david h. merchant - co2 conference...2015/12/08 · cmtc-440223 “the energy gap – how co 2...

Presented to Midland CO2 Conference

December 9, 2015 Midland, Texas

David H. Merchant

CMTC-440075 “SPE-139516 “Life beyond 80 – A Look at

Conventional WAG Recovery beyond 80% HCPV Injection in

CO2 Tertiary Floods”

CMTC-440223 “The Energy Gap – How CO2 Tertiary Oil

Recovery will mark its place in the 21st Century”

Merchant Consulting - Midland CO2 Conf - Dec 2015

Permian Basin

Welcome to the Permian Basin?

300 miles (480 km) North South 250 miles (400 km) East West


Carbon Management Technical Conference

November 2015

Sugarland, Texas

CMTC-440075 “SPE-139516 “Life beyond 80 – A Look at

Conventional WAG Recovery beyond 80% HCPV Injection in

CO2 Tertiary Floods”

CMTC-440223 “The Energy Gap – How CO2 Tertiary Oil

Recovery will mark its place in the 21st Century”

Thanks: CMTC Management Team

George Koperna (ARI)

Greatly Appreciated, Thank you


CMTC-440075-MS

SPE-139516 “Life beyond 80 – A Look at Conventional WAG Recovery beyond 80% HCPV Injection in CO2 Tertiary Floods” David Merchant, Merchant Consulting

Note: This paper, along with my other SPE and CMTC Publications can be down-loaded from my WEB sites listed above.

What is CO2 Tertiary Oil Recovery?


Tertiary CO2 Flooding

“CO2 Flood History since 1972”

Since 1972 over 130+ CO2 Tertiary Projects have been implemented in the United States.

Today, CO2 projects in the United States produce over 350,000 BOPD with CO2 transported over 4,500 miles of CO2 pipeline.

Sacroc Field - 1972


Permian Basin Statistics


Permian Basin

“First Commercial CO2 Flood - 1972”

“Latest Success Story”

Sacroc Unit in Kelly Snyder Field


Alabama

ArizonaArkansas

California

Colorado

Connecticut

Delaw are

Florida

Georgia

Idaho

Illinois Indiana

Iow a

Kansas Kentucky

Louisiana

Maine

Maryland

Massachusetts

Michigan

Minnesota

Missouri

Montana

NebraskaNevada

New Hampshire

New Jersey

New Mexico

New York

North Carolina

Ohio

Oklahoma

Oregon

Pennsylvania

Rhode Island

South Carolina

South Dakota

Tennessee

Texas

Utah

Vermont

Virginia

Washington

W. Virginia

Wisconsin

Wyoming

North Dakota

Mississippi

McElmo Dome Sheep Mountain

Bravo Dome

Terrell, Puckett,

Mitchell, Grey RanchPlants

LaBarge

Jackson Dome

Great Plains Coal Plant

CURRENT CO2 SOURCES and PIPELINES

1561185 Ft/In

PETRA 12/1/99 10:10:02 AM

Permian Basin Louisiana/Mississippi

Canadian

EXISTING MARKETS

Wyoming Year - 2000

Sacroc Unit

Kelly Snyder Field


SACROC UNITKELLY SNYDER FIELD

BASE MAP

By: David H. MerchantDate: September 2000

9464 Ft/In

PETRA 9/12/00 12:17:43 AM

Canyon Reef Map –

Sacroc Unit

The Kelly Snyder Field (Sacroc Unit) recovers Tertiary Oil from the Canyon Reef Limestone Formation about 6,700 ft. deep


