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EOR Study for Permian Basin

Wei Long, Ph.D.

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Permian Basin

• Permian basin located in the west

Texas and southeast New Mexico.

• Estimated OOIP for Permian Basin

was ~106 Bbbl, 29 Bbbl has been

produced today from 1339 reservoirs,

with ~73% OOIP left behind, including

31 Bbbl mobile oil and 46 Bbbl

residual oil.

• The Permian Basin produced 17% of

the total US oil production, and it

contains an estimated 22% of the

proved oil reserves in the US.

• A reservoir database was established

by Railroad Commission of Texas

(RRC) with reservoir number and

district, production, etc. for Texas.

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Outline

Introduction

• Reservoir management for CO2 flooding

− Impact of heterogeneity, WAG ratio, CO2 slug size, and Oil gravity

• Reservoir management for surfactant

− Well stimulation and surfactant flooding

• Reservoir management for mobility control

− CO2 foam flooding

• Managing uncertainty

• Summary

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Reservoir model

• Geological data:

• Reservoir depth at -5500 ft

• Reservoir thickness from 40 ft

to 100 ft

• Averaging porosity = 0.12

• Averaging permeability, k =

150 md

• Wettability: oil wet to

intermediate wet

• Simulation data:

• Reservoir size: 1000 ft x 1000

ft x 100 ft

• Grid size: 10 x 10 x 10

• Well Data: • One producer and one injector with well distance around 1400 ft (5 spot 40 acres)

• Injector is controlled by surface rate with 500 stb/d of water or 1500 Mscf/d of CO2

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Reservoir heterogeneity

• Rock types: − Rock type 1: = 0.03, k = 9.4 mD, Sor = 0.35, Siw = 0.35

− Rock type 2: = 0.12, k = 150 mD, Sor = 0.2, Siw = 0.3

− Rock type 3: = 0.21, k = 459 mD, Sor = 0.15, Siw = 0.25

• Two reservoir heterogeneity are studied:

where 𝑣𝑑𝑝 =𝑘50 − 𝑘84.1

𝑘50

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PVT data

𝑀𝑀𝑃 = 15.998 × 𝑇 0.744206+0.0011038×𝑀𝑊 𝐶5+

• Cronquist correlation is employed to determine the minimum

miscible pressure where

and MMP = 1744 psi < Pinit = 3000 psi

• Averaging MW = 153, and MW C5+ = 128. According to the DOE

report for Permian basin:

API = 56, very light oil.

𝑀𝑊 𝐶5+ = 4247.99𝐴𝑃𝐼−0.87022

Elevation [ft] CO2 C1N2 C2C3 C4C5 C6P1 C6P2 C6P3

-5450 0.004 0.313 0.181 0.080 0.132 0.137 0.153

Elevation [ft] CO2 C1N2 C2C3 C4C5 C6P1 C6P2 C6P3

-5450 0.004 0.213 0.181 0.080 0.132 0.137 0.253

• MMP = 2311 psi < Pinit = 3000 psi

• Averaging MW = 197, MW C5+ = 176, and API = 39.

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Outline

• Introduction

Reservoir management for CO2 flooding







• Summary

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Sensitivity study - pressure impact on oil recovery

MMP MMP

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Sensitivity study - slug size impacts

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Reservoir management for CO2 flooding

• Reservoir management studies were performed to

investigate the sensitivity of API gravity, WAG ratio, Slug

size, and Vdp on the oil recovery to maximize the

recovery factor and net present value (NPV).

Factors: Scenario I Scenario II

API 56 39

WAG Ratio 0.69 3.44

Slug Size, % HCPV 0.4 2

Vdp, Dykstra-Parsons Coefficient 0.57 0.76

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Comparison between water and WAG flooding for API = 39

𝑣𝑑𝑝 = 0.57 𝑣𝑑𝑝 = 0.76

• More heterogeneous reservoir provides less benefits for CO2

flooding comparing to water flooding.

