Paul Button and Chris Peterson KinderMorgan

10th ANNUAL CO2 FLOODING CONFRENCE

Midland, TX

December 2004www.spe-pb.org

Enhanced Gravity Drainage Through Immiscible CO2 Injection in

the Yates Field (Tx)

MILES

0 25 50

DELAWARE

BASIN

MIDLAND

BASINNEW MEXICO

TEXAS

N

CENTRAL

BASIN

PLATFORM

NORTHWEST SHELF

EA

STE

RN

SHE

LF

SHEFFIELD CHANNEL

Midland

YATES FIELD -HIGH POINT OF CBP

VAL VERDEBASIN

• ~ 90 miles South Midland/Odessa

• SE tip of Central Basin Platform

• Structural high point of the CBP

• 26,423 Acres

Yates Field Unit - Location Map

General Facts & History

• Field Discovery - October 28, 1926 (Ira Yates’ 67th birthday)

• Discovery Well: I. G. Yates A No. 1 (Unit Well No. 4901)

Structure on Top of the San Andres Formation

North

Vertical Exaggeration ~ 9x.

Type of Reservoir• Highly Fractured Carbonate

Middle shelf Shelf crestInnerslopeHFS 2

HFS 3HFS 4

Rampcrest

HFS 1

Ramp

Outer ramp

HFS 5

11 km

StratigraphyStratigraphy

Fusulinid packstone/grainstone

Indicator FaciesCGR

50 m

eter

s

1-D Interpretation

HF

S 5

HF

S 4

HF

S 3

HF

S 2

East-West Permeability Slice

High Permeability Zones

3-D View of San Andres Structure with Fracture

Connection Overlay

7Rv/Qn/Gbg 0.5

SA (above +1,050’) 2.8SA (+950’ to +1,050’) 1.4

Total (above +950’) 4.2

SA (below +950’) 0.3

TOTAL 5.0

Gross

BBO .

Yates Original Oil in Place (OOIP)

+950’

+1,050’

0

20,000

40,000

60,000

80,000

100,000

120,000

1925 1945 1965 1985 2005

Production History

Great Depression

WWII

Unitization

BOPD

General Facts & History• Field Discovery - October 28, 1926

• Highest Oil Rate = 205,000 BPD (Well No. 4930 in 1929)

• Total Wells in 1929 = 315

• Total Production Capacity of Wells Exceeded 2 MMBOPD!

• Unitized July 1, 1976

Gas Plant built in 1961 to recover natural gas liquids and prevent flaring

General Facts & History

East Side of Field

-In-field drilling continued into the mid 80’s

-East side had flowing wells

A distinct east/west line of demarcation was considered to exist in the field

West Side of Field

-Waterflood started in 1979

-Produced using pumping units

-Polymer injection from 1983 - 1989

General Facts & History

1985-1991

CO2 injected into the gas cap on east side of the field for pressure maintenance

General Facts & History

1993 – Nitrogen injection from ASU #1 (30 MMCFD) initiated for pressure maintenance

1996 – ASU #2 (60 MMCFD) increased nitrogen injection.

General Facts & History

WALRUS Process

1998 - WALRUS program initiated• Acronym for Wettability Alteration of Reservoirs Using Surfactant

• Surfactant was added with produced water and injected into the reservoir to enhance oil movement

General Facts & History

1998 – Water Export commenced for reservoir management

General Facts & History

1999 –2002

Steam injection pilot was run;

post-evaluation in progress.

General Facts & History

Historical Recovery Techniques• Primary Depletion/Natural Bottom Water Drive

(NBWD) (1926 – 1976)

• Gas Injection/Limited NBWD (1976 – 1985)

• West Side Water Flood/Polymer Augmented WF (1981-1988)

• East Side CO2 Injection (1985 - 1991)

• Double Displacement Process (Co-Production) (1993-2000)

• Gravity Drainage (2000 – Present)

Primary Depletion

Unit Formed

Tertiary CO2 PAW

Tertiary DDP

Tertiary Thermal

WALRUS

Gravity Drainage Process

Recovery Processes

Yates Field ReservoirSecondary Pressure

Maintenance

YFU Extraneous Gas Injection

0

30000

60000

90000

120000

Jul-7

6

Jul-7

7

Jul-7

8

Jul-7

9

Jul-8

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Jul-8

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Jul-0

0

Eff

ecti

ve F

ree

Gas

Ad

dit

ion

s (

MC

FP

D)

Flue gas CO2 C1 N2 Solution gas

Discovered in 1926550’ of Oil Column at Structure Top

Discovery: 1926

Produced By Individual OperatorsUnitized in 1976 to Prevent Aquifer Influx

1926 - 1976

1976 - 1992 Gas Re-injected, Water Re-injectedOil Column Thinned

1992 - 2000 Gas Cap InflationReservoir DewateringContact Lowering

2000 - 2005 Contact StabilizationGas Cap InjectionAquifer “Maintenance” By Offsite Disposal

Yates Reservoir History

Yates Field Unit Saturation Profile

+ 1200

+ 1050

+ 850

WOC

1926

Frac

Mat

rix

1976

Frac

GOC

Mat

rix

WOC

1990’s

Frac

GOC

Mat

rix

WOC

Present

Frac

GOC

Mat

rix

WOC

Reservoir Review

So, WhyGravity Drainage?

