WATER-CO2-OIL INTERACTIONS IN THE MORROW B SANDSTONE OF THE FARNSWORTH, TEXAS HYDROCARBON FIELD: IMPLICATIONS FOR CO2 SEQUESTRATION

The Morrow B Sandstone in the Farnsworth, Texas hydrocarbon field has been the subject of an ongoing case study by the Southwest Partnership for CO₂ Sequestration to determine the behavior of CO₂ injected into hydrocarbon-bearing clastic media. Numerical reactive transport modeling based on past and projected fluid injection histories and rigorous geologic characterizations has yielded insights into these behaviors. The results are sensitive to uncertainties in model parameters, particularly relative permeability and capillary pressure, but some general patterns have emerged. The models predicted little change in the pressure or temperature of the Morrow B as a result of a ten-year period of fluid injection. However, the injected CO₂ temporarily reduced the pH of the formation water from near neutral to as low as 4.7. Plumes of immiscible CO₂ developed within a few tens to hundreds of meters of the wells during injection, but disappeared within a few decades after injection ceased. The CO₂ that dissolved into the Morrow B formation water was largely advected beyond the western boundary of the Farnsworth field within a few centuries. Much of the injected CO₂ also dissolved into oil. CO₂-charged formation waters dissolved native formation minerals like albite, ankerite, chlorite, and illite. Quartz and kaolinite were predicted to precipitate. Dolomite, calcite, and siderite were predicted to be minor mineral sinks for injected CO₂, and on the whole, carbonate mineral precipitation exceeded carbonate mineral dissolution. However, mineral precipitation and dissolution were predicted to have minimal effect on the porosity and permeability of the Morrow B. Current limitations of the models include the absence of geomechanical effects of CO₂ injection on the Morrow B or the dissolution of petroleum into the formation water, but are priorities for future work.