Field Demonstration of CO2Miscible Flooding

in the Lansing-Kansas City Formation, Central Kansas

April 16, 2007NETL Project ReviewTulsa, Oklahoma

University of KansasG. Paul Willhite, TORPAlan Byrnes, KGS

Class II Revisited DE-AC26-00BC15124

Overview

• Demonstration Site• Objectives• Working Interest Partners• Field Demonstration Plan• Milestones• Oil Production Response• Management Plan • Evaluation of Potential for Commercial Operation• Geological Learnings

Lansing-Kansas City Production and Project Location

Hall-Gurney Field

5 MilesCO2 Pilot Study Area

PartnersPartners

Purpose of Demonstration• Determine the technical and economic feasibility

of using CO2 miscible flooding to recover residual and bypassed oil in LKC shallow shelf carbonates.

• Develop reservoir data for the LKC and Hall-Gurney for other floods

• Develop an understanding of operating costs and operating experience for CO2 miscible flooding in Lansing-Kansas City reservoirs

• Oil in tank and provide sufficient information to expand to commercial scale

Location of Ethanol Plant & CO2 Location of Ethanol Plant & CO2 Pilot SitePilot Site

Kansas Geological SurveyKansas Geological Survey

Kansas Geological SurveyKansas Geological Survey

CO2 Pilot Area

Tank Battery & CO2 Injection Equipment

DOE ParticipationDOE Participation• Phase One – DOE Contribution 45%DOE Contribution 45%

– March 2000 to January 2004

– Perform Reservoir Characterization and Simulation

– Conduct Field Studies to Determine if CO2 Pilot Implementation Feasible (Included Well Workovers and Water Injection Facilities)

– Develop Working Interest Partnerships and Other Working Agreements (CO2 Supply, CO2 Transport, and CO2 Injection)

– Pre-startup Activities (Tank Battery Upgrade and CO2 Injection Equipment Set-up )

– Trial CO2 Injection

DOE ParticipationDOE Participation

• Phase Two – DOE Contribution 35%DOE Contribution 35%– February 2004 to December 2008

– Implement, Operate, and Monitor CO2 Pilot

• Phase Three – DOE Contribution 10%DOE Contribution 10%– January 2009 to March 2010

– Post CO2 Flood Monitoring (Water Injection)

– Continue Tech Transfer Activities

Milestones• December 3, 2003-Begin CO2 Injection• February 2004- Initial oil production response in pilot

wells~3 B/D• June 2005-Switch to water injection after injection of

16.19 MM lb(138.05MMCF) of CO2• April-May 2006-Increased oil production from Graham

A4(adjacent lease) discovered in August 2006• May 2006-Oil production from pilot increased to

5.5-6 B/D• August 2006-Colliver #7 opened to C zone-substantial

increase in oil production on Colliver A Lease• March 15, 2007- 4329 BBL production from pilot wells

Oil Production –Pilot -2007

0.0

2.0

4.0

6.0

8.0

10.0

12.0

Jan-06 Feb-06 Mar-06 Apr-06 May-06 Jun-06 Jul-06 Aug-06 Sep-06 Oct-06 Nov-06 Dec-06

Oil

Rat

e, B

/D

CO2#13CO2#12

Flush Production from CO2#16 and Increase Rate in CO2#12

Colliver A

16

CO2 Pilot Lease

Colliver A

16

CO2 Pilot Lease

Graham A Lease Monthly Oil Production

0

50

100

150

200

250

300

350

Aug-04Sep

-04Oct-

04Nov-0

4Dec

-04Ja

n-05Feb

-05Mar-

05Apr-0

5May

-05Ju

n-05Ju

l-05

Aug-05Sep

-05Oct-

05Nov-0

5Dec

-05Ja

n-06Feb

-06Mar-

06Apr-0

6May

-06Ju

n-06Ju

l-06

Aug-06Sep

-06Oct-

06Nov-0

6Dec

-06

bpm

It Only Makes Sense To:It Only Makes Sense To:

Kansas Geological SurveyKansas Geological Survey

Colliver A Lease Oil Production

1

10

100

12/14

/2005

3/24/2

006

7/2/20

06

10/10

/2006

1/18/2

007

4/28/2

007

bopd

Colliver A Lease Oil Production

Colliver A 7 packer released, 8/28/06

Colliver A 7 SPM from 11.3 to 12.5, 9/28/06

Colliver A 3 RTP'd, 10/11/065 wells producing,

#1, #5, #6, #7, & #14

Long stroked Colliver A 3, 10/17/06

Colliver Lease as of April 2, 2007

+

++

Production from SurroundingLeases

Graham A April-May 2006

Colliver A August 2006

Table 1: Estimated Incremental Oil from CO2 Injection into LKC C

Date CO2 Pilot

Colliver A Lease

Graham A Lease

TotalBBL

MCF /BBL

12/31/06 3927 2703 1193 7823 17.9

6/30/07 4827 5242 10069 13.9

12/31/07 5747 6297 12044 11.6

CO2 Injected-138.05 MMCF

WI WI Profit/Year Income Oper Cost Loss .2002 $ 0 $ 10,160 ($ 10,160)2003 $ 8,641 $ 175,718 ($ 167,077)2004 $ 28,621 $ 105,446 ($ 76,825)2005 $ 53,755 $ 71,171 ($ 17,416)2006 $ 98,370 $ 119,439 ($ 21,069)

