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The Midwest Regional Carbon Sequestration Partnership (MRCSP) is implementing a commercial-scale carbon capture and storage (CCS) project in multiple Silurian carbonate pinnacle reefs in northern Michigan that are in various phases of enhanced oil recovery. This paper presents analyses of five pressure fall-off tests performed sequentially during the injection of 166,000 tonnes of CO 2 into a Type-1 (depleted) reef which has undergone primary and secondary production. Bottom-hole pressures were monitored in the injection well and in two observation wells to record progressively increasing reservoir pressure during the injection period, which also included five fall-off tests. Pressure data were analyzed using combined history-matching and pressure derivative matching techniques implemented with a commercial well-test interpretation program, FAST WellTest™. The paper illustrates the challenges of consistently interpreting CO 2 injection fall-off tests under multi-phase flow with varying pressure conditions using a single-phase analytical model. This work is relevant to CO 2 sequestration in depleted oil reservoirs because regular fall-off testing is required under the U.S. Environmental Protection Agency's Underground Injection Control (UIC) Program for CO 2 geologic sequestration (75 FR 77230). [ABSTRACT FROM AUTHOR]

Abstract Carbon sequestration is an important measure to reduce greenhouse gas emissions. This paper introduces a new method of carbon sequestration using CO 2 waterless fracturing technology. Based on the supporting technology system with independent intellectual property rights, waterless fracturing field tests were carried out on 19 wells in Jilin oilfield. The on-site monitoring data shows that CO 2 stays in a supercritical state for a long time in the process of waterless fracturing, soaking and flowback, which is favourable for carbon sequestration. The geological model of H87 test area was established to simulate and evaluate CO 2 recovery after fracturing. The results show that the storage ratio of CO 2 waterless fracturing is 76.46%. Meanwhile, the production after waterless fracturing is 2.4 times that after water-based fracturing with the same scale, and the average single well operation saves 1512 m3 water. It can be seen that CO 2 waterless fracturing is a new type of carbon sequestration technology with high storage efficiency, good stimulation effect, significantly reduction of water consumption during oil and gas reservoir development and has broad market prospects. [ABSTRACT FROM AUTHOR]

Defining the ideal suite of monitoring technologies to be deployed at a carbon capture and storage (CCS) site presents a challenge to project developers, financers, insurers, regulators and other stakeholders. The monitoring, verification, and accounting (MVA) toolkit offers a suite of technologies to monitor an extensive range of parameters across a wide span of spatial and temporal resolutions, each with their own degree of sensitivity to changes in the parameter being monitored. Understanding how best to optimize MVA budgets to minimize the time to leak detection could help to address issues around project risks, and in turn help support broad CCS deployment. This paper presents a case study demonstrating an application of the Designs for Risk Evaluation and Management (DREAM) tool using an ensemble of CO 2 leakage scenarios taken from a previous study on leakage impacts to groundwater. Impacts were assessed and monitored as a function of pH, total dissolved solids (TDS), and trace metal concentrations of arsenic (As), cadmium (Cd), chromium (Cr), and lead (Pb). Using output from the previous study, the DREAM tool was used to optimize monitoring system designs based on variable sampling locations and parameters. The algorithm requires the user to define a finite budget to limit the number of monitoring wells and technologies deployed, and then iterates well placement, sensor type and location until it converges on the configuration with the lowest time to first detection of the leak averaged across all scenarios. To facilitate an understanding of the optimal number of sampling wells, DREAM was used to assess the marginal utility of additional sampling locations. Based on assumptions about monitoring costs and replacement costs of degraded water, the incremental cost of each additional sampling well can be compared against its marginal value in terms of avoided aquifer degradation. Applying this method, DREAM identified the most cost-effective ensemble with 14 monitoring locations. While this preliminary study applied relatively simplistic cost and technology assumptions, it provides an exciting proof-of-concept for the application of DREAM to questions of cost-optimized MVA system design that are informed not only by site-specific costs and technology options, but also by reservoir simulation results developed during site characterization and operation. [ABSTRACT FROM AUTHOR]

Large-scale pressure increases resulting from carbon dioxide (CO 2 ) injection in the subsurface can potentially impact caprock integrity, induce reactivation of critically stressed faults, and drive CO 2 or brine through conductive features into shallow groundwater. Pressure management involving the extraction of native fluids from storage formations can be used to minimize pressure increases while maximizing CO 2 storage. However, brine extraction requires pumping, transportation, possibly treatment, and disposal of substantial volumes of extracted brackish or saline water, all of which can be technically challenging and expensive. This paper describes a constrained differential evolution (CDE) algorithm for optimal well placement and injection/extraction control with the goal of minimizing brine extraction while achieving predefined pressure contraints. The CDE methodology was tested for a simple optimization problem whose solution can be partially obtained with a gradient-based optimization methodology. The CDE successfully estimated the true global optimum for both extraction well location and extraction rate, needed for the test problem. A more complex example application of the developed strategy was also presented for a hypothetical CO 2 storage scenario in a heterogeneous reservoir consisting of a critically stressed fault nearby an injection zone. Through the CDE optimization algorithm coupled to a numerical vertically-averaged reservoir model, we successfully estimated optimal rates and locations for CO 2 injection and brine extraction wells while simultaneously satisfying multiple pressure buildup constraints to avoid fault activation and caprock fracturing. The study shows that the CDE methodology is a very promising tool to solve also other optimization problems related to GCS, such as reducing ‘Area of Review’, monitoring design, reducing risk of leakage and increasing storage capacity and trapping. [ABSTRACT FROM AUTHOR]

Natural gas is considered a cleaner and lower-emission fuel than coal, and its high abundance from advanced drilling techniques has positioned natural gas as a major alternative energy source for the U.S. However, each ton of CO 2 emitted from any type of fossil fuel combustion will continue to increase global atmospheric concentrations. One unique approach to reducing anthropogenic CO 2 emissions involves coupling CO 2 based enhanced gas recovery (EGR) operations in depleted shale gas reservoirs with long-term CO 2 storage operations. In this paper, we report unique findings about the interactions between important shale minerals and sorbing gases (CH4 and CO 2 ) and associated economic consequences. Where enhanced condensation of CO 2 followed by desorption on clay surface is observed under supercritical conditions, a linear sorption profile emerges for CH4. Volumetric changes to montmorillonites occur during exposure to CO 2 . Theory-based simulations identify interactions with interlayer cations as energetically favorable for CO 2 intercalation. In contrast, experimental evidence suggests CH4 does not occupy the interlayer and has only the propensity for surface adsorption. Mixed CH4:CO 2 gas systems, where CH4 concentrations prevail, indicate preferential CO 2 sorption as determined by in situ infrared spectroscopy and X-ray diffraction techniques. Collectively, these laboratory studies combined with a cost-based economic analysis provide a basis for identifying favorable CO 2 -EOR opportunities in previously fractured shale gas reservoirs approaching final stages of primary gas production. Moreover, utilization of site-specific laboratory measurements in reservoir simulators provides insight into optimum injection strategies for maximizing CH4/CO 2 exchange rates to obtain peak natural gas production. [ABSTRACT FROM AUTHOR]

Numerical simulation is an invaluable analytical tool for scientists and engineers in making predictions about of the fate of carbon dioxide injected into deep geologic formations for long-term storage. Current numerical simulators for assessing storage in deep saline formations have capabilities for modeling strongly coupled processes involving multifluid flow, heat transfer, chemistry, and rock mechanics in geologic media. Except for moderate pressure conditions, numerical simulators for deep saline formations only require the tracking of two immiscible phases and a limited number of phase components, beyond those comprising the geochemical reactive system. The requirements for numerically simulating the utilization and storage of carbon dioxide in partially depleted petroleum reservoirs are more numerous than those for deep saline formations. The minimum number of immiscible phases increases to three, the number of phase components may easily increase fourfold, and the coupled processes of heat transfer, geochemistry, and geomechanics remain. Public and scientific confidence in the ability of numerical simulators used for carbon dioxide sequestration in deep saline formations has advanced via a natural progression of the simulators being proven against benchmark problems, code comparisons, laboratory-scale experiments, pilot-scale injections, and commercial-scale injections. This paper describes a new numerical simulator for the scientific investigation of carbon dioxide utilization and storage in partially depleted petroleum reservoirs, with an emphasis on its unique features for scientific investigations. The mathematical foundations of this new simulator for enhanced oil recovery are those of the simulators developed for carbon sequestration in deep saline reservoirs, altered to consider the increased number of potential phases and compositional aspects by considering the oil in the system. As a demonstration of the simulator, a numerical simulation of carbon dioxide utilization for enhanced oil recovery in the western section of the Farnsworth Unit, representing an early stage in the progression of numerical simulators for carbon utilization and storage in depleted oil reservoirs. [ABSTRACT FROM AUTHOR]

This paper is inspired by theory related to the water-food-energy-climate nexus and suggests a novel model, suited for analysing carbon sequestration in dry land agriculture using irrigation. The model is applied specifically to photovoltaic water pumping (PVWP) systems for irrigation of grasslands in China. We argue against the narrow approaches to analysing the water issue often found in literature and propose that carbon sequestration, energy security, food security together with local moisture recycling patterns should be included within the system boundary in order to make analyses of dry land agricultural activities more relevant and accurate. [ABSTRACT FROM AUTHOR]