For

mat

ion

Por

osity

%

Total Formation HeterogeneityLow High

0

30

Gravity And Capillary

Replacement Processes

Dis

plac

emen

t P

roce

sses

Depletion Processes

Neutral Zone

Yates

Reservoir Recovery Process Screening

Matrix surroundedby fluid-filled fractures

Matrix exposed togas-filled fractures

Matrix exposed togas-filled fractures

Matrix exposed togas-filled fractures

Mobilization

GOC

WOC

1) Oil drains vertically through matrix until downward movement is limited by phase mobility.

Mobilization

GOC

WOC

1) Oil drains vertically through matrix until downward movement is limited by phase mobility.

2) When vertical mobility is limited, the oil migrates laterally into fractures and is Mobilized to be available for Capture.

~222 MMCFD

~151 MMCFD

+1015 Current WOC

+1040 Current GOC~24,500 BOPD

~392,000 BWPD

~25,000 BWPD Export

+1050 Original WOC

~417,000 BWPD

~109 MMCFD CO2

~113 MMCFD Prod

Produced Gas Composition

N2 CO2 H2S HC

~41% ~30% ~3% ~26%

Operations – Material Balance

~550 NGLPD

~14.8 MMCFD Fuel ~3.3 MMCFD Gas Sales

~17.6 MMCFD N2 Vent

Average Contacts – Connected Wells

1000

1020

1040

1060

1080

1100

1120

1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005

0

20

40

60

80

100

120

GOC WOC OCT Well Count

Resaturation

800

900

1000

1100

1200

1300

1400

1500

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

So (Oil Saturation)

Ele

vati

on

(F

T S

UB

SE

A)

Current Oil saturation Futrure Oil saturation GOC WOC

So to .89Sw to .11

GOC = 1045’

WOC = 1015’

1) Resaturation is controlled by maintaining the position of the contacts

2) Goal - prevent downward movement of the oil column

Oil

Gas

Water

At a lower elevation and thinner column, the fracture connectivity within the oil column is reduced.

Yates Horizontal Drilling Operations/Results

Production response from Production response from HDH wellsHDH wells

Horizontal Drain HoleHorizontal Drain HoleRe-establish fracture connectionsRe-establish fracture connections

10,000

12,000

14,000

16,000

18,000

20,000

22,000

24,000

26,000

2001 2002 2003 2004 2005

BO

PD

2005 (115wl)2004 (130 wl)2003 (75 wl)Base

Why CO2 at Yates ??

• After active fluid contact movement stopped need to develop method to enhance gravity drainage above Nitrogen injection

• Possible EOR Processes– Thermal - Expensive and doesn’t replace voidage

– Methane Injection – Expensive for voidage replacement

– NGL Injection – Expensive and technically challenging

– Immiscible CO2 – Reasonable cost and positive

compositional effects

Why Immiscible CO2 Will Work at Yates• Compositional effects of Nitrogen Injection

– Strips light end components– Increase oil viscosity– Negative impact on Kro

• Compositional effects of Immiscible CO2

– Decrease oil viscosity• Lab tests ~ -25 % from “Non-stripped“ sample• Lab tests ~ -50 % from “N2 stripped“ sample• Model ~ 30 % from N2 processed oil

– Positive impact on Kro• Lab tests ~ 5 % from “Non-stripped“ sample• Lab tests ~ 12 % from “N2 stripped“ sample• Model ~ 7-8 % from N2 processed oil

• CO2 injection results in improved oil mobility vs. Nitrogen injection

Oil Mobility = K * Kro

Yates Compositional Model History Match

300

400

500

600

700

800

900

Pre

ssu

re (

Psi)

1052 New Pressure @ +1050

Production History Match

-

20,000

40,000

60,000

80,000

100,000

120,000

140,000

J-26 J-31 J-36 J-41 J-46 J-51 J-56 J-61 J-66 J-71 J-76 J-81 J-86 J-91 J-96 J-01

Oil

an

d W

ater

(B

PD

)

-

50,000

100,000

150,000

200,000

250,000

Gas

(M

CF

)

Model Oil Model Water

Hist Oil Hist Water

Model Gas Hist Gas

-Reasonable pressure match- Discrepancy due to large difference in fluid contacts across the reservoir in late 80’s and 90’s

- Reasonable match on all fluids- Major oil difference due to documented leak oil- Water match on exported water

Yates Compositional Model History Match

800

900

1000

1100

1200

1300

1400

1500

0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0

So

Ele

va

tio

n (

Ft)

12/31/1984 1984 Log Study 8/31/2002 1984 Ave (block)