Sacroc UnitHistorical Production and Injection


-

50,000

100,000

150,000

200,000

250,000

300,000

Jan-

48

Jan-

50

Jan-

52

Jan-

54

Jan-

56

Jan-

58

Jan-

60

Jan-

62

Jan-

64

Jan-

66

Jan-

68

Jan-

70

Jan-

72

Jan-

74

Jan-

76

Jan-

78

Jan-

80

Jan-

82

Jan-

84

Jan-

86

Jan-

88

Jan-

90

Jan-

92

Jan-

94

Jan-

96

Jan-

98

Jan-

00

Time, years

BO

PD, M

CFI

PD

-

200,000

400,000

600,000

800,000

1,000,000

1,200,000

BW

IPD

BOPDMCFIPDBWIPD

Water Injection

September 1954

CO2 Injection

January 1972

Peak Oil Rate 209,000 BOPD

Current Oil Rate 9,071 BOPD

Peak Water Inj. 126,000 BWIPD

Field Discovery

November 1948

Sacroc Unit – Production History

Year

2000

1948 1972 2000


Sacroc Unit Pennzoil Operatorship 1992 - 1999


Sacroc Unit Pennzoil Operatorship 1992 - 1999


-

50,000

100,000

150,000

200,000

250,000

300,000

Jan-

48

Jan-

50

Jan-

52

Jan-

54

Jan-

56

Jan-

58

Jan-

60

Jan-

62

Jan-

64

Jan-

66

Jan-

68

Jan-

70

Jan-

72

Jan-

74

Jan-

76

Jan-

78

Jan-

80

Jan-

82

Jan-

84

Jan-

86

Jan-

88

Jan-

90

Jan-

92

Jan-

94

Jan-

96

Jan-

98

Jan-

00

Time, years

BO

PD, M

CFI

PD

-

200,000

400,000

600,000

800,000

1,000,000

1,200,000

BW

IPD

BOPDMCFIPDBWIPD

1948 2000 1992


1996 CO2 Pattern Development Plan 300 Acre Pilot

Sacroc Unit – Pennzoil Ownership Center-line Project

1. Ghasem Bayat 2. Tony Benvegnu 3. Claud Pickard 4. Jack Horkowitz 5. Tom Wingate 6. Don Hartman

Pennzoil Team



-

8,000

16,000

24,000

32,000

40,000

Jan-90 Jan-91 Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00

Time, years

BOPD

, MCF

D, M

CFIP

D

-

40,000

80,000

120,000

160,000

200,000

240,000

BOPD

MCFIPD

Sacroc Unit – Pennzoil Ownership Historical Production – Oil Production and CO2 Injection

Pennzoil

3 years


Sacroc Unit – Pennzoil Ownership Historical Production by Project Area


Oil Rate - Historical (1990 - 2000)

0

5000

10000

15000

20000

25000

30000

Jan-

90

Jan-

91

Jan-

92

Jan-

93

Jan-

94

Jan-

95

Jan-

96

Jan-

97

Jan-

98

Jan-

99

Jan-

00

Time - years

BOPD

CENTERLINENORFLOODSOUTHWEST BANKNON PROJECT AREA

Center-line Project

Up – 3000 BOPD


Sacroc Unit Devon Operatorship 1999 – 2000 Kinder Morgan Ownership 2000 - Today


Current CO2 and Water Injection

Sacroc Unit


-

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

900,000

Jan-9

7Ju

l-97

Jan-9

8Ju

l-98

Jan-9

9Ju

l-99

Jan-0

0Ju

l-00

Jan-0

1Ju

l-01

Jan-0

2Ju

l-02

Jan-0

3Ju

l-03

Jan-0

4Ju

l-04

Jan-0

5Ju

l-05

Jan-0

6Ju

l-06

Jan-0

7Ju

l-07

Jan-0

8Ju

l-08

Jan-0

9Ju

l-09

Jan-1

0Ju

l-10

Time, years

MSC

FIPD

-

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

900,000

BW

IPD

MSCFIPD (CO2)-HIST

BWIPD-HIST

Historical Water and CO2 Injection

Kinder Morgan Company purchased Shell CO2 Company in April 2000

CO2 Injection Increase

120 MMSCFD

800 MMSCFD

2002 2010 1997


Current Oil Production

Sacroc Unit


-

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

Jan-9

7Ju

l-97

Jan-9

8Ju

l-98

Jan-9

9Ju

l-99

Jan-0

0Ju

l-00

Jan-0

1Ju

l-01

Jan-0

2Ju

l-02

Jan-0

3Ju

l-03

Jan-0

4Ju

l-04

Jan-0

5Ju

l-05

Jan-0

6Ju

l-06

Jan-0

7Ju

l-07

Jan-0

8Ju

l-08

Jan-0

9Ju

l-09

Jan-1

0Ju

l-10

Time, years

BO

PD

BOPD-HIST

BOPD-(Base Case)

BOPD-(2000 Prediction)

HistoricalOil Rate

PredictionsOil Rate

Kinder Morgan Company purchased Shell CO2 Company in April 2000

Tertiary Oil Response

8,500 BOPD

33,000 BOPD

2002 2010 1997

In 2015, the field continues to produce over 30,000 BOPD


You can’t fool Mother Nature…….

