Bureau of Economic Geology

Gulf Coast Carbon Center

WaterRF Project: Background

State of Knowledge

One of the important approaches being considered for mitigating greenhouse gases (GHGs) is sequestration of CO2 in deep geologic formations. Injection of CO2 into brine formations is being considered highly favorably because of the large storage capacity estimated to range globally from 350 to 1,000 Gt of CO2 (Holloway, 2001; IPCC, 2005). The widespread occurrence of brine formations in the U.S. greatly increases the likelihood that such formations are located adjacent to major CO2 sources (Figure 1). According to the 2005 U.S. Government Energy Information Administration (EIA), Texas is the eighth-largest emitter of CO2 in the world, emitting 0.6 billion m3 of CO2. The large emissions result from Texas being a leading producer of energy, as well as supporting large petrochemical industries. However, the Gulf Coast has the potential to serve as the leading carbon sequestration sink in the U.S., with 4.5 billion m3 of storage in Gulf Coast brine formations (Figure 2).

Figure 1

Figure 1. Distribution of CO2 sources (power plants and pure sources) and sinks (brine formations ≥1,000 m deep) in the U.S. Darker shades of green indicate deeper brine formations. (Source: Gulf Coast Carbon Center).

Geologic sequestration literature, such as the IPCC Special Report (2005) and the U.S. Department of Energy (DOE) Carbon Sequestration Road Map (DOE, 2007), divides sequestration sites into three main types: depleted hydrocarbon reservoirs, brine-bearing "saline" formations, and unminable coal seams. Unminable coal seams are clearly a separate type of storage, having a distinctive trapping mechanism and requiring their own types of capacity and risk assessment. However, hydrocarbon reservoirs are a subset of regional brine formations, representing the parts of the formation in which geometry and fluid migration coincided so that economically significant hydrocarbon was able to accumulate. Hydrocarbon reservoirs are formed by the same types of rocks and have the same types of seals as their host brine formations; CO2 will move through and be trapped in essentially the same manner in both.

Figure 2

Figure 2. CO2 storage potential of different saline formations in southeastern U.S. Storage potential of the Gulf Coast saline formation system is estimated to be 4.5 billion m3.

One of the critical issues with respect to CO2 sequestration in brine formations is the potential impact of such storage on fresh groundwater in overlying aquifers. One way in which CO2 sequestration in deep brine formations can impact aquifers is by perturbing the flow field in the deep aquifer, which could result in brines or brackish water being pushed updip into unconfined sections of the same formations or into the capture zone of fresh-water wells. This issue was examined in the Gulf Coast system by Nicot (2008) using groundwater modeling. Results of this analysis indicate that injection of water, equivalent to 50 million tons of CO2/yr for 50 yr resulted in an average water-table rise of ~1 m and no significant increase in groundwater salinity (Nicot, 2008).

Geologic sequestration can also impact fresh-water aquifers by leakage of CO2 occurring through the caprock or through preferential pathways, such as faults and wells, especially abandoned wells. Upward leakage of CO2 from deep geologic sequestration reservoirs can impact groundwater quality by transporting deep brines and associated naturally occurring contaminants into the aquifer and/or by mobilizing contaminants within the aquifer through related groundwater pH reduction (Keating et al., 2009). These processes can alter many aspects of groundwater chemistry, resulting in exceedances of primary and/or secondary Environmental Protection Agency (EPA) Maximum Contaminant Levels (MCLs). Many of the studies that evaluate potential impacts of CO2 leakage into aquifers are based on modeling analyses. Wang and Jaffe (2004) suggested that pH reduction from CO2 leakage would result in large concentrations of Pb as a result of dissolution of galena. The negative impacts of CO2 leakage are greatly reduced in aquifers with high alkalinity and pH buffering capacity such as those containing calcite. Wang and Jaffe (2004) also suggested that high trace-metal concentrations in an aquifer may be used as an indicator of CO2 leakage above deep geologic sequestration sites. However, information on mineral dissolution kinetics, which strongly controls simulated trace-metal concentrations, is limited. Reactive transport modeling of CO2 input into an aquifer for 100 yr by Zheng et al. (in press) indicates that CO2 leakage could mobilize As and Pb through mineral dissolution. This study used 38,000 groundwater chemical analyses from aquifers throughout the U.S. and identified potential mineral hosts containing hazardous trace metals. However, As concentrations rarely exceeded the EPA MCL of 10 ug/L and Pb concentrations never exceeded the MCL. An increase in leakage rate leads to increases in partial pressure of CO2 and, consequently, lower pH and higher maximum contaminant concentrations in the aquifer.

Apps et al. (2009) used the same data set and found that the most serious problem from CO2 leakage resulted from enhanced pyrite dissolution and release of As. At the highest p(CO2) used in the simulations (1 bar), Ba, Pb, and Zn also approached or exceeded regulatory limits. The simulations indicated that Cd and Zn are unlikely to be exceeded and Hg, Se, and U concentrations are unaffected by CO2 leakage. Modeling analyses by Carroll et al. (2009) indicate that CO2 leakage can be detected by pH changes and carbonate chemistry in aquifers. The ability to detect CO2 leakage from a storage reservoir into overlying dilute groundwater depends on CO2 solubility, leakage flux, CO2 buoyancy, and groundwater flow. However, Zheng et al. (in press) pointed out that all modeling analyses are subject to considerable uncertainty inherent in geochemical parameters and that quantitative predictions of CO2 leakage impacts would require integration of modeling with detailed laboratory and field studies to test model assumptions and parameters. Most modeling studies attribute trace-element mobilization related to CO2 input into aquifers to mineral solubilization; however, evaluation of trace-element distributions in natural aquifers suggests that the primary mechanism for releasing trace elements is desorption from Fe or Mn (oxy)hydroxides (Smedley and Kinniburgh, 2002; Smedley et al., 2005; Scanlon et al., 2009). It is not clear that the actual processes causing trace-element mobilization in aquifers are being evaluated in the modeling studies.

A variety of approaches can be used to assess impacts of CO2 leakage from deep reservoirs on overlying groundwater quality in aquifers, including natural analogs, laboratory and field tests, and numerical modeling. Each approach has advantages and disadvantages. Aquifers adjacent to volcanic aquifers or that receive CO2 from geothermal sources may provide suitable natural analogs for CO2 leakage (Federico et al., 2004; Keating et al., 2009). One of the problems with a natural analog is that it may be difficult to distinguish upward flow of contaminants in brine that is moving with the CO2 from contaminants mobilized within the aquifer as a result of CO2 injection. Studies at a sandstone aquifer in New Mexico indicate that pH changes resulting from CO2 influx were buffered by high alkalinity and carbonate mineral dissolution, whereas increased As, Pb, and U were attributed to leakage of brine with the CO2 based on high correlations between these elements and Cl (Keating et al., 2009). However, in other areas it may be difficult to distinguish impacts of upward brine migration from in situ mobilization of contaminants in the aquifer.

Batch experiments have been conducted in the laboratory to evaluate potential impacts of CO2 on water chemistry. Lu et al. (in press) examined impacts of CO2 on rock samples from major aquifers in Texas, including the Ogallala and Gulf Coast aquifers. Both carbonate and silicate systems were examined. Results indicate that all major and trace elements increase as a result of CO2 injection; however, the increase represents a transient pulse. In carbonate systems pH increases are buffered by carbonate mineral dissolution, whereas in silicate systems, pH decreases sharply because it is not buffered. Silica increases in both carbonate and silicate systems. In carbonate systems, Ca and Mg concentrations level off after a time. Mineral dissolution rates are much slower in silicate systems.

To date, specific field experiments have not been conducted to evaluate impacts of CO2 leakage on groundwater quality. Field tests have been conducted to assess impacts of deep geologic sequestration. Single-well push-pull tests were conducted in deep basalts in New York and showed that carbonic acid from CO2 was neutralized by carbonate dissolution and cation exchange (Assayag et al., 2009).


Click here for "RI0283. Geological CO2 Sequestration Atlas of Miocene Strata, Offshore Texas State Waters"


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