Thermal effects on geologic carbon storage

The final publication is available at Springer via http://dx.doi.org/10.1016/j.earscirev.2016.12.011One of the most promising ways to significantly reduce greenhouse gases emissions, while carbon-free energy sources are developed, is Carbon Capture and Storage (CCS). Non-isothermal effects play a major role in all stages of CCS. In this paper, we review the literature on thermal effects related to CCS, which is receiving an increasing interest as a result of the awareness that the comprehension of non-isothermal processes is crucial for a successful deployment of CCS projects. We start by reviewing CO2 transport, which connects the regions where CO2 is captured with suitable geostorage sites. The optimal conditions for CO2 transport, both onshore (through pipelines) and offshore (through pipelines or ships), are such that CO2 stays in liquid state. To minimize costs, CO2 should ideally be injected at the wellhead in similar pressure and temperature conditions as it is delivered by transport. To optimize the injection conditions, coupled wellbore and reservoir simulators that solve the strongly non-linear problem of CO2 pressure, temperature and density within the wellbore and non-isothermal two-phase flow within the storage formation have been developed. CO2 in its way down the injection well heats up due to compression and friction at a lower rate than the geothermal gradient, and thus, reaches the storage formation at a lower temperature than that of the rock. Inside the storage formation, CO2 injection induces temperature changes due to the advection of the cool injected CO2, the Joule-Thomson cooling effect, endothermic water vaporization and exothermic CO2 dissolution. These thermal effects lead to thermo-hydro-mechanical-chemical coupled processes with non-trivial interpretations. These coupled processes also play a relevant role in “Utilization” options that may provide an added value to the injected CO2, such as Enhanced Oil Recovery (EOR), Enhanced Coal Bed Methane (ECBM) and geothermal energy extraction combined with CO2 storage. If the injected CO2 leaks through faults, the caprock or wellbores, strong cooling will occur due to the expansion of CO2 as pressure decreases with depth. Finally, we conclude by identifying research gaps and challenges of thermal effects related to CCS.Peer ReviewedPostprint (author's final draft

Expert-based development of a standard in CO2 sequestration monitoring technology

Bureau of Economic Geolog

Frictional Instabilities and Carbonation of Basalts Triggered by Injection of Pressurized H2O- and CO2- Rich Fluids

The safe application of geological carbon storage depends also on the seismic hazard associated with fluid injection. In this regard, we performed friction experiments using a rotary shear apparatus on precut basalts with variable degree of hydrothermal alteration by injecting distilled H2O, pure CO2, and H2O + CO2fluid mixtures under temperature, fluid pressure, and stress conditions relevant for large-scale subsurface CO2storage reservoirs. In all experiments, seismic slip was preceded by short-lived slip bursts. Seismic slip occurred at equivalent fluid pressures and normal stresses regardless of the fluid injected and degree of alteration of basalts. Injection of fluids caused also carbonation reactions and crystallization of new dolomite grains in the basalt-hosted faults sheared in H2O + CO2fluid mixtures. Fast mineral carbonation in the experiments might be explained by shear heating during seismic slip, evidencing the high chemical reactivity of basalts to H2O + CO2mixtures

Geomechanical Response Of Overburden Caused By CO2 Injection Into A Depleted Oil Reservoir

This study investigates the hydro-mechanical aspects of carbon dioxide (CO2) injection into a depleