Monitoring a large volume CO2 injection: Year two results from SECARB project at Denbury’s Cranfield, Mississippi, USA

Tuscaloosa Marine Shale: Seal or Source? Petrophysical Comparative Study of Wells in SE Louisiana and SW Mississippi

The Tuscaloosa Marine Shale (TMS) is a versatile Late Cretaceous shale formation present in central and SE Louisiana and SW Mississippi, which drew attention because of the various roles played within the Tuscaloosa Group. In this paper, it is debated whether the Tuscaloosa Marine Shale can act as a source, reservoir, or seal all throughout the shale play or only in certain areas. Well log and core data from Adams County, Mississippi, are compared to data from East Feliciana Parish in Louisiana. Conclusions were drawn based on the results of well log analysis, X-ray Diffraction (XRD), porosity–permeability measurements, programmed pyrolysis, and fracture analysis. It was shown that the Tuscaloosa Marine Shale interval in SE Louisiana consists of important amounts of calcite, exhibits multiple natural fractures, has porosity values as high as 9.3%, and shows a TOC content of up to 2.8 wt%. On the other hand, samples from a well at the Cranfield field, MS, are characterized by considerably lower TOC values of around 0.88 wt%, porosities between 0.33% and 4%, and no serious fracturing. The formation demonstrates better reservoir and source potential in SE Louisiana and reliable CO2 sealing capacity in SW Mississippi. The analysis presented in this paper represents a holistic approach to the characterization of shale formations, is applicable to other plays around the world, and can be used as an integral part of CO2 sequestration or hydraulic fracturing programs.

Impacts of Methane on Carbon Dioxide Storage in Brine Formations

In the context of geological carbon sequestration (GCS), carbon dioxide (CO₂ ) is often injected into deep formations saturated with a brine that may contain dissolved light hydrocarbons, such as methane (CH₄ ). In this multicomponent multiphase displacement process, CO₂ competes with CH₄ in terms of dissolution, and CH₄ tends to exsolve from the aqueous into a gaseous phase. Because CH₄ has a lower viscosity than injected CO₂ , CH₄ is swept up into a 'bank' of CH₄ -rich gas ahead of the CO₂ displacement front. On the one hand, this may provide a useful tracer signal of an approaching CO₂ front. On the other hand, the emergence of gaseous CH₄ is undesirable because it poses a leakage risk of a far more potent greenhouse gas than CO₂ if the cap rock is compromised. Open fractures or faults and wells could result in CH₄ contamination of overlying groundwater aquifers as well as surface emissions. We investigate this process through detailed numerical simulations for a large-scale GCS pilot project (near Cranfield, Mississippi) for which a rich set of field data is available. An accurate cubic-plus-association equation-of-state is used to describe the non-linear phase behavior of multiphase brine-CH₄ -CO₂ mixtures, and breakthrough curves in two observation wells are used to constrain transport processes. Both field data and simulations indeed show the development of an extensive plume of CH₄ -rich (up to 90 mol%) gas as a consequence of CO₂ injection, with important implications for the risk assessment of future GCS projects.

Hydrochemical variations in selected geothermal groundwater and carbonated springs in Korea: a baseline study for early detection of CO2 leakage

A baseline hydrochemistry of the above zone aquifer was examined for the potential of CO₂ early detection monitoring. Among the major ionic components and stable isotope ratios of oxygen, hydrogen, and carbon, components with a relative standard deviation (RSD) of <10 % for the seasonal variation were selected as relatively stable. These components were tested for sensitivity to the introduction of 0.1 mol/L CO₂ (g) using the PHREEQC simulation results. If the relatively stable components were sensitive to the introduction of CO₂, then they could be used as indicators of CO₂ leakage into the above zone. As an analog to the zone above CO₂ storage formation, we sampled deep groundwater, including geothermal groundwater from well depths of 400-700 m below the ground surface (bgs) and carbonated springs with a high CO₂ content in Korea. Under the natural conditions of inland geothermal groundwater, pH, electrical conductivity (EC), bicarbonate (HCO₃), δ¹⁸O, δ²H, and δ¹³C were relatively stable as well as sensitive to the introduction of CO₂ (g), thus showing good potential as monitoring parameters for early detection of CO₂ leakage. In carbonated springs, the parameters identified were pH, δ¹⁸O, and δ²H. Baseline hydrochemistry monitoring could provide information on parameters useful for detecting anomalies caused by CO₂ leakage as measures for early warning.

Viability and adaptation potential of indigenous microorganisms from natural gas field fluids in high pressure incubations with supercritical CO2

Carbon Capture and Storage (CCS) is currently under debate as large-scale solution to globally reduce emissions of the greenhouse gas CO2. Depleted gas or oil reservoirs and saline aquifers are considered as suitable reservoirs providing sufficient storage capacity. We investigated the influence of high CO2 concentrations on the indigenous bacterial population in the saline formation fluids of a natural gas field. Bacterial community changes were closely examined at elevated CO2 concentrations under near in situ pressures and temperatures. Conditions in the high pressure reactor systems simulated reservoir fluids i) close to the CO2 injection point, i.e. saturated with CO2, and ii) at the outer boundaries of the CO2 dissolution gradient. During the incubations with CO2, total cell numbers remained relatively stable, but no microbial sulfate reduction activity was detected. After CO2 release and subsequent transfer of the fluids, an actively sulfate-respiring community was re-established. The predominance of spore-forming Clostridiales provided evidence for the resilience of this taxon against the bactericidal effects of supercritical (sc)CO2. To ensure the long-term safety and injectivity, the viability of fermentative and sulfate-reducing bacteria has to be considered in the selection, design, and operation of CCS sites.