Graduation Year

2019

Document Type

Dissertation

Degree

Ph.D.

Degree Name

Doctor of Philosophy (Ph.D.)

Degree Granting Department

Chemical Engineering

Major Professor

Scott W. Campbell, Ph.D.

Co-Major Professor

Jeffrey A. Cunningham, Ph.D.

Committee Member

Dharendra Y. Goswami, Ph.D.

Committee Member

John N. Kuhn, Ph.D.

Committee Member

Eric L. Sonnenthal, Ph.D.

Keywords

Carbon Sequestration, Geochemistry, NO2, Disproportionation Reaction, Storage Efficiency, Salinity, Gas Saturation, SO2, Reactive Transport, Solubility Trapping

Abstract

Geological carbon sequestration in a saline formation is a promising technology for large-scale carbon dioxide (CO2) mitigation. Several factors such as temperature, pressure, salinity, hydraulic conductivity, and mineralogy of a formation affect the CO2 sequestration in saline formations. These factors can vary widely depending upon the type of formation or the degree of heterogeneity within a formation. In addition to these properties of the repositories, the CO2-rich flue gas streams captured from point sources often contains small amounts of impurities such as sulfur oxides (SOx) and nitrogen oxides (NOx), which may have serious implications on the chemistry of the repositories during geological carbon storage. Carbonate minerals which are abundant in saline formations are more responsive than silicate minerals to these geochemical reactions. Therefore, the overall objective of this dissertation is to assess the impact of salinity, temperature, and trace gases (SO2 and NO2) on geological carbon sequestration in deep saline carbonate aquifers. The overall goal is achieved through five specific goals: 1) evaluating a modeling tool to simulate geological carbon storage in high-salinity carbonate formations, 2) estimating the effect of brine salinity on geological carbon storage, 3) estimating the effect of formation temperature on geological carbon storage, 4) estimating the effect of SO2 co-injection on the storage, and 5) estimating the effect of NO2 and SO2-NO2 co-injection on the storage.

For the first specific goal, the suitability of TOUGHREACT 3.0/ECO2N (https://tough.lbl.gov/software/toughreact) has been assessed for modeling geological carbon storage in a deep saline carbonate formation. Based on the assessment, TOUGHREACT/ECO2N has been used for the simulations in rest of the goals.

For rest of the goals, injection of CO2 into a deep saline aquifer comprised of calcite, anhydrite, and dolomite have been simulated. For goal 2 and goal 3, brine salinity and formation temperature were varied respectively. For goal 4 and goal 5, mole % of trace gases co-injected with the CO2 were varied. The effects of the varying conditions on the volume of CO2 stored, changes in pH of brine, and precipitation and dissolution of minerals have been assessed.

Results from the study suggests that low salinity favors the solubility trapping of CO2 with better storage efficiency (goal 2). For goal 3, the storage efficiency decreases with increase in temperature. However, the solubility trapping of CO2 increases with increase in temperature due to higher interfacial area between brine and gas/supercritical phase. Formation temperature and salinity don’t have large impact on acidification of brine or porosity of the formation due to dissolution and precipitation of the minerals.

Co-injection of SO2 forms sulfuric acid and leads to more acidification of brine than pure CO2. Also, it further leads to higher precipitation of anhydrite (goal 4) in the SO2 outreach zone and causes a lower net increase in porosity as compared to pure CO2. In the case of CO2- NO2 co-injection, the acidification of brine or pH change is similar to goal 4 but the precipitation of anhydrite is similar as in case of pure CO2. In fact, the net increase in porosity increases with increase in NO2 concentration. In CO2-SO2-NO2 co-injection, the net increase in porosity decreases with increase in SO2 concentration in the trace gas.

Overall, the results from the study suggests that CO2 can be successfully sequestered in the temperature range of 35-95 °C and salinity range of 1-15% NaCl (by weight). Also, co-injecting the trace gases along with CO2 is technically feasible with acceptable changes in mineralogy. The co-injection of trace gases adds economic benefit for sustainable and dedicated geological carbon storage.

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