H13K-01
Changes in Shallow Groundwater Chemistry Following CO2 Injection at the ZERT Field Site, Bozeman, Montana
Approximately 300 kg/day of food-grade CO2 was injected through a perforated pipe placed horizontally 2-2.3 m deep during July 9-August 7, 2008 at the MSU-ZERT field test to evaluate atmospheric and near- surface monitoring and detection techniques applicable to the subsurface storage and potential leakage of CO2. As part of this multidisciplinary research project, we collected 80 samples of water from 10 shallow observation wells (1.5 or 3.0 m deep) located 1-6 m from the injection pipe, and from two distant monitoring wells. The samples were collected before, during and following CO2 injection. Field determinations of pH, alkalinity, conductance and DO, showed rapid, systematic and significant to major changes following CO2 injection, especially in samples collected from the 1.5 m wells. The collected samples are being analyzed in the laboratory for major, minor and trace cations, metals and anions, as well as DOCs, VOCs and some isotopes. Results obtained to date show major increases in the concentrations of Ca (from 90 to 200 mg/L) Mg (25 to 70 mg/L), Fe (5 to 1000 ppb) and Mn (5 to 1200 ppb) following CO2 injection. Dissolution of carbonate minerals and desorption-ion exchange resulting from lowered pH values of groundwater (from 7.0 to 5.8) following CO2 injection, are the likely processes responsible for the observed increases in the concentrations of cations and anions. The concentrations decreased temporarily following the four significant precipitation events that occurred during sampling. The DOC values obtained are generally about 4 mg/L, with a range from 2.6 to 6.9 mg/L; the variations do not seem related to CO2 injection. The injection of CO2, however, is clearly responsible for the lowered pH values, mobilization of metals and increases in the values for Ca, Mg, alkalinity and conductance of shallow groundwater
H13K-02
Geoelectric Monitoring Studies for the Carbon Dioxide Geological Storage
Self-potential (SP) anomalies of negative polarity are frequently observed near deep wells. These anomalies appear to be caused by an underground electrochemical mechanism similar to a galvanic cell: the metallic well casing acts as a vertical electronic conductor connecting regions of differing redox potential. Electrons flow upward though the casing from a deeper reducing environment to a shallower oxidizing environment, and simultaneously a compensating vertical flow of ions is induced in the surrounding formation to maintain charge neutrality. If the redox potential in the deeper region is then increased by injecting an oxidizing substance, the difference in redox potential between the shallower and deeper regions will be reduced, resulting in an SP increase near the wellhead. We have been monitoring earth-surface SP during gas injection tests at various sites in Japan. When air was injected into a 100-meter well within a geothermal field, a remarkable simultaneous increase in SP centered on the wellhead was observed. A small but unmistakable SP increase also took place near the wellhead when CO2 was slowly injected, which we believe was caused by local pH reduction at depth resulting from dissolution of the injected CO2 in the aquifer fluid. SP changes were also observed in Yubari, geological sequestration test site in Japan, where one well injected CO2 into a coal bed and the fluid containing CH4 was produced from a nearby well. The CO2 content of the fluid was also monitored. SP increased substantially around the injection wellhead, but no significant SP changes attributable to the injection were observed near the production wellhead. This is consistent with the observation that CO2 did not break through into the production well during the experiment. We believe that SP measurements at the earth surface represent a new and promising technique for sensing the approach of CO2 to well casings deep within the subsurface.
H13K-03
Gas Membrane Sensor Technique for in-situ Downhole Detection of Gases Applied During Geological Storage of CO2
The geological storage of CO2 in deep saline aquifers is regarded as a possible technology for the reduction of anthropogenic greenhouse gases. However, comprehensive research is still needed to better understand the behaviour of CO2 during and after storage. Therefore, we developed and applied a new, innovative geochemical monitoring tool for the real time and in-situ determination of CO2 and other gases in the underground and in bore holes. The method uses a phase separating silicone membrane, permeable for gases, in order to separate gases dissolved in borehole fluids, water and brines. Argon is used as a carrier gas to conduct the collected gases through capillaries to the surface. Here, the gas phase is analyzed in real-time with a portable mass spectrometer for all permanent gases. In addition, gas samples may be collected for detailed investigations in the laboratory. Downhole extraction and on-line determination of gases dissolved in brines using this gas membrane sensor (GMS) technique was successful applied at the scientific CO2SINK test site in Ketzin, Germany (sandstone aquifer). GMSs together with temperature and pressure probes were installed in two approx. 700m deep observation holes, drilled in 50m and 100m distance from the CO2 injection well. Hydraulic pressure in the observation wells rose gradually during injection of CO2. Increasing reservoir gas concentrations of helium, hydrogen, methane, and nitrogen as well as the arrival of the added krypton tracer were determined shortly before the injected CO2 appeared. The breakthrough of CO2 into the observation well, in 50m distance, was recorded after 531.5 tons of CO2 were injected.
H13K-04
Isotopic Approaches to Evaluate the Fate of Injected CO2 in Two Geological Storage Projects in Mature Oilfields in Canada
Monitoring and verification of CO2 storage is an essential component of geological storage projects. We present evidence from two enhanced oil recovery projects in Canada that geochemical and isotopic techniques can be successfully used to trace the fate of injected CO2. Geochemical and isotopic data for fluids and gases obtained from multiple wells at the International Energy Agency Greenhouse Gas Weyburn CO2 Monitoring and Storage Project (Saskatchewan, Canada) and from the Penn West Pembina Cardium CO2-Enhanced Oil Recovery Monitoring Pilot (Alberta, Canada) were collected before and throughout the CO2 injection phase. Carbon isotope ratios of injected CO2 in the Weyburn project were significantly lower than those of background CO2 in the reservoir. In contrast, carbon isotope ratios of injected CO2 at Penn West's Pembina Cardium CO2-Enhanced Oil Recovery Monitoring Pilot were markedly higher than those of background CO2. After commencement of CO2 injection, the concentrations and carbon isotope values of CO2 and HCO3- in fluids and gases repeatedly obtained from monitoring wells were determined. Increasing CO2 and HCO3- concentrations in concert with carbon isotope values trending towards those of the injected CO2 revealed effective solubility and ionic trapping of injected CO2 at several monitoring wells at both study sites. In addition, changes in the oxygen isotope values of reservoir fluids provided independent evidence for dissolution of injected CO2 in the produced waters. We conclude that geochemical and isotopic monitoring techniques can play an essential role in verification of CO2 storage provided that the isotopic composition of the injected CO2 is distinct.
H13K-05
Midwest Regional Carbon Sequestration Partnership Appalachian Basin Test Site: Developing a Sequestration Site from Concept through Injection
The Midwest Regional Carbon Sequestration Partnership (MRCSP) Appalachian Basin Field Test is located at the First Energy Generation Corp. RE Burger Power Plant in Belmont County, Ohio. The goal at this site is to injection up to 3000 tonnes of carbon dioxide in up to three separate geologic formations. We present the development of this injection plan as more data was collected and added to the system. In addition, we present initial injection results. Site characterization consisted of a regional geological assessment and a 2D seismic survey. A test injection well (FEGENCO 1) was completed in early 2007 and data collected from this well, included geophysical wireline logs and core samples, were used to develop an injection plan. Two previously identified injection targets were analyzed, the Devonian Oriskany Sandstone and the Silurian Clinton Sandstone. Both of these sandstones are regional sequestration targets across the Midwestern United States. In addition to these, a third injection target was identified after drilling. The Silurian Salina Group is regionally extensive throughout most of the Midwest and consists of carbonate and evaporate layers. In the FEGENCO 1 well, one of the subgroups was found to have higher porosity dolomitic stringers sandwiched between anhydrite layers. Wireline data and field samples were used to better understand the geologic model and predict the porosity and permeability distribution of the interval. Injection is expected to be completed by Fall 2008. This work was done as part of the Midwest Regional Carbon Sequestration Partnership (MRCSP); DOE/NETL Cooperative Agreement No. DE-FC26-05NT42589
H13K-06
Coupled flow and mechanical simulation as an aid in monitoring overburden pressure during geologic carbon sequestration
The development of monitoring technologies for carbon sequestration is a key element to reducing risks to acceptable levels. A key need for such technology is the development of simulation tools that can help interpret the monitoring data that are gathered. As carbon dioxide is injected into a formation, the pressures within that formation and in overlying and underlying rock formations change, both due to the transmission of pressure within the fluid and rock mediums. As demonstrated in previous studies, the overburden pressure response depends on the permeability of the target formation and surrounding rock layers and the geomechanical properties of surrounding strata. The pressure response in an overlying reservoir layer may be an indicator of the presence of absence of carbon dioxide migration outside of the target reservoir. In this study, several hypothetical cases of fractures in the cap rock were considered. A "monitoring layer" in the overburden is defined as a highly permeable layer above the primary caprock. This study tests the variation in pressure response in the monitoring layer in the presence and absence of a fracture in the caprock. An overburden response during injection of carbon dioxide was simulated by considering coupled flow and deformation behavior within the nearby rock strata. Since the pressure response is perpetrated through the brine much faster than the CO2, single-phase flow assumptions were used to simplify the calculations. Several parameters, such as fracture and matrix permeabilites, elastic moduli, layer thicknesses, and fracture location were varied to test the effect on pressure response. The results from this and further studies can be useful in the development of monitoring techniques for evaluating long-term performance of carbon storage sites.
H13K-07 INVITED
Lessons Learned from Ongoing Field Tests of Geologic CO2 Sequestration
We present lessons learned – an attempt to describe what we know and do not know– based on ongoing field tests of geologic carbon sequestration. The Southwest Regional Partnership on Carbon Sequestration, funded by the U.S. Department of Energy and managed by DOE's National Energy Technology Laboratory, is conducting three separate field tests of geologic sequestration that include extensive monitoring and analysis of the fate of injected CO2. The CO2 injection sites include the Aneth oilfield in southern Utah, the coalbed "fairway" in the San Juan basin in northern New Mexico, and the SACROC oilfield in the Permian basin of west Texas. Results of the ongoing sequestration field tests are both encouraging and problematic. At the San Juan basin coalbed injection test, we forecasted coalbed swelling following injection to be detectable at the surface. Tiltmeter results indicated subsidence, not uplift, and poroelastic models of the site suggest that swelling is likely occurring, but cleat compaction may be responsible for the net subsidence. In a similar context, initial poroelastic models of the Aneth, Utah injection site suggested minimal rock strain would be induced by the 100,000 tons of CO2 injected over the past year, but this forecast is belied by daily microearthquakes recorded at the site (albeit very small events: M -1 to 0 ). On the other hand, our initial multiphase flow models of the Aneth site provided forecasts of CO2 migration that turned out to be extremely consistent with observed tracer test results, suggesting that our estimated permeability distributions and other model parameters were effective to some extent. These field tests suggest that probably the greatest challenges are (1) verification or confirmation of trapping mechanisms, and (2) monitoring of processes in the "intermediate zone," the section of strata above the sequestration formation topseal unit and below the upper 100 m of the section, (3) developing meaningful geologic characterization with sparse data, (4) developing meaningful risk assessment frameworks, especially quantification of consequences of "failed" sequestration. For example, regarding verification of trapping mechanisms, we developed detailed, quantitative forecasts of trapping mechanisms, including hydrostratigraphic trapping, solubility trapping, residual gas trapping and mineral trapping, for the SACROC field, using models calibrated with 30 years of past CO2 injection data. However, verifying these forecasts is next to impossible.