The amount of CO2 TRAPPED, STORED, OR SEQUESTERED is dependent on the Composition of the Residual Oil Saturation and Phase Trapping of the Non-Wetting Phase, which in this case is CO2.


CO2 Miscible Process Compositionally Driven

Multiple Contact Miscible Process (time and compositionally dependent)

Miscible Zone formed by CO2 becoming enriched with C2 – C30

Oil Bank Transition Zone

Residual Oil

Oil Bank CO2 Rich (Slug)


Ten CO2 Recovery Methods


1. Conventional WAG Recovery (90%+)

2. Residual Oil Zone (ROZ) (Seminole)

3. Gravity Drainage (Yates Field)

4. Double Displacement (Yates Field)

5. Gas Cycling (Denbury, Mississippi).

6. Huff-and-Puff (100+ Projects)

7. Heavy Oil - Calif. (14+ API Gravity)

8. Shale Oil (Bakken) (Under Investigation)

9. Horizontal Well Pattern Development

10. CO2 Gas Drive w/ Nitro Boost

Ten CO2 Recovery Methods used for Tertiary Oil Recovery in the United States



Conventional WAG w/ ROZ












SPE Paper 139516 – “Life Beyond 80 – A look at Conventional WAG Recovery beyond 80% HCPV Injection in CO2 Tertiary Floods”



“The Previous Millennium”

20th

Century

“Life below 80% HCPV Injected”


Pennzoil

Apac he

Alex Slaughter Uni t

M edal l ion

Tyner Unit - Oxy

Mallet Unit - Mobil

Duggan Slaughter Unit - PennzoilAltura

FL Woodley Unit - Mobil

Conoco Dean Unit - Merit

League 91 Unit

CS Dean A Unit - Apache

Boyd Mallet Unit - Belco

Bass PropertiesEast Mallet Unit - Mobil

Central Mallet Unit - Altura

Anadark o

Bob Slaughter Unit - Texaco

WG Fraz ier Uni t - Al tura Pennz oi l

Slaughter Estate Unit - Altura

Coons Uni t

Ex x on

GB Luc as Uni t

Dean C unit

Al tura

Dean B Unit - Union Royalty

Terry County

Hockley CountyCochran County

Yoakum County

Mallet LC (C,D,F) - Texaco

HT Boyd UnitIgoe Smith Unit

Sm it h I goe

NW Mallet Unit - Altura West RKM Unit - Altura

East RKM Unit - Altura

Sundown Unit - Altura

Mallet Unit - OXY

Hudgens Uni t

Gl im p Uni t

M al le t Land and Cattle - Pennz oi l

M G Gordon

M R Berry

Alt ur a

XIT Unit - Apache

Dean C Unit - M obil

Slaughter Field Map - Current Operators

SLAUGHTER FIELD - Slaughter Field Project - All Leases in Slaughter Field

14686 Ft/In

PETRA 8/1/99 9:35:02 AM

Example -WAG BENEFITS

(Control CO2 Process)

Oxy-Permian - Slaughter Estate Unit in Slaughter Field

SPE Paper No. 26624


Example - WAG BENEFITS

(Control CO2 Process)

Oxy-Permian - Slaughter Estate Unit in Slaughter Field Production and Injection (1984 – 1994)

SPE Paper No. 26624

1984

1984

1994 1994

1994 1994

1984

1984


Example - WAG BENEFITS

(Control CO2 Process) Level Load Gas Production

WAG Change - 1989

1984 1994

Effect of Constant WAG Injection Operations

Effect of Over-WAG Ops.

Oil Prod

Gas Prod



“The New Millennium”

21st

Century

“Life beyond 80% HCPV Injected”

SPE Paper 139516 – “Life Beyond 80 – A look at Conventional WAG Recovery beyond 80% HCPV Injection in CO2 Tertiary Floods”

2010’s


Field Example

Seminole Field


Oil Field History – (All Fields Worldwide)

Recovery Mechanisms Primary Oil Recovery

Secondary Recovery

Tertiary Oil Recovery

Oil Field Basics

Well Log



Permian Basin (Seminole Field)

Seminole Field Location Seminole Field

Seminole Field

The Seminole field recovers Tertiary Oil from the San Andres Formation about 5,500 ft. deep which also includes a large Residual Oil Zone (ROZ).

The Field is developed on 9-spot pattern spacing.