API = 39

WAG

Water

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Comparison between water and WAG flooding for 𝑣𝑑𝑝 = 0.57

API = 56 API = 39

• Lower API oil provides less benefits for CO2 flooding

comparing to high API gravity. 𝒗𝒅𝒑 = 𝟎. 𝟓𝟕

WAG

Water

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Impact of various reservoir management on oil recovery

API = 56

API = 39

Vdp = 0.57 Vdp = 0.76

Improved Recovery Improved Recovery

2 year CO2+1 year Water 13.31% 5.74%




Vdp = 0.57 Vdp = 0.76

Improved Recovery Improved Recovery





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Reservoir economics

API = 56

API = 39

Value

Oil price $80 /bbl

Oil price

increase

10%

Royalty 12.5%

Discount

rate

15%

CO2 price $1 / Mscf

OPEX $1 /bbl

Federal tax

rate

32%

Vdp = 0.57 Vdp = 0.76

NPV [MM$] Improved [%] NPV [MM$] Improved [%]

Water only $26.41 - $23.72 -

2 year CO2+1 year Water $29.05 10.00% $23.51 -0.87%

10 year CO2+5 year Water $30.24 14.53% $24.11 1.66%



Vdp = 0.57 Vdp = 0.76


Water only $29.66 - $26.63 -





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Reservoir economics

API = 56

API = 39

Value

Oil price $80 /bbl

Oil price

increase

10%

Royalty 12.5%

Discount

rate

15%

CO2 price $2 / Mscf

OPEX $1 /bbl

Federal tax

rate

32%

Vdp = 0.57 Vdp = 0.76


Water only $26.41 - $23.72 -





Vdp = 0.57 Vdp = 0.76


Water only $29.66 - $26.63 -

2 year CO2+1 year Water $29.13 -1.78% $23.72 -10.92%




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Summary

• Several factors needs to be assessed for CO2 flooding:

− Is CO2 source/pipeline available, and what is the corresponding

MMP pressure

− Is the MMP sufficiently below overburden pressure/FPP, can the

high injectivity be achieved to maintain the pressure

− Is the CO2 flood economic with or without reaching the MMP

− How much CO2 needs to be purchased and how much can be

recycled

− Numerical simulations can give a guidance for CAPEX & OPEX,

and identify the optimal slug size and best WAG ratio

− Surveillance practice to achieve the optimal performance is

necessary, no matter whether constant WAG ratio taped to high

ratio towards the end of the project, or monthly adjustment WAG

ratios based on the observed performance

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Outline

• Introduction



Reservoir management for surfactant





• Summary

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0

200

400

600

800

1000

1200

1400

1600

0

200

400

600

800

1000

1200

Pipeline PSI MCF/D CO2 Injection

West TX Field

Inj RateCO2

0.4% CnF Injection

7-23 thru 7-25

Injectivity enhancement – well stimulation

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Well stimulation and production enhancement

CnF Injection

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Surfactant mechanisms

𝑆𝑖𝑟 = 0 𝑊ℎ𝑒𝑛 𝛿 < 0.005 𝑚𝑁/𝑚

𝑆𝑖𝑟 = 0.3 ∗ 1 + log 𝛿 2.3 𝑊ℎ𝑒𝑛 0.005 𝑚𝑁/𝑚 < 𝛿 < 1 𝑚𝑁/𝑚 𝑆𝑖𝑟 = 0.3 𝑊ℎ𝑒𝑛 𝛿 > 1 𝑚𝑁/𝑚

𝑁𝑖 = 1.0 𝛿 < 0.005 𝑚𝑁/𝑚

𝑁𝑖 = 1.5 + log 𝛿 6 0.005 𝑚𝑁/𝑚 < 𝛿 < 1 𝑚𝑁/𝑚 𝑁𝑖 = 1.5 𝛿 > 1 𝑚𝑁/𝑚

• The residual oil saturation, water saturation and relative permeability will

change (Pope & Nelson, 1978) for Corey correlation:

𝑞𝑠𝑢𝑟 = 𝑞𝑚𝑎𝑥

𝑏 ∗ 𝐶𝑠𝑢𝑟1 + 𝑏 ∗ 𝐶𝑠𝑢𝑟

• Langmuir-type adsorption model is considered:

CMC = 2 g/L (0.2%)

• Questions:

− What is the surfactant concentration that we should inject?

− How long do we need to inject?

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Impact of surfactant concentration on NPV

API = 56 API = 39

Surfactant price of $4/lb is used in the economic evaluation

CMC CMC

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Impact of surfactant injection time

API = 56 API = 39

3 g/L surfactant concentration with a price of $4 /lb

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Economic analysis for surfactant flooding

API = 56

API = 39

3 g/L concentration, 5 years surfactant injection, and $4 /lb were used

Vdp = 0.57 Vdp = 0.76

NPV [MM$] Improve% by WAG NPV [MM$] Improve% by WAG


10 year CO2+5 year Water $30.23 -2.55% $25.75 2.72%



Vdp = 0.57 Vdp = 0.76

NPV [MM$] Improve% by WAG NPV [MM$] Improve% by WAG


10 year CO2+5 year Water $28.83 -1.20% $23.48 1.88%



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Outline

• Introduction





Reservoir management for mobility control



• Summary

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Overview of polymer flooding

• Polymer flooding is commonly used in the oil fields for mobility

control. A favorable mobility, M<1, is preferred especially for a very

heterogeneous reservoir to avoid early water/CO2 breakthrough

• The polymer flooding is limited by:

− Low water injectivity (WI)

− Stability issues

− Only limited to reservoir rock above 5 mD because polymer molecules

are large enough to plug the small pore throats

• In the simulation model, Langmuir adsorption model is used, and

the relative permeability change is not considered

𝑀 =𝑘𝑤/𝜇𝑤𝑘𝑜/𝜇𝑜

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CO2 foam

Viscosity

factor

Foam concentration [ppm]

500 1000 1500 2000 2500 3000

Rock 1

(9.4 mD)

1.2 1.4 1.8 2 2.5 3

Rock 2

(150 mD)

1.5 2.5 4 6 8.5 10

Rock 3

(459 mD)

2 5 10 20 30 45

• Studies show that different from the polymer, mobility reduction by

CO2 foam depends on permeability and oil saturation. At the low

permeability zone where the oil left behind, the mobility reduction is

decreased

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Reservoir management for CO2 foam

Impact of injected foam

concentration

Impact of injected foam time

API = 39, Vdp = 0.76, 2 years CO2 + 5 years water w/Foam

Foam price of $2 /lb is used in the economic analysis

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Managing uncertainty

• Technical factors/uncertainties, such as geological

uncertainty, reservoir pressure & temperature, and

salinity, will have a great impact on the actual enhanced

oil recovery

• Economical uncertainties such as the oil price, CO2

price, surfactant & polymer price, etc. will have a great

impact to identify the EOR opportunity and the economic

evaluation

• How to identify these uncertainties and how confident

are we for the improved oil recovery and economic

analysis for EOR flooding

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Uncertainty for oil recovery

API = 39, Vdp=0.76, 2 years CO2 + 5 years SP injection

• Technical factors/uncertainties, such

as the reservoir pressure,

temperature, and salinity, will have

a great impact on the enhanced oil

recovery

• Economical factors such as the oil

price, SP price, discount rate, etc.

will have a great impact on the

economic evaluation

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Managing uncertainty

Improvement [%] P10 50.20%

P50 32.51%

P90 13.96%

API = 39, Vdp=0.76, 2 years CO2 + 5 years SP injection

• How to identify the uncertainty and how confident are we for the

NPV and improved recovery by SP flooding?

NPV [MM $] P10 33.40

P50 27.69

P90 23.10

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High level questions for EOR

• What is the current oil saturation?

− If the residual oil saturation of the current flooding zone is very high, then

using CO2 or surfactant is recommended

• What is the reservoir description such as heterogeneity and

porosity/permeability?

− An early CO2/WAG breakthrough indicates a very heterogeneous

reservoir and mobility control (either CO2 foam or polymer) is highly

recommended to improve the sweep efficiency; if the permeability is very

small then the use of polymer needs to be cautious

• What is the oil API gravity or viscosity?

− “CO2 flooding becomes very inefficient if the oil viscosity increases

above 10 cp; SP/ASP becomes less efficient above 200 cp; polymer

flooding has been used up to 1000 cp”

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Thank you

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Comparison of breakthrough between CO2 and water flooding

• The more heterogeneous of the reservoir, the earlier breakthrough

of the CO2 than water, and the less benefits of CO2 flood.

API = 56 API = 39

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When do we expect a positive cash flow?

0.4 HCPV (2 years) CO2 injection

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Guidance for Rel Perm with surfactant

𝑆𝑖𝑟 = 0 𝑊ℎ𝑒𝑛 𝛿 < 0.005 𝑚𝑁/𝑚

𝑆𝑖𝑟 = 0.3 ∗ 1 + log 𝛿 2.3 𝑊ℎ𝑒𝑛 0.005 𝑚𝑁/𝑚 < 𝛿 < 1 𝑚𝑁/𝑚 𝑆𝑖𝑟 = 0.3 𝑊ℎ𝑒𝑛 𝛿 > 1 𝑚𝑁/𝑚

𝑆𝑤𝑛 = 𝑆𝑤 − 𝑆𝑖𝑤

1 − 𝑆𝑖𝑤 − 𝑆𝑜𝑤

𝑘𝑟𝑤 = 𝑘𝑟𝑤𝑜 𝑆𝑤𝑛

𝑁𝑤

𝑘𝑟𝑜 = 𝑘𝑟𝑜𝑜 1 − 𝑆𝑤𝑛

𝑁𝑜

𝑘𝑟𝑖𝑜 = 𝑘𝑟𝑖

𝑜 + 1 − 𝑘𝑟𝑖𝑜 0.3 − 𝑆𝑖𝑟 /0.3

𝑁𝑖 = 1.0 𝑊ℎ𝑒𝑛 𝛿 < 0.005 𝑚𝑁/𝑚

𝑁𝑖 = 1.5 + log 𝛿 6 𝑊ℎ𝑒𝑛 0.005 𝑚𝑁/𝑚 < 𝛿 < 1 𝑚𝑁/𝑚 𝑁𝑖 = 1.5 𝑊ℎ𝑒𝑛 𝛿 > 1 𝑚𝑁/𝑚

• According to Pope & Nelson (1978), the residual oil saturation, water

saturation and relative permeability will change when the interfacial tension

is lowered:

where the exponents of Corey

correlation can be calculated:

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Adsorption model for surfactant

𝑞𝑠𝑢𝑟 = 𝑞𝑚𝑎𝑥

𝑏 ∗ 𝐶𝑠𝑢𝑟1 + 𝑏 ∗ 𝐶𝑠𝑢𝑟

• Langmuir-type adsorption model is considered:

q is the adsorption, Csur is the surfactant concentration in water,

and b is the initial slope of the isotherm.

qmax is salinity dependent where:

𝑞𝑚𝑎𝑥 = 𝑞𝑚𝑎𝑥0 + 𝑎 ∗ 𝐶𝑠𝑎𝑙

• Our study used: qmax0 = 200 µg/g, a = 1.0e-5, b = 0.1

• Critical miscible concentration, CMC = 2 g/L (0.2%)

• Questions:

− What surfactant concentration should we inject?

− How long do we need to inject?

− What’s the economic benefit of surfactant flooding?

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Economics for CO2 foam flooding

API = 39, Vdp = 0.76, 2 years CO2 + 5 years water w/Foam, Foam price of $2 /lb

NPV Improvement Oil Recovery Improvement

[MM$] [%] [%] [%]

2 year CO2+1 year Water $25.49 7.61% 63.51% 13.82%




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