Richard A. Esposito

Effect of dissolved CO2 on a shallow groundwater system: a controlled release field experiment.

Capturing carbon dioxide (CO(2)) emissions from industrial sources and injecting the emissions deep underground in geologic formations is one method being considered to control CO(2) concentrations in the atmosphere. Sequestering CO(2) underground has its own set of environmental risks, including the potential migration of CO(2) out of the storage reservoir and resulting acidification and release of trace constituents in shallow groundwater. A field study involving the controlled release of groundwater containing dissolved CO(2) was initiated to investigate potential groundwater impacts. Dissolution of CO(2) in the groundwater resulted in a sustained and easily detected decrease of ~3 pH units. Several trace constituents, including As and Pb, remained below their respective detections limits and/or at background levels. Other constituents (Ba, Ca, Cr, Sr, Mg, Mn, and Fe) displayed a pulse response, consisting of an initial increase in concentration followed by either a return to background levels or slightly greater than background. This suggests a fast-release mechanism (desorption, exchange, and/or fast dissolution of small finite amounts of metals) concomitant in some cases with a slower release potentially involving different solid phases or mechanisms. Inorganic constituents regulated by the U.S. Environmental Protection Agency remained below their respective maximum contaminant levels throughout the experiment.

The cross-scale science of CO2 capture and storage: from pore scale to regional scale

We describe state-of-the-art science and technology related to modeling of CO2 capture and storage (CCS) at four different process scales: pore, reservoir, site, and region scale. We present novel research at each scale to demonstrate why each scale is important for a comprehensive understanding of CCS. Further, we illustrate research linking adjacent process scales, such that critical information is passed from one process scale to the next adjacent scale. We demonstrate this cross-scale approach using real world CO2 capture and storage data, including a scenario managing CO2 emissions from a large U.S. electric utility. At the pore scale, we present a new method for incorporating pore-scale surface tension effects into a relative permeability model of CO2-brine multiphase flow at the reservoir scale. We benchmark a reduced complexity model for site-scale analysis against a rigorous physics-based reservoir simulator, and include new system level considerations including local site-scale pipeline routing analysis (i.e., reservoir to site scale). We also include costs associated with brine production and treatment at the site scale, a significant issue often overlooked in CCS studies. All models that comprise our total system include parameter uncertainty which leads to results that have ranges of probability. Results suggest that research at one scale is able to inform models at adjacent process scales, and that these scale connections can inform policy makers and utility managers of overall system behavior including the impacts of uncertainty.

Potential CO2 Leakage Reduction through Biofilm-Induced Calcium Carbonate Precipitation

Mitigation strategies for sealing high permeability regions in cap rocks, such as fractures or improperly abandoned wells, are important considerations in the long term security of geologically stored carbon dioxide (CO(2)). Sealing technologies using low-viscosity fluids are advantageous in this context since they potentially reduce the necessary injection pressures and increase the radius of influence around injection wells. Using aqueous solutions and suspensions that can effectively promote microbially induced mineral precipitation is one such technology. Here we describe a strategy to homogenously distribute biofilm-induced calcium carbonate (CaCO(3)) precipitates in a 61 cm long sand-filled column and to seal a hydraulically fractured, 74 cm diameter Boyles Sandstone core. Sporosarcina pasteurii biofilms were established and an injection strategy developed to optimize CaCO(3) precipitation induced via microbial urea hydrolysis. Over the duration of the experiments, permeability decreased between 2 and 4 orders of magnitude in sand column and fractured core experiments, respectively. Additionally, after fracture sealing, the sandstone core withstood three times higher well bore pressure than during the initial fracturing event, which occurred prior to biofilm-induced CaCO(3) mineralization. These studies suggest biofilm-induced CaCO(3) precipitation technologies may potentially seal and strengthen fractures to mitigate CO(2) leakage potential.

Deployment models for commercialized carbon capture and storage.

Even before technology matures and the regulatory framework for carbon capture and storage (CCS) has been developed, electrical utilities will need to consider the logistics of how widespread commercial-scale operations will be deployed. The framework of CCS will require utilities to adopt business models that ensure both safe and affordable CCS operations while maintaining reliable power generation. Physical models include an infrastructure with centralized CO(2) pipelines that focus geologic sequestration in pooled regional storage sites or supply CO(2) for beneficial use in enhanced oil recovery (EOR) and a dispersed plant model with sequestration operations which take place in close proximity to CO(2) capture. Several prototypical business models, including hybrids of these two poles, will be in play including a self-build option, a joint venture, and a pay at the gate model. In the self-build model operations are vertically integrated and utility owned and operated by an internal staff of engineers and geologists. A joint venture model stresses a partnership between the host site utility/owners engineer and external operators and consultants. The pay to take model is turn-key external contracting to a third party owner/operator with cash positive fees paid out for sequestration and cash positive income for CO(2)-EOR. The selection of a business model for CCS will be based in part on the desire of utilities to be vertically integrated, source-sink economics, and demand for CO(2)-EOR. Another element in this decision will be how engaged a utility decides to be and the experience the utility has had with precommercial R&D activities. Through R&D, utilities would likely have already addressed or at least been exposed to the many technical, regulatory, and risk management issues related to successful CCS. This paper provides the framework for identifying the different physical and related prototypical business models that may play a role for electric utilities in commercial-scale CCS.

Fracture Sealing with Microbially-Induced Calcium Carbonate Precipitation: A Field Study

A primary environmental risk from unconventional oil and gas development or carbon sequestration is subsurface fluid leakage in the near wellbore environment. A potential solution to remediate leakage pathways is to promote microbially induced calcium carbonate precipitation (MICP) to plug fractures and reduce permeability in porous materials. The advantage of microbially induced calcium carbonate precipitation (MICP) over cement-based sealants is that the solutions used to promote MICP are aqueous. MICP solutions have low viscosities compared to cement, facilitating fluid transport into the formation. In this study, MICP was promoted in a fractured sandstone layer within the Fayette Sandstone Formation 340.8 m below ground surface using conventional oil field subsurface fluid delivery technologies (packer and bailer). After 24 urea/calcium solution and 6 microbial (Sporosarcina pasteurii) suspension injections, the injectivity was decreased (flow rate decreased from 1.9 to 0.47 L/min) and a reduction in the in-well pressure falloff (>30% before and 7% after treatment) was observed. In addition, during refracturing an increase in the fracture extension pressure was measured as compared to before MICP treatment. This study suggests MICP is a promising tool for sealing subsurface fractures in the near wellbore environment.