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


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


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


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%


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

0

10

20

30

40

50

60

70

80

90

100

0

1,000,000

2,000,000

3,000,000

4,000,000

5,000,000

6,000,000

7,000,000

8,000,000

9,000,000

10,000,000

20

10

Wat

er

Cu

t, %

20

10

Cu

mu

lati

ve O

il P

rod

uct

ion

, bb

l 2010 Oil Production and Water Cut by Formation

Oil Production Water Cut


0

10

20

30

40

50

60

70

0 2000 4000 6000 8000 10000 12000 14000 16000

Oil

AP

I Gra

vity

Reservoir Depth, ft

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

Likely Candidates for Miscible CO2 Flooding


CO2-EOR Candidate Reservoirs by Basins


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


Oil Gravity vs. EOR Methods

0 10 20 30 40 50 60

Oil Gravity oAPI

N2 & Flue Gas

Hydrocarbon

CO2 - Miscible

Immiscible Gas (CO2)

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)


• 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


• 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


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


Peigui Yin

Nick Jones

Matthew Johnson

Scott Cooper (consultant)

John Lorenz (consultant)

Gene George (consultant)

Reservoir Characterization & Modeling Team


Shaochang Wo

Reza Barati

Shuiquan Li

Mao Velasquez

Reservoir Modeling & Simulation Team

IT Support Team

Allen Tanner

Jeffrey Lang


• 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


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


Tensleep and Minnelusa Sandstones

(Figure from Peigui Yin of EORI)


Aquifer Influx and Fracture Effects on Tensleep Reservoirs


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

0.0001

0.001

0.01

0.1

1

10

100

1000

10000

0.000001 0.00001 0.0001 0.001 0.01 0.1 1

Frac

ture

Per

mea

bili

ty, D

arcy

Fracture Porosity, fraction

Fracture Permeability as a Function of Fracture Porosity and Width

Kf = ɸf 𝑒2/12

e = 10 micron

50 micron

100 micron

200 micron

1 mm

700 micron

500 micron

300 micron


Evaluation of IOR/EOR Options for Minnelusa Reservoirs


Correlations between Core Permeability and Porosity by Sand Units


Initial Oil Saturation

Current Oil Saturation after History Matching


• 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


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


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


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


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 0

5,000,000

10,000,000

15,000,000

20,000,000

25,000,000

0 50 100 150 200 250 300 350 400

Time, month

Fie

ld C

um

. O

il P

rod

ucti

on

, S

TB

O

Scenario 1 Scenario 2 Scenario 3

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


Scenario 3 Ternary View before CO2 injection

Ternary View after 4-year CO2 injection


Ternary View before CO2 injection

Ternary View after 30-year CO2 injection

Scenario 3


Scenario 3:

End of 30-year CO2 flooding

Gas Saturation

CO2 Fraction


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


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





Total CO2 injected, bscf 37.5 164.1 322.7


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



Targeted Oil in Place, MMSTBO 37 37 37

Repressurization Phase





Total CO2 injected, bscf 109.5 110.4 90


CO2 injection duration, years 6 2.75 2.25

Production Phase





Total CO2 injected, bscf 125 421.1 772.4


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


Thank You!

reservoir modeling & simulation at eori · pdf filereservoir modeling & simulation at...

Documents