BakerHughes Feasibility of CO2 Floding

Feasibility of CO2

Flooding Higher Viscosity Oils, Field Results, and Screening

Presented by:Richard Baker,December 7, 2012

Steve’s Challenge; Population of CO2 Flooded Oils: Gravities and Viscosities

San Andres CO2 Flood Oil Viscosities*

0

2

4

6

8

10

12

0‐0.5 0.5‐1.0 1.0‐1.5 1.5‐2.0 2.0‐2.5 2.5‐3.0 3.0‐3.5 3.5‐4.0 >4 but<10

>10

Oil Viscosity ‐ Degrees API

No. of CO2 Floods

* OGJ Production Volume, Apr 2, 2012

Means Reservoir Oil ‐ 6 cp

U.S. and San Andres CO2 Flood Oil Gravities*

0

5

10

15

20

25

30

<28 28‐30 30‐32 32‐34 34‐36 36‐38 38‐40 40‐42 42‐44 >44

Oil Gravities ‐ Degrees API

No. of CO2 Floods

San Andres (PB)

All US

* OGJ Production Volume, Apr 2, 2012

Means

Eastern Mississippi

Floods

Cdn

Immiscible CO2

CdnImmiscible CO2

Organization of Immiscible CO2 Talk

•Executive Summary•Summary of Field experience in immiscible floods

√

California (Wilmington)

–

Arkansas (Lick Creek)–

Trinidad

–

Malaysia–

Turkey

√

Canada (Retlaw)

•Screening Criteria

Executive Summary

Limited immiscible pilots in literature show the promise immiscible CO2

floodingLaboratory work seems to show promise of improved recovery

(∆RF=6-15%OOIP)Review of Old CO2

Pilot Project in Canada shows good responseRough simulation @μoil

= 30cP (∆RFCO2-wtrfld

=7%OOIP)@μoil


=16%OOIP)@μoil


~+20%OOIP)

Criteria;

Oil saturation SO current

>50%

Successful waterflood; volumetric sweep Evol

>50%

Biggest hurdle; Inexpensive CO2

corrosion hurdle existing pipe systems +CTP

API gravity 15-25API Insitu viscosity= 10- 1000cP

Why Medium Grade Oil Pools? 20-25 API, oil viscosity 10-1000cP, CRF>20%

√

In excellent quality reservoirs, predictable and well understood water flood development

√

High permeability and porosity√

High oil saturation

√

Thin (3-5m), but good continuity

Map of Alberta Pools 20 -25 API

As well as Sask. side

~8 Bbbl

USA Target

©

2009 Baker Hughes Incorporated. All Rights Reserved.7

Heavy oil fields

OLD IMMISCIBLE CO2 PILOTS

©


Summary of Field Experience in Immiscible Floods

Wilmington Calif. USALick Creek Arkansas USATrinidadMalaysia

CO2

Recovery of Heavy Oil: Wilmington Field Test

Saner, W.B., Patton, J.T., “CO2

recovery of Heavy Oil: Wilmington Field Test”, SPE paper 12082, JPT , July 1986

CO2




CO2




CO2


Saner, W.B., Patton, J.T., “CO2 recovery of Heavy Oil: Wilmington Field Test”, SPE paper 12082, JPT , July 1986

14 API oil after waterflood

Five fold increase in oil rateDecrease in watercut

Wilmington Field

•“Actually, CO2

displacement of viscous crude is not as efficient as the miscible displacement lighter crude.”

• “ However, the difference in efficiency is more than offset by the generous oil saturation present at the end of waterflooding in reservoirs that contain viscous crudes.”

Saner, W.B., Patton, J.T., “CO2 recovery of Heavy Oil: Wilmington Field Test”, SPE paper 12082, JPT , July 1986

CANADIAN IMMISCIBLE FLOOD

Retlaw

Mannville

V

©


Mannville

Retlaw

V –

map view

Oil viscosity @ initial reservoir conditions –

30cpCO2 allocation to HC gas injected is at an average of 0.5 (ranges from 0.4-0.6)

1 mile

Summary Data for Retlaw

Mannville

V Oil PoolPay Thickness 5.03 ft

Porosity 18.9%

Water Saturation 28.4%

Bo 1.12

Initial Pressure 1743 psia

~Psat=MMP

Fm Temperature 89.6 F

API Gravity 18.1 API

OOIP 12 MMBbl

OOIP Remaining 71%

Number of wells 47

μoil

= 30 cP

CO2 & Gas Injection Rate, Oil Production Rate vs

Time

1000 Stk

bbl O/ d10 MMcf/d

Water Rate Injected, Gas Rate and CO2 Rate Injected vs

Time

Start, middle and late time CO2

injection.