1000

1050

1100

1150

1200

1250

1300

1350

1400

1450

1500

Jan-26 Jan-31 Jan-36 Jan-41 Jan-46 Jan-51 Jan-56 Jan-61 Jan-66 Jan-71 Jan-76 Jan-81 Jan-86 Jan-91 Jan-96 Jan-01

Ft

abo

ve S

ea le

vel

0

50

100

150

200

250

300

350

400

450

500

Ft

GOC OWC hist GOC Hist WOC

Series7 OCT Hist OCT

-Reasonable fluid contact match based on available data early time-Very good fluid contact match late time

-Reasonable oil saturation match based on 1984 log saturation study-Projection of current matrix oil saturation

Projected Oil Response from Yates Immiscible CO2 Injection Project

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

2002 2004 2006 2008 2010 2012 2014 2016 2018 2020

Year

Oil

Rat

e (B

OP

D)

High Trend (BOPD)

Medium Trend (BOPD)

Low Trend (BOPD)

Immiscible CO2 Injection Design

• Vertical Placement– Concentrate CO2 within 50’ of

current GOC

• Areal Placement– NW portion of Field (Area with

high N2 content)

• Planned CO2 Migration– Vertical

• Migration Upward to GLM

– Areal• Recycle through Gas Plant

and injected in SE Area

Vertical CO2 Placement

800

900

1000

1100

1200

1300

1400

1500

0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0

Matrix Oil Saturation

Ele

vati

on

(ft

ab

ove

sea

lev

el)

Current So Current GOC Top of CO2 Target Area Avg CLM Elevation

CO2 Target Area

CO2 Recycle Area

Implementation of Immiscible CO2 Injection

• CO2 injection started March 1st 2004• Used existing infrastructure to distribute CO2

to injection wells • Converted gassed-out horizontal producers to

CO2 injectors within 50’ of current gas-oil contact

• Initiated injection at 42.5 MMCFD of CO2

• N2 Rejection started March 2005

• Current CO2 injection rate 109 MMCFD

Cumulative CO2 Injected Since March, 2004

CO2 Inj. Well

Gas Inj. Well

Total CO2 Injected = 45.7 BCF

CO2 Area

Non-CO2 Area

CO2 Injection – Assessment

Non-CO2 Area

CO2 AreaIs Oilier

Different GOR Behavior

Different Vertical Declines

All Wells Non-CO2 Area

0

2000

4000

6000

8000

10000

12000

0 10000 20000 30000 40000 50000 60000

CUM GAS MCFPD

CU

M O

IL B

OP

D

Feb 05

Feb 04

Sep 04

Less Efficient

More Efficient

CO2 Injection – Assessment

All Wells CO2 Area

0

2000

4000

6000

8000

10000

12000

14000

16000

0 10000 20000 30000 40000 50000 60000 70000 80000

CUM GAS MCFPD

CU

M O

IL B

OP

D

Feb 05

Feb 04

Sep 04

Less Efficient

More Efficient

CO2 Injection – Assessment

Vertical Wells Non-CO2 Area

0

1000

2000

3000

4000

5000

6000

7000

0 5000 10000 15000 20000 25000 30000

CUM GAS MCFPD

CU

M O

IL B

OP

D

Feb 05

Feb 04

Sep 04

Less Efficient

More Efficient

CO2 Injection – Assessment

Vertical Wells CO2 Area

0

1000

2000

3000

4000

5000

6000

7000

0 5000 10000 15000 20000 25000 30000 35000

CUM GAS MCFPD

CU

M O

IL B

OP

D

Feb 05

Feb 04

Sep 04

Less Efficient

More Efficient

CO2 Injection – Assessment

All Wells

0

5000

10000

15000

20000

25000

30000

0 20000 40000 60000 80000 100000 120000 140000 160000

CUM GAS MCFPD

CU

M O

IL B

OP

D

Feb 05

Feb 04

Sep 04

Less Efficient

More Efficient Aug 05

CO2 Injection – Assessment

0

5,000

10,000

15,000

20,000

25,000

30,000

2002 2003 2004 2005

BO

PD

Base Pre 05 HDH 05 Phs 1 CO2

Current Production

Yates Field Response VS. Modeling Predictions

• Field response much earlier than model predicted

• Portion of early oil production response may be response to redistribution of gas injection

Projected Oil Response from Yates Immiscible CO2 Injection Project

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

2002 2004 2006 2008 2010 2012 2014 2016 2018 2020

Year

Oil

Rat

e (B

OP

D)

High Trend (BOPD)

Medium Trend (BOPD)

Low Trend (BOPD)

8801 OBS

88158816 Flush oil from thinning

Imitates CO2 response

Yates CO2 Expansion Options

• Modify Existing Facilities– Increase N2 Rejection (to 30+ MMCFD)

• CO2 Processing

– Expand Delivery Capacity• Pipeline Pump

– Mix CO2 with Recycle Gas

• New Facility Potential– New gas processing facility N2 Rejection– Additional Pipeline for CO2 Delivery– Simulation Driven