Permian Basin (Residual Oil Zone - ROZ)

Melzer CO2 Conf 2011

Total Gross= 406 ft Total Net= 333 ft

Gas Cap

Main

Pay

ROZ


Permian Basin (Residual Oil Zone - ROZ)

ROZ - Oil Saturation Profile

Oil Saturation

0% 100%

Note: ROZ Pay Zones do not exist in all Basins

Note:

Reservoir originally contained full column of oil

Oil migrated elsewhere in basin

A Residual Oil Saturation remained afterwards

Oil Saturation

0% 100%

Today Original


Seminole San Andres Unit

0

20,000

40,000

60,000

80,000

100,000

Jan-

35

Jan-

40

Jan-

45

Jan-

50

Jan-

55

Jan-

60

Jan-

65

Jan-

70

Jan-

75

Jan-

80

Jan-

85

Jan-

90

Jan-

95

Jan-

00

Jan-

05

Jan-

10

Jan-

15

Jan-

20

Jan-

25

Jan-

30

Jan-

35

Jan-

40

Time, years

BOPD

0

100,000

200,000

300,000

400,000

500,000

BWPD

, MSC

FD (T

otal

Gas

)

BOPDBOPD (WF)BOPD (PRIMARY)MCFDBWPDBOPD (PREDICTION)MCFD (PRIMARY PRED)BWPD (PRIMARY PRED)


Total Unit Performance

Historical Production and Injection - Rate Predictions(Primary, Secondary, Tertiary Recovery Mechanisms)

1935 201220001970 2040

Field Discovery - 1936

100,000 BOPD 500,000 BWPD, MCFD

Primary Peak Oil Production - 25,000 BOPD

Primary Recovery

Today

Note: Little Water Production occurred during Primary Recovery Note: Reservoir Pressure depleted during this time frame

Primary Recovery



0

50,000

100,000

150,000

200,000

250,000

Jan-

35

Jan-

40

Jan-

45

Jan-

50

Jan-

55

Jan-

60

Jan-

65

Jan-

70

Jan-

75

Jan-

80

Jan-

85

Jan-

90

Jan-

95

Jan-

00

Jan-

05

Jan-

10

Jan-

15

Jan-

20

Jan-

25

Jan-

30

Jan-

35

Jan-

40

Time, years

BWIP

D

BWIPD

BWIPD (Pred)

Seminole San Andres Unit Total Unit Performance

Historical and Prediction - Water Injection

1935 1971 (WF) 2012

250,000 BWIPD

TodayWater Injection

Note: Water Injection is introduced into the Reservoir in 1971 Note: Mass Balance – Water had to be found to initiate Waterflood operations

Secondary Recovery - Waterflood



0

20,000

40,000

60,000

80,000

100,000

Jan-

35

Jan-

40

Jan-

45

Jan-

50

Jan-

55

Jan-

60

Jan-

65

Jan-

70

Jan-

75

Jan-

80

Jan-

85

Jan-

90

Jan-

95

Jan-

00

Jan-

05

Jan-

10

Jan-

15

Jan-

20

Jan-

25

Jan-

30

Jan-

35

Jan-

40

Time, years

BOPD

0

100,000

200,000

300,000

400,000

500,000

BWPD

, MSC

FD (T

otal

Gas

)

BOPDBOPD (WF)BOPD (PRIMARY)MCFDBWPDBOPD (PREDICTION)MCFD (SECONDARY PRED)BWPD (SECONDARY PRED)




1935 201220001971 (WF) 2040


100,000 BOPD 500,000 BWPD, MCFD

Secondary Recovery

Today

Secondary Peak Oil Production - 75,000 BOPD

Water Injection

Secondary Recovery - Waterflood

Note: Good Secondary Oil Response after Water Injection Note: Gas Production collapsed after Water Injection (Pressure-up) Note: Water Prodution occurred shortly after Water Injection



0

20,000

40,000

60,000

80,000

100,000

Jan-

35

Jan-

40

Jan-

45

Jan-

50

Jan-

55

Jan-

60

Jan-

65

Jan-

70

Jan-

75

Jan-

80

Jan-

85

Jan-

90

Jan-

95

Jan-

00

Jan-

05

Jan-

10

Jan-

15

Jan-

20

Jan-

25

Jan-

30

Jan-

35

Jan-

40

Time, years

BOPD

0

50,000

100,000

150,000

200,000

250,000

BWPD

, MSC

FD (T

otal

Gas

)