6 mmcf/d

Retlaw

Mannville

V background

•

Current RF = 29%•

47 wells in total, 33 Oil producers, 13 injection wells (6 CO2

injectors)

•

1st

cycle of CO2 injection began October 1983 and concluded on April 1989.

•

2nd

cycle of CO2 injection began on January 1991 and concluded on April 1996.

•

Water injection began on May 1987

Recovery Factor vs. HCPVI

Injection of CO2 Stops

For the geeks

Total (water +CO2

)

RF vs

HCPVI

Injection of CO2 Stops

Water injected

Cum Gas & CO2

Inj

for Retlaw

Mannville

V

Cum Gas Injected : 1.1 MMMcfCum CO2

injected : 4.8 MMMcf

Cum Oil Prod for Retlaw

Mannville

V

July 2012

Cum Gas Prod for Retlaw

Mannville

V

North South Pressure Regions

1976 1978 1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 20080

2500

5000

7500

10000

12500

15000

17500

20000

22500

25000

0

1

_TIME_ [Years]

OIL

PR

ES

SU

RE

[kP

a]

OIL PRESSURE

NORTH PRODUCERSSOUTH PRODUCERS

UNTITLED PROJECTDATE 2008 -7 All WellsGROUP1GROUP3NORTH PRODUCERSSOUTH PRODUCERS

More Injection in South Region

Initial pressure Psi

=Pbubbble

= MMP

SIMULATION MODEL

History Matching Parameters

•

Liquid Rate Constraint•

Frac

Pressure Injection Well Constraint

•

Perm Increase around producing wells•

K = 100mD

•

Kv/Kh

= 0.1•

Pi = Pb

= 120bar

•

2 perm streaks introduced between inj

prod pairs

Ternary Saturation Diagrams

Feb 1971 Aug 2008

Injected water into gas cap

Well location

30

History Match –

Water Production

31

History Match –

Gas Production

Sensitivity to oil viscosity; What did we do?

©


20

cp

Waterflood CO2Waterflood CO2

Waterflood CO2

Incremental recovery vs. Oil Viscosity

©


Incremental recovery factor for CO2

immiscible flooding vs. waterfloods

SCREENING FOR IMMISCIBLE CO2

©


Screening for Immiscible CO2

criteria

•Oil saturation SO current

>50%•Successful waterflood; volumetric sweep Evol

>50%•Biggest hurdle;

–

Inexpensive CO2

–

corrosion hurdle existing pipe systems +CTP•API gravity 15-25API

–

Insitu

viscosity= 10-

1000cP

•

But at low temperatures and higher viscousity

there is a larger viscosity effect on Oil

©


Insitu

viscosity= 10-

1000cP why is screening problematic

©


As temperature ↓→

the change in oil viscosity goes up

~50 time drop

~10 time drop

37

What Really Controls Recovery?

Recovery Factor = ERecovery Factor = Edd

··

EEvolvol

Without Horizontal Well

EEvolvol

––

volumetric efficiencyvolumetric efficiencyEEd d ––

displacement efficiencydisplacement efficiency

Maximize thecontacted rockvolume

Epic Copyright 200938

where:

Ed

=

displacement efficiencySoi

=

initial oil saturationROS

=

the remaining average oil saturation after one movable pore volume has been

injected.

oi

oid S

ROSSE

)(

Displacement Efficiency

ROS is high for heavyoils therefore change Is significant if oil saturated with CO2

Summary

Limited immiscible pilots in literature show the promise immiscible CO2

floodingLaboratory work seems to show promise of improved recovery (∆RF=6-15%OOIP)Field projects show promiseSimulation of Canadian pilot shows; @μoil


=7%OOIP)

Simulation sensitivity @μoil


~+20%OOIP)

•Screening–Oil saturation SO current

>50%–Successful waterflood; volumetric sweep Evol

>50%

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BakerHughes Feasibility of CO2 Floding