Investigation of Geochemical Interactions of Carbon Dioxide and a Carbonate Formation in the Northwest McGregor Oil Field after Enhanced Oil Recovery and CO2 Storage

University ofNorth Dakota

Grand Forks

EERCEnergy & Environmental Research Center®

Putting Research into Practice

PCOR2222Partnership

The live water pH measurement service offered by Oilphase DBR was performed before the stimulation. On injection of dye into the sample at reservoir pressure and temperature, it was determined that the pH value of the sample is expected to be <4.5 units at 2600 psia and 225°F.

Conclusions 1. The fluid samples recovered before and after CO2 injection with Schlumberger’s E-line technique and analyzed by Oilphase-DBR and various geochemical modeling techniques illustrated:

- Unusually low (< 4.5) pH readings - Very consistent dataset which proved to be viable and applicable for further modeling - Very high concentration of dissolved solids (around 300,000 mg/kg of water)

2. Results of the equilibrium modeling further indicated that the analyzed water is in equilibrium or near-equilibrium state with the Mississippian Formation minerals: anhydrite, calcite, dolomites, pyrite, and illite.

3. Modeling suggests low reactivity of the reservoir rocks with the injected CO2 and in situ brine. However, minor mineralogical changes, such as minor dissolution of calcite and dolomite minerals, are predicted to occur. The kinetic and mass-transfer modeling illustrated the dynamics of the possible mineralogical changes. It was observed that the next thermodynamically stable point can be reached in nearly 7 years after the CO2 injection.

4. The numerical modeling results are in agreement with the laboratory study. In addition, the low precipitation of hematite was observed in laboratory conditions, as a result of minor ankerite dissolution.

Authors: Yevhen I. Holubnyak, Blaise A. F. Mibeck, Jordan M. Bremer, Steven A. Smith, James A. Sorensen, Charles D. Gorecki, Edward N. Steadman, and John A. Harju

Abstract Injection of carbon dioxide (CO2) for the purpose of enhanced oil recovery is widely regarded as one of the key commercial applications of geological storage and provides valuable insight into other large-scale projects aimed at reducing CO2 emissions to the atmosphere. The Plains CO2 Reduction (PCOR) Partnership, one of the seven U.S. Department of Energy National Energy Technology Laboratory Regional Carbon Sequestration Partnerships, is conducting a project in the Northwest McGregor oil field in North Dakota to determine the effects CO2 has on the productivity of the reservoir, wellbore integrity, and the carbonate formation into which the CO2 was injected. The method used in this project was huff ‘n’ puff whereby 440 tons of supercritical CO2 was injected into a well over a 2-day period and allowed to “soak” for a 2-week period. The well was subsequently put back into production to recover incremental oil. This paper outlines the approach and current observations derived from numerical modeling and laboratory simulations of potential geochemical reactions to evaluate the short-term risks for operations (e.g., porosity and permeability decrease) and long-term implications for CO2 storage via mineralization. The integration of data obtained during mineralogical analyses, fluid sampling, and laboratory experiments proved to be a key for better understanding the dynamic geochemical processes which happen in the reservoir after CO2 injection and was necessary for successful completion of the numerical modeling. Results of the numerical modeling suggest that the already acidic and highly saline environment (pH <4.5 and total dissolved solids ~300,000 mg/kg) of the Northwest McGregor oil field should not experience any significant changes in mineralogy as a result of CO2 injection, especially in the near term, which correlates with the postinjection field geochemical analyses.

McGregorField

E. Goetz #1 well – InjectionE.L. Gudvangen #1 well – Observation

SaukField

TempleField

Divide County

Williams County

Burke County

Mountrail County

SaskatchewanNorth Dakota

Montana

Sheridan County

Roosevelt County

Location

Reservoir Modeling

Reservoir CharacteristicsProducing Formation Mission Canyon

Lithology Primarily limestone

Average Porosity 15%

Matrix Permeability 0.35 mD

Secondary Permeability Fractures

Depth from Surface to Pay 8050 ft/2434 m

Average Temperature 216°F/102°C

Original Discovery Reservoir Pressure 3127 psig/216 bar

Preinjection Reservoir Pressure 2700 psig/186 bar

Oil Gravity (API) 41.7°

Cumulative Oil Production 2.2 million STB

Reservoir Geochemistry

14.0

13.5

13.0

12.5

12.0

11.5

11.0

10.5

10.0

9.5

9.0

Mineral (calcite) (gmole)

2,47

02,

460

2,45

02,

440

2,43

0

100 200

0.00

0.00

120.00

40.00 80.00 meters

240.00 feet

CO2 Injector

0.15280

0.15274

0.15268

0.15261

0.15255

0.15249

0.15243

0.15237

0.15231

0.15225

0.15219

Porosity – Current

2,47

02,

460

2,45

02,

440

2,43

0

100 200

0.00

0.00

120.00

40.00 80.00 meters

240.00 feet

CO2 Injector

45.00

44.90

44.79

44.69

44.58

44.48

44.38

44.27

44.17

44.06

43.96

2,47

02,

460

2,45

02,

440

2,43

0

100 200

Mineral (dolomite) (gmole)

0.00

0.00

120.00

40.00 80.00 meters

240.00 feet

CO2 Injector

14.0

13.5

13.0

12.5

12.0

11.5

11.0

10.5

10.0

9.5

9.0

Mineral (calcite) (gmole)

2,47

02,

460

2,45

02,

440

2,43

0

100 200

0.00

0.00

120.00

40.00 80.00 meters

240.00 feet

CO2 Injector

0.15280

0.15274

0.15268

0.15261

0.15255

0.15249

0.15243

0.15237

0.15231

0.15225

0.15219

Porosity – Current

2,47

02,

460

2,45

02,

440

2,43

0

100 200

0.00

0.00

120.00

40.00 80.00 meters

240.00 feet

CO2 Injector

45.00

44.90

44.79

44.69

44.58

44.48

44.38

44.27

44.17

44.06

43.96

2,47

02,

460

2,45

02,

440

2,43

0

100 200

Mineral (dolomite) (gmole)

0.00

0.00

120.00

40.00 80.00 meters

240.00 feet

CO2 Injector

14.0

13.5

13.0

12.5

12.0

11.5

11.0

10.5

10.0

9.5

9.0

Mineral (calcite) (gmole)

2,47

02,

460

2,45

02,

440

2,43

0

100 200

0.00

0.00

120.00

40.00 80.00 meters

240.00 feet

CO2 Injector

0.15280

0.15274

0.15268

0.15261

0.15255

0.15249

0.15243

0.15237

0.15231

0.15225

0.15219

Porosity – Current

2,47

02,

460

2,45

02,

440

2,43

0

100 200

0.00

0.00

120.00

40.00 80.00 meters

240.00 feet

CO2 Injector

45.00

44.90

44.79

44.69

44.58

44.48

44.38

44.27

44.17

44.06

43.96

2,47

02,

460

2,45

02,

440

2,43

0

100 200

Mineral (dolomite) (gmole)

0.00

0.00

120.00

40.00 80.00 meters

240.00 feet

CO2 Injector

pH Density

g/cm3 Conductivity

at 25˚C,mS/cm

Resistivity at 77 ˚F

Salinity TDS, mg/kg

5.55 (at 106˚F) 4.50 (at 216˚F – live pH) 4.23 (modeled)

1200 2 49 4 .02 283,855 2 92,863

12.47

35.42

47.01

3.43

57.93

0.04

36.89

2.69

0

10

20

30

40

50

60

70

CO2 H2S N CH4 C2H6 C3H8

Mol

e %

Before Inj.4 months after Inj.

Measured concentration of some gases in the reservoir before and after stimulation.

9153 8

15712 6

256

484

1362 9

102

103

4125

1147

1042200

1061678

589

8875 3

15661 1

326

438

513

1890 0

237

424652

1338

7

1781

2420

740

1.E+01 .E+2 1.E+41 .E+6

Na

Cl

B

Ba

Br

HCO3

Ca

Cu

F

Fe

K

Li

Mg

Mn

NH4

P

Pb

SO4

Si

Sr

4 Months After Inj.Before Inj.

7800

7900

8000

8100

Vclay

VLime

VDol

VAnhydrite

VSand

VPyrite

Salt

Voil

Vwater

Spatial 2-D distribution of the calcite and dolomite dissolution and insignificant porosity increase modeled 10 years after injection.