BOPD (WF)BOPD (PRIMARY)BOPD (PREDICTION)BOPDMCFDBWPDBWPD (Pred)MCFPD (Pred)




1935 20122000 2040


100,000 BOPD 250,000 BWPD, MCFD

Tertiary Recovery

(Main Pay Only)

Today


CO2 Injection

Tertiary Peak (MP) Peak Oil Production - 43,000 BOPD

1983 (MP)

(Level Load)

Note: The Reservoir produced a strong Tertiary Oil Response Note: Total Gas Production increased with rapid breakthrough Note: Water Injection and Production were decreasing prior to 1996 prior to ROZ start-up in 1996 Note: Total Gas Rate is “Level Loaded” to Plant Inlet Rate



0

50,000

100,000

150,000

200,000

250,000

Jan-

35

Jan-

40

Jan-

45

Jan-

50

Jan-

55

Jan-

60

Jan-

65

Jan-

70

Jan-

75

Jan-

80

Jan-

85

Jan-

90

Jan-

95

Jan-

00

Jan-

05

Jan-

10

Jan-

15

Jan-

20

Jan-

25

Jan-

30

Jan-

35

Jan-

40

Time, years

BW

IPD

0

100,000

200,000

300,000

400,000

500,000

MSC

FIPD

BWIPD

BWIPD (Pred)

MCFIPD

MCFIPD (Pred)


Historical and Prediction - Water and CO2 Injection

1935 1971 (WF) 1983 (MP)CO2 Injection

1996 (ROZ) 2012

250,000 BWIPD 500,000 MSCFIPD


Note: Total Gas Injection has been constant since CO2 Injection in 1983 Note: Water Injection was decreasing from 1983 to 1996 (Prior to ROZ)



0

20

40

60

80

100

Jan-

35

Jan-

40

Jan-

45

Jan-

50

Jan-

55

Jan-

60

Jan-

65

Jan-

70

Jan-

75

Jan-

80

Jan-

85

Jan-

90

Jan-

95

Jan-

00

Jan-

05

Jan-

10

Jan-

15

Jan-

20

Jan-

25

Jan-

30

Jan-

35

Jan-

40

Time, years

OIL

REC

OVE

RY

- % O

OIP

OIL REC PRIMARY - % OOIPOIL REC WF - % OOIPOIL RECOVERY - % OOIPOIL REC PRIMARY - % OOIPOIL REC WF - % OOIPOIL RECOVERY - % OOIP



PRIMARY

Historical Oil (Primary + Secondary + Tertiary) Recovery - % OOIP

Tertiary Oil Recovery -

TERTIARYSECONDARY

Waterflood Oil Recovery -

Primary Recovery-

Total Incremental Tertiary Oil Recovery to Date -

12.8%

29.9%

26.0%

18.9%

PREDICTION

Expected Ultimate Oil Recovery - 68.7%

Tertiary Recovery

(Main Pay Only)

Note: The Reservoir is expected to Recover 26% of its OOIP with CO2 Injection


0

20,000

40,000

60,000

80,000

100,000

Jan-

35

Jan-

40

Jan-

45

Jan-

50

Jan-

55

Jan-

60

Jan-

65

Jan-

70

Jan-

75

Jan-

80

Jan-

85

Jan-

90

Jan-

95

Jan-

00

Jan-

05

Jan-

10

Jan-

15

Jan-

20

Jan-

25

Jan-

30

Jan-

35

Jan-

40

Time, years

BOPD

0

50,000

100,000

150,000

200,000

250,000

BWPD

, MSC

FD (T

otal

Gas

)

BOPDBOPD (WF)BOPD (Tertiary MP)BOPD (ROZ)MCFDBWPDBWPD (Pred)MCFPD (Pred)




1935 20121996 (ROZ) 2040


100,000 BOPD 250,000 BWPD, MCFD

Tertiary Recovery

(ROZ Addition)

Today


CO2 Injection

Tertiary Peak (MP) Peak Oil Production - 43,000 BOPD

1983 (MP)

(Level Load)


Note: The ROZ produced a strong Tertiary Oil Response Note: Total Gas Production has been “Level Loaded” to Plant Inlet Rate Note: ROZ Water Production will be strong initially, but should decrease with time, level out, and then increase as WAG Ratio is increased



