Carbon Dioxide Demonstration Project Supporting Research at KU

Jyun-Syung Tsau

presented for

Tertiary Oil Recovery Project

Advisory Board Meeting

October 19-20, 2001

Supporting Research Activities

• Simulation– Hall-Gurney field (LKC formation)– Bemis-Shutts field (Arbuckle formation)

• Laboratory experiments– Slim-tube displacement– Residual oil measurement

Simulation

• Reservoir simulator– VIP black oil simulator

• Primary production, waterflooding

– VIP compositional simulator• CO2 flooding

Compositional Simulator

• Equation of state (EOS) for CO2-oil phase behavior characterization and properties calculation

• Peng-Robinson 3-parameter EOS model

Typical Data Preparation for Compositional Simulation

• C7+ characterization (sub-grouping heavy end)

• Pseudoization (grouping)

• Phase behavior calculation (swelling test)

• Slim-tube displacement

Laboratory Displacement Data to Fine Tune Reservoir Simulator

• Slim-tube displacement experiment– Ideal porous media– Oil recovery attributed to phase behavior– MMP (minimum miscibility pressure)

indicates the pressure required to develop multiple-contact miscibility

– Fine tune EOS parameters in reservoir simulator

Schematic of Slim-tube Experiment ApparatusC

O2

sour

ce

Milton Roy pump

Effluent

N2 source

CO

2

Oil

T

TT

ISCO pump

ISCO pump

BPR

T

Oil Recovery Performance in Slim-tube Experiment(Letsch #7 oil)

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0.2

0.4

0.6

0.8

1

0.0 0.2 0.4 0.6 0.8 1.0 1.2CO2 injection (HCPV)

Oil

pro

du

ced

(H

CP

V)

1305 psia

1015 psia

Temp: 105 °F

MMP Measurements of Letsch #7 Oil

40

50

60

70

80

90

100

800 900 1000 1100 1200 1300 1400

Pressure (psia)

Rec

ove

ry (

%)

Recovery at 1.0 HCPV CO2 injection

Oil Recovery Performance Match

0

0.2

0.4

0.6

0.8

1

1.2

0.0 0.5 1.0 1.5 2.0

CO2 injection (HCPV)

Oil

pro

du

ced

(H

CP

V)

Experiment

Simulation_bip0.05

Simulation_bip0.0735

Pressure = 1305 psia

Determination of Residual Oil Saturation to Carbon Dioxide

Why it is important?

• Miscibility developed by multiple contact results in variable amount of oil left behind in CO2-swept zone

• Uncertainty in projection of oil recovery by the simulator

Critical Issues to the Measurements

• Measurement needs to account for

– Well defined development of miscibility

– Representative fluid and rock properties

Schematic of Residual Oil Saturation Measurement Apparatus

Characteristics of Slim-tube and Core Sample

Slim-tube Core sampleLength (inch) 459.48 1.9205

I.D. (inch) 0.2425 0.9845

Bulk volume (cc) 347.80 23.96

Pore volume (cc) 127.76 5.26

Porosity (%) 36.73 21.95

Permeability (md) 4900 453.73

Porous media Glass bead Berea sandstone

Future Tasks

• Investigate the effect of displacement rate, core length and structure on residual oil saturation determination

• Investigate the effect of water saturation on the residual oil saturation to CO2

Evaluation of Arbuckle Crude Oil for Oil Recovery by CO2 Displacement

• Conduct experiment to measure MMP of crude oil obtained from Arbuckle formation

• Perform simulation to match current field condition and test the reservoir response to pressurization process

MMP Measurements of Peavey #B1 Oil(Bemis-Shutts field)

40

50

60

70

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100

800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800

Pressure (psia)

Oil

reco

very

(%

OO

IP)

Temp: 108 °F

Current Reservoir Condition

• Average reservoir pressure is around 500 psia, which is not high enough for CO2 miscible displacement

• Reservoir must be pressurized

Approaches

• Construct a generic model to simulate the process of– Primary production– Pressurization

• Model contains– 126 active production wells in a 2 by 2

square miles area (2560 acres)

Grid Cell System Used in the Model

Cross Section of the Reservoir Formation

• 11 layers with permeability ranging between 0.2 ~5 md in aquitard and 50 ~1500 md in production zones

86 ft

2 miles

aqui

feraquitard

3486'

3400'

Satisfactory Match

• Simulation results were to match– Reservoir average pressure– Cumulative oil and water production– Current oil and water production rate

Observations

• Reservoir is a layered reservoir with high permeability contrast between layers

• Bottom water drive

Edge water drive does not provide enough energy to support the average reservoir pressure and production performance

Pressure Distribution at the End of Primary Production (Beginning of Pressurization)

Simulation Tests to Pressurize a Project Area

• 5 spot pattern (10 acres) with 6 confining injectors (within 120 acres)

Well Condition Parameters During the Pressurization

• Injector– 5-spot: BHP: 2000 psia, Qmax: 3000 bbl/day– Confining area: BHP: 2000 psia, Qmax: 3000

bbl/day

• Producer– 5-spot: shut-in– Around confining area: BHP: 1100 psia, Qmax:

300 bbl/day– Other active producers : BHP: 300 psia, Qmax:

300 bbl/day

Pressure Distribution After 3-year’s Pressurization

Summary of Pressurization Process

• The magnitude of pressure increase within a pattern depends on the size of the pattern, confining area, and bottom hole pressure control of injectors and producers.

• The ultimate pressures within the pattern varied from 1200 psia to 1500 psia.

Preliminary Results

• Attainable reservoir pressure might slightly below the MMP as required for a miscible CO2 displacement

• Oil recovery remains relatively high (70 ~85%) for a few hundred psi below MMP

Current Status

• Oil and gas samples collected from the wellhead and separator were analyzed by Core-Lab

• High nitrogen content was found on some of the separator samples through the quality check, which suggests the needs to measure MMP and oil recovery using a live oil sample

• Detailed PVT test and swelling test would be conducted by Core-Lab, and data would be used for compositional simulation