Total $ 189,387 $ 481,934 ($ 292,547)

Summary of Operating CostsSummary of Operating Costs

Summary• Oil displaced by CO2 injection is being produced from

offset leases• Oil production from CO2 pilot lease appears to be

stable• Estimated oil recovery attributed to CO2 injection

from all leases may approach 12 MCF/BBL by the end of 2007

• Current reservoir model does not represent reservoir heterogeneity correctly based on field response

• Little contribution from CO2#13~1 B/D poor connection to CO2 I-1

Project ManagementBudget Period II-2007

• Project is not economic even with DOE cost share• 95% of the CO2 remains in the LKC C zone reservoir

interval• Maintain pressure in pilot area above MMP(1250 psi) • Inject water into CO2I-1 to continue mobilization of oil

by displacing the carbon dioxide• Document oil production from Colliver A Lease that can

be attributed to CO2 displacement(no economic benefit to some of the WI owners)

• Produce defendable estimates of oil recovery based on oil in the tank

Scrh =0.25

SwCO2 = 0.45

SgCO2=0.30

CO2 Bank

SoCH= 0.148SCO2h=0.102

So=0.40

Sw=0.60

Oil Bank

Sorw=0.3

Sw=0.70

Displacement Model During CO2 InjectionPiston-Like Displacement

Scrh =0.25

SwCO2 = 0.45

SgCO2=0.30

CO2 Bank

SoCH= 0.148SCO2h=0.102

So=0.40

Sw=0.60

Oil Bank

Sorw=0.3

Sw=0.70

S CO

2t=0

.15 Sw=0.60

ΔSo=0.30-0.148=0.152

Carbon dioxide rich

hydrocarbon phase

Water Bank

Displacement Model During Water InjectionPiston-Like Displacement

0

5000

10000

15000

20000

25000

30000

35000

40000

0 20000 40000 60000 80000 100000 120000 140000 160000 180000 200000Volume of Water Injected, RB

Volu

me

of O

il D

ispl

aced

,RB

Oil Displaced by CO2

End of CO2 Displacement

Water Injection-March31,2007

Recovery of Mobilized Oilby Water Injection

Mobilization of Oil byDisplacement of Carbon Dioxide by Injection of Water

Piston-Like Displacement Model

0

50

100

150

200

250

300

350

0 20000 40000 60000 80000 100000 120000 140000 160000 180000 200000Volume of Water Injected, RB

Oil

Dis

plac

ed, R

B/A

F

Oil Displaced, RB/AFEnd of Oil Mobilization by CO2Water Injection-March 31, 2007

;Mobilization of Oil byDisplacement of Carbon Dioxide by Injection of Water

Recovery of Mobilized Oilby Water Injection

Piston-Like Displacement Model

Project ManagementBudget Period II-2007

• Operate project until effective displacement ends in pilot and adjacent leases-at least until 12-31-2007 based on current projections

• Revise reservoir description to improve capability of reservoir model to match and predict production

• Consider the possibility of expanding the project to commercial scale

Project Expansion• 5.85 MMCFD of CO2 is available at the Russell CO2

plant• Average injection rate of 245 MCFD would support 24

injection wells not considering recycle• Substantial remaining residual oil in adjacent leases• Adjacent leases are owned by operators who may be

willing to participate in a large scale project• Hundreds of royalty interest holders• Field scale project (~600 acres) would be required to

approach economic operation

L-KC Recoveries in Hall-Gurney and Trapp

> 8 MBO/acre

6-8 MBO/acre

4-6 MBO/acre

2-4 MBO/acre

Cumulative ProductionPrimary + SecondaryLansing-Kansas City(Per Section Basis)

Trapp

Hall-Gurney

Pilot Site

Kansas Geological Survey

Proposed Field Scale Expansion-2001

Funding Possibilities for Commercial Application

• High risk will require either venture capital or cost sharing-current operator looking for financial support

• Independent interest in carbon sequestration credits may make it possible to construct and operate a CO2 pipeline to Hall Gurney with acceptable CO2 costs for economic operation

• CO2 sequestration has been demonstrated. Potential funding for CO2 sequestration demonstration projects?