0

50,000

100,000

150,000

200,000

250,000

Jan-

35

Jan-

40

Jan-

45

Jan-

50

Jan-

55

Jan-

60

Jan-

65

Jan-

70

Jan-

75

Jan-

80

Jan-

85

Jan-

90

Jan-

95

Jan-

00

Jan-

05

Jan-

10

Jan-

15

Jan-

20

Jan-

25

Jan-

30

Jan-

35

Jan-

40

Time, years

BWIP

D

0

100,000

200,000

300,000

400,000

500,000

MSC

FIPD

BWIPD

BWIPD (Pred)

MCFIPD

MCFIPD (Pred)


Historical and Prediction - Water and CO2 Injection

1935 1971 (WF) 1983 (MP)CO2 Injection

1996 (ROZ) 2012

250,000 BWIPD 500,000 MSCFIPD


Note: Total Gas Injection has been constant since CO2 Injection in 1988 Note: Water Injection was decreasing from 1983 to 1996 (Prior to ROZ) Note: ROZ Increase in Water Injection in 1996 and decrease in 2000


Gravity Drainage / Double Displacement













CO2 Sequestration, Gas Storage and

Gravity Drainage Projects

Low Dip Reservoir Moderately Low or High Dip Res. (Conformance can be detrimental) (Can run Miscible or Immiscible) Gas Cycling is a big problem Conduct a gravity Stabilized CO2 flood with chase gas

CO2 Conformance Problems

CO2 Bank

Chase Gas Inj.

CO2, Flue gas, Nitrogen , Air

Displacement Process Replacement Process


San Andres Map – Yates Field

San Andres Map – Yates Field


Discovered in 1926 550’ of Oil Column at Structure Top

Discovery: 1926

Produced By Individual Operators Unitized in 1976 to Prevent Aquifer Influx

1926 - 1976

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

1992 - 2000 Double Displacement Reservoir Dewatering Contact Lowering

2000 - 2012 Contact Stabilization (30 ft oil column) Gas Cap Injection Aquifer “Maintenance” By Offsite Disposal

Yates Reservoir History


Field Production and Injection

Yates Total Unit PerformanceProduction and Injection

0

50,000

100,000

150,000

200,000

250,000

Jan-

25

Jan-

30

Jan-

35

Jan-

40

Jan-

45

Jan-

50

Jan-

55

Jan-

60

Jan-

65

Jan-

70

Jan-

75

Jan-

80

Jan-

85

Jan-

90

Jan-

95

Jan-

00

Jan-

05

Time, years

BO

PD, M

SCFD

0

100,000

200,000

300,000

400,000

500,000

BW

PD

BOPD

MCFPD

MSCFIPD(Total Gas)

BWPD

BWIPD

Oil Production (Peak)130 MBOPD (approx.)

Primary ProductionHistory

Secondary and Tertiary Production History

Yates Unit Historical Performance


Yates Total Unit PerformanceGas Injection Only

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

200,000

Jan-

70

Jan-

72

Jan-

74

Jan-

76

Jan-

78

Jan-

80

Jan-

82

Jan-

84

Jan-

86

Jan-

88

Jan-

90

Jan-

92

Jan-

94

Jan-

96

Jan-

98

Jan-

00

Jan-

02

Jan-

04

Time, years

BO

PD, M

SCFD

0

50,000

100,000

150,000

200,000

250,000

MSC

FIPD

(GA

S,C

O2,

N2)

BOPD

MSCFPD(GAS)

MSCFPD(CO2)

MSCFPD(N2)Gas Inj Startup - July 1976 Tertiary Production History

CO2 GasInjection

N2 Gas Injection

CO2 Injection Startup - Nov. 1985

Comb GasInjection

Field Gas Injection Breakout

CO2 Flue Gas Nitrogen/CO2 CO2



Field Injection (Current)

Yates Total Unit PerformanceNitrogen and CO2 Injection (Current)

-

50,000

100,000

150,000

200,000

250,000

Jan-

97

Jul-9

7

Jan-

98

Jul-9

8

Jan-

99

Jul-9

9

Jan-

00

Jul-0

0

Jan-

01

Jul-0

1

Jan-

02

Jul-0

2

Jan-

03

Jul-0

3

Jan-

04

Jul-0

4

Jan-

05

Jul-0

5

Jan-

06

Jul-0

6

Jan-

07

Jul-0

7

Jan-

08

Jul-0

8

Jan-

09

Jul-0

9

Jan-

10

Jul-1

0

Time, years

MS

CFI

PD

MSCFIPD (N2)-HIST

MSCFIPD (CO2)-HIST

Historical N2 and CO2 Injection

Kinder Morgan returned CO2 injection to Yates field in 2003 in addition to a horizontal drilling program


CO2

N2


Field Production (Current)

Yates Total Unit PerformanceOil Production (Current)

-

10,000

20,000

30,000

40,000

50,000

60,000

70,000

Jan-

97

Jul-9

7

Jan-

98

Jul-9

8

Jan-

99

Jul-9

9

Jan-

00

Jul-0

0

Jan-

01

Jul-0

1

Jan-

02

Jul-0

2

Jan-

03

Jul-0

3

Jan-

04

Jul-0

4

Jan-

05

Jul-0

5

Jan-

06

Jul-0

6

Jan-

07

Jul-0

7

Jan-

08

Jul-0

8

Jan-

09

Jul-0

9

Jan-

10

Jul-1

0

Time, years

BO

PD

BOPD-HIST

HistoricalOil Rate

Kinder Morgan returned CO2 injection to Yates field in 2003 in addition to horizontal drilling program


10,000 BOPD Increase

In 2015, the field continues to produce between 20,000 BOPD and 30,000 BOPD


Gas Cycling – Denbury Resources













Gas Cycling Example – Denbury

Little Creek Field and West Mallalieu Field


Gas Cycling Example – Denbury

Little Creek Field and West Mallalieu Field

Denbury: 2006 CO2 Conf


Huff-n-Puff (Single Well Injection)













Small Field and Huff-n-Puff Example Dr. Robert Zubrin


Heavy Oil (14+ API Gravity)












Wilmington Offshore THUMS Unit

Wilmington Onshore CO2 Pilots


Heavy Oil Example – 14+ API Gravity Wilmington Field – Los Angeles (3 CO2 Pilots)

Wilmington Field


Shale Oil – Bakken, Wolfcamp













Williston Basin – Bakken Formation – Shale Oil Target

To improve Primary Oil Recovery, operators have resorted from single to bilateral Horizontal Well Completions with massive sand fracture technology to improve Primary Oil Recovery.


Williston Basin – Bakken Formation

To make this technology work, large investments involving many horizontal wells on steep decline are required to keep a reasonable continuous rate profile. This results in a many well, many year continuous drilling programs.



Results of this effort are shown below

The 10 year Bakken development plan shown above contains 10 one year phases. Ninety wells per phase per year are required for the first four phases with 45 wells per phase per year for the last six phases. This results in a total of 635 wells to be drilled over a 10 year period with a single well cost of around 3 million dollars. For other areas of the Bakken drilling costs can exceed 12 million dollars per well.


Reservoir Model Study – CO2 Tertiary Prediction

Simulation Comparison study results are shown above. Primary recovery was limited to 5 years (3.64% OOIP). With CO2 Injection over 95 years, Continuous Injection of CO2 out-performed water injection and other cyclic Huff-n-Puff injection schemes.

CO2 Oil Recovery

Primary

Oil Recovery



Reservoir Model Study – CO2 Tertiary Prediction

The simulation results show that CO2 flooding presents a technically promising method for recovering Bakken oil, but over a very long injection period (95 years of injection). Also, note the long time to breakthrough (several months to many years).

Water flood Recovery CO2 Recovery



Horizontal Well Development













Horizontal Drilling CO2 Projects

Canada - Weyburn Field Utah - Aneth Field

Montana – Cedar Creek Anticline North Sea – Denmark – Dan Field

Current CO2 Floods

Future CO2 Floods


CO2 Gas Drive w/ Nitro Boost












Merchant Consulting - Midland CO2 Conf - Dec 2015 Kern County California

Kern County California

California

Kern County Oil Fields

Rio Bravo Field - Phased-in Pattern Development Conventional WAG Case – Producer and Injector Pattern Development

Rio Bravo Field - Phased-in Pattern Development Gravity Drainage Case - Injectors

Rio Bravo Field - Phased-in Pattern Development Gravity Drainage Case - Producers


Oxy Fuel Concept

Rio Bravo Unit Field - Phased-in Pattern Development Gravity Drainage Case – CO2 Injection w/ Nitro Boost

Merchant Consulting - Midland CO2 Conf - Dec 2015 84

Additional CO2 Injection Wells (down-dip)

N2 Injection Wells (up-dip)

Gravity Drainage Development Plan CO2 Injector Count: 5 Wells N2 Injector Count: 5 Wells Producer Count: 113 Wells Nitro Boost Addition

Rio Bravo Field - Phased-in Pattern Development Gravity Drainage Case – with addition of Nitro Boost












Eleventh CO2 Recovery Methods used for Tertiary Oil Recovery in the United States

Recover both Tertiary Oil and Water

Eleventh CO2 Recovery Method used for CO2 Sequestration

Enhanced Oil Recovery - EOR

Note: Recover both Tertiary Oil and Water


Note: This paper, along with my other SPE and CMTC Publications can be down-loaded from my WEB sites listed above.


