Investigation of Geochemical Interactions of Carbon Dioxide and a Carbonate Formation in the Northwest McGregor Oil Field after Enhanced Oil Recovery and CO 2 Storage University of North Dakota Grand Forks EERC Energy & Environmental Research Center ® Putting Research into Practice P CO R 2 2 Partnership 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 CO 2 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 CO 2 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 CO 2 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 (CO 2 ) 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 CO 2 emissions to the atmosphere. The Plains CO 2 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 CO 2 has on the productivity of the reservoir, wellbore integrity, and the carbonate formation into which the CO 2 was injected. The method used in this project was huff ‘n’ puff whereby 440 tons of supercritical CO 2 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 CO 2 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 CO 2 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 CO 2 injection, especially in the near term, which correlates with the postinjection field geochemical analyses. McGregor Field E. Goetz #1 well – Injection E.L. Gudvangen #1 well – Observation Sauk Field Temple Field Divide County Williams County Burke County Mountrail County Saskatchewan North Dakota Montana Sheridan County Roosevelt County Location Reservoir Modeling Reservoir Characteristics Producing 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) 2,470 2,460 2,450 2,440 2,430 100 200 0.00 0.00 120.00 40.00 80.00 meters 240.00 feet CO 2 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 2,470 2,460 2,450 2,440 2,430 100 200 0.00 0.00 120.00 40.00 80.00 meters 240.00 feet CO 2 Injector 45.00 44.90 44.79 44.69 44.58 44.48 44.38 44.27 44.17 44.06 43.96 2,470 2,460 2,450 2,440 2,430 100 200 Mineral (dolomite) (gmole) 0.00 0.00 120.00 40.00 80.00 meters 240.00 feet CO 2 Injector pH Density g/cm 3 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 CO 2 H 2 S N CH 4 C 2 H 6 C 3 H 8 Mole % 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 9 102 103 412 5 114 7 104 220 0 106 167 8 589 8875 3 15661 1 326 438 513 1890 0 237 424 6 52 133 8 7 178 1 242 0 740 1.E+01 .E+2 1.E+41 .E+6 Na Cl B Ba Br HCO 3 Ca Cu F Fe K Li Mg Mn NH 4 P Pb SO 4 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.