(Scholle & James, 1995)

Modern Ooid Shoal,Great Bahama Banks

LKC Oomoldic Limestone pervasive across KS Shelf

and similar worldwide

L-KC CO2 I #1 2903 ft

•Early pore cementation•Ooid dissolution•Crushing

Total Magnetic Field IntensityReduced to Pole Russell County, Kansas

CO2 Project

Structure Top Plattsburg Limestone

CO2 Project

0

20

feet

Gross Pay Plattsburg Limestone

-1204

-1148

CO2 Project

Structural lineaments

feet

1 mi. C.I. = 1 ft.

C.I. = 2 ft.

Attribute Analysis on Baseline DataAttribute Analysis on Baseline DataTTime structural map (red highs)ime structural map (red highs)

SSimilarity imilarity ““seismic faciesseismic facies”” map map white poorer reservoir white poorer reservoir properties properties

suggestive of a complex ooid shoal depositional suggestive of a complex ooid shoal depositional motif, which is supported by oolitic lithofacies motif, which is supported by oolitic lithofacies being the known reservoir in this intervalbeing the known reservoir in this interval

Colliver #16 core: Bedsets, grain size range2 3 4 5 6 7

2882

2884

2886

2888

2890

2892

2894

2896

2898

2900

2902

2904

Bed #

vc c-m f-vf mud

Bedset #4:Cap- well sortedLower-Poorly sorted

Bedset #5:Top– 3 cm thick

beds w/bioclast capsLower-micritic clasts,

bioclasts, superficialoolite

Bedset #6:Poorly sorted, openmarine bioclasticpackstone to wackest.

Bedset #3:Top-coarse, well sortedLower-poorly sorted

w/bioclasts

Bedset #2:3-fining up, well sorted1-coarsening up, well sorted1-fining up, less well sorted Better

sortedcapping strataon

bedsets

Thin bedsets

5

4

3

2

Small-scalebeds notedas breaks

Largest to smallestgrain size

Shoa

l 2Sh

oal 1

Sec 28 Sec 27

Sec 33 Sec 34

CO2 #1

Shoa

l #1

Shoa

l #2

Shoa

l #3

Sec. 28

Sec. 33

-1130

-1150

-1160

North South

N

S

T.B Carter #10T.B Carter #2C. Colliver #18C. Colliver #CO2-1 Colliver #13Colliver #2Giese 7

2a 2 1

Low GR, higher Ø

Ooid shoal unit

Structural profile at top Plattsburg Ls.

- Prograde from north, moving stratigraphically updip to south?- Leading edge on north is capped by cleaner oolite in Colliver #2- Geise #7 location has shalier interval, located structurally downdip,

possibly lower energy (too low for major oolite fm.); labeled 2a- Shoal unit #1 on south side on structurally highest position

suggesting early onset of ooid shoal development prior to shoals #2 & 3

Up stratigraphic section

K.M. Carter #1 T.B. Carter #11 T.B. Carter #5 #CO2-1 Colliver #9 H. Rein #A-5

-1150

-1160

-1170

Sec. 28

Sec. 33

SW NE

-- Uniform oolite development in shoal unit #2 characterized by low GR, similar thickness, and Ø.

-- Section along central core of NE-trending shoal

-- Uniformity suggest that section lies within more continuous prograding trajectory

-- Generally thinning upstructure to northeast

-- Also, steady SW dip of section along flank of structural saddle

-- Northeast end that is structurally high also has shoal unit #1 developed SW

NE

Structural profile at top Plattsburg Ls.

Low GR, higher ØOoid shoal unit

2 221

1000 ft (300 m)

-1167

-1153

-1167

-1153

Seismic lineament Seismic lineament

NW

SE

Colliver #10Colliver #7 Colliver #CO2-1Colliver #4 Colliver #16Colliver #9

32 2

1

Low GR, higher Ø

Ooid shoal unit

Structural profile at top Plattsburg Ls.

* Colliver #4 – (cuttings) dominant fine gr. tight ooid grainstone* Colliver #7 – (cuttings) bioclastic with interparticle Ø, forams, crinoids, encrusters; 40% ooid* Colliver #CO2-1 and Colliver #16 (upper) –(cored) oomoldic grainstone, clean porous (shoal #2); Shoal #1 in well #16; finer grained and less permeable, lower permeability; higher perm in Shoal #2.

Correlation of individual ooid shoals

Thickness of low GR interval

Sec 28 Sec 27

Sec 33 Sec 34

CO2 #1

Structure Contour Map, Top Plattsburg Limestone

Shoa

l #1

Shoa

l #2

Shoa

l #3

Sec 28 Sec 27

Sec 33 Sec 34

CO2 #1

Shoa

l #1

Shoa

l #2

Shoa

l #3

Isopach of upper Plattsburg Ls. Sequence