“CO2 Sequestration Future 2005”

In the 21st Century, CO2 Sequestration will provide CO2 from IGCC Natural Gas and Coal Fired Power Plants, Refineries, and other large scale Anthropogenic CO2 Sources to fill the Energy Gap that exists between “Peak Oil” and the future “Hydrogen Energy Economy”.


1. Primary Oil Recovery 2. Secondary Oil Recovery 3. Tertiary CO2 - Conventional Tertiary Oil Recovery 4. Tertiary CO2 - Residual Oil Zone (ROZ) 5. Tertiary CO2 – Heavy Oil (14+ API) 6. Offshore – Shallow and Deep Water 7. Natural Gas (Conventional Reservoirs) 8. Liquefied Natural Gas (LNG) 9. Shale Oil (Wolfcamp, Eagle Ford, Bakken, Others) 10. Shale Gas (Marcellus, Barnett, Eagle Ford) 11. Coal to Gas, Coal to Liquids 12. Steam, Thermal, and MEOR (Bacteria)

Gap Fillers


1. Wind Power 2. Solar Power 3. Nuclear (Fission) 4. Nuclear (Fusion) 5. Hydrogen Power (Hydrogen Cars and Hydrogen Fuel Cells) 6. Tertiary CO2 – EOR and CO2 Sequestration 7. Mass Transportation (Automobiles poor means to move

people) 8. Clean Coal Gasification (Pre-Post Combustion, Oxy-fuel) 9. Clean Natural Gas – (Conventional and Un-Conventional) 10. Biomass – Balance with Mother Nature 11. Nano Tech 12. Algae (Clean Fuels)

Hydrogen Economy –“Clean Air Environment”

Merchant Thanks to Steering Committee! 1995 First CO2 Conference: Talk on: Montage approach to Reservoir

Management in Tertiary CO2 Floods – SPE 26624

Newspaper Article celebrates CO2 Injection start-up into the Elmar field along with the CO2 Conference scheduled for December 4-5, 1995

Pictured: Tom McKnight (Union Royalty) David Merchant (Amoco) Ron Brockmeyer (Amoco) Russell Martin (Enron Gas Pipeline)

Merchant Thanks to Steering Committee! 1995 Montage approach to Reservoir Management in Tertiary

. CO2 Floods – SPE 26624 1999 Screening CO2 Candidate Reservoirs Fundamentals of Pattern

Analysis 2000 Setting up the Pieces – What Constitutes a Simulation? 2004 Pattern Performance as a Diagnostic Tool for Reservoir

Surveillance 2004 Monitoring the CO2 Flood - Problem Identification and Solutions 2009 Comparisons of Conventional CO2 WAG Injection Techniques used

in the Permian Basin 2010 Life beyond 80 – A look at Conventional WAG Recovery beyond

80% HCPV in CO2 Tertiary Floods – SPE 139516 2012 The Energy Gap - “How CO2 Tertiary Recovery will mark its place

in the 21st Century” 2013 Short Course: Surveillance and Monitoring of CO2 Injection Projects

– “Pattern Balancing and Mass Balance” 2014 Short Course: Produced Water Management for CO2 Injection

Projects – “Factors in the Permian Basin Subsurface “Mass Balance” 2015 CMTC440075 Life beyond 80 – A look at Conventional WAG

Recovery beyond 80% HCPV in CO2 Tertiary Floods – SPE 139516

Thanks,

Now its your turn?

David H. Merchant

Merchant Consulting Email: [email protected]

CO2 Storage Solutions WEB: www.CO2StorageSolutions.com

Key Words: Merchant Consulting, CO2 Storage Solutions, CO2 Seminars on Wheels

Magnolia, Texas o281-374-6330

mailto:[email protected]

http://www.co2storagesolutions.com/

david h. merchant - co2 conference...2015/12/08 · cmtc-440223 “the energy gap – how co 2...

Documents