3R

• Case 7A: drill a new injector

• Case 7B: Case 7A + converting CX #3R, CX #4 and WX #1

Simulation Evaluation of Nine Development Scenarios

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

Simulation Forecasting: Field Daily Oil Prod. Rates under Different Development Scenarios

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

Simulation Forecasting: Field Cum. Oil Productions under Different Development Scenarios

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

Summary of simulation forecasting. The best case in each category is highlighted in green.

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

Simulation Evaluation of Gravity-Stable CO2 Flooding in the Muddy Reservoir at Grieve Field, Wyoming

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

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Scenario 1 Low-volume CO2 injection

Grieve Field: Simulated Gravity-Stable CO2 Injection

Scenario 2 Medium-volume CO2 injection

Scenario 3 High-volume CO2 injection

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

Scenario 3 Ternary View before CO2 injection

Ternary View after 4-year CO2 injection

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

Ternary View before CO2 injection

Ternary View after 30-year CO2 injection

Scenario 3

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

Scenario 3:

End of 30-year CO2 flooding

Gas Saturation

CO2 Fraction

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

Grieve Field: Summary of simulated scenarios under 14-year CO2 injection

Scenario 1 Scenario 2 Scenario 3

Targeted Oil in Place, MMSTBO 37 37 37

Repressurization Phase

CO2 injection wells 10 10 10

Per-well CO2 injection rate, mscf/day 5,000 11,000 11,000

Total CO2 injection rate, mscf/day 50,000 110,000 110,000

CO2 volume factor, rb/mscf 0.42 - 0.54 0.42 - 0.54 0.42 - 0.54

Total CO2 injected, bscf 109.5 110.4 90

Injected CO2 slug size, PORV 0.35 0.35 0.29

CO2 injection duration, years 6 2.75 2.25

Production Phase

CO2 injection wells 3 4 7

Per-well CO2 injection rate, mscf/day 5,000 11,000 11,000

Total CO2 injection rate, mscf/day 15,000 44,000 77,000

CO2 volume factor, rb/mscf 0.42 - 0.54 0.42 - 0.54 0.42 - 0.54

Total CO2 injected, bscf 37.5 164.1 322.7

Injected CO2 slug size, PORV 0.12 0.52 1.03

Production wells 10 14 16

Total oil produced, mmbo 15.15 20 21.4

Maximum daily oil rate, stbo/day 8,300 12,380 13,600

Total gas produced (including CO2), bscf 37.3 149.4 279.7

Maximum daily gas rate, mscf/day 40,000 109,000 170,000

Total water produced, mmbw 12.9 16.4 18.2

Maximum daily water rate, bw/day 11,600 14,500 16,800

Injection/production duration, years 8 11.25 11.75

Overall CO2 Usage of Both Phases

CO2 injected, bscf 147 274.5 412.7

CO2 produced & reinjected, bscf 28.1 128.5 251.7

CO2 purchased, bscf 118.9 146 161

Net CO2 utility, mscf/bo 7.84 7.3 7.5

Overall Operation Duration, years 14 14 14

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

Scenario 1 Scenario 2 Scenario 3

Targeted Oil in Place, MMSTBO 37 37 37

Repressurization Phase

CO2 injection wells 10 10 10

Per-well CO2 injection rate, mscf/day 5,000 11,000 11,000

Total CO2 injection rate, mscf/day 50,000 110,000 110,000

CO2 volume factor, rb/mscf 0.42 - 0.54 0.42 - 0.54 0.42 - 0.54

Total CO2 injected, bscf 109.5 110.4 90

Injected CO2 slug size, PORV 0.35 0.35 0.29

CO2 injection duration, years 6 2.75 2.25

Production Phase

CO2 injection wells 3 4 7

Per-well CO2 injection rate, mscf/day 5,000 11,000 11,000

Total CO2 injection rate, mscf/day 15,000 44,000 77,000

CO2 volume factor, rb/mscf 0.42 - 0.54 0.42 - 0.54 0.42 - 0.54

Total CO2 injected, bscf 125 421.1 772.4

Injected CO2 slug size, PORV 0.4 1.35 2.47

Production wells 10 14 16

Total oil produced, mmbo 19.8 22.2 23.2

Maximum daily oil rate, stbo/day 8,300 12,380 13,600

Total gas produced (including CO2), bscf 107.7 392.5 717.2

Maximum daily gas rate, mscf/day 40,000 109,000 170,000

Total water produced, mmbw 19.2 22.1 23.2

Maximum daily water rate, bw/day 11,600 14,500 16,800

Injection/production duration, years 24 27.25 27.75

Overall CO2 Usage of Both Phases

CO2 injected, bscf 234.5 531.5 862.4

CO2 produced & reinjected, bscf 89 360.8 674.5

CO2 purchased, bscf 145.5 170.7 187.9

Net CO2 utility, mscf/bo 7.35 7.69 8.1

Overall Operation Duration, years 30 30 30

Grieve Field: Summary of simulated scenarios under 30-year CO2 injection

E N H A N C E D O I L R E C O V E R Y I N S T I T U T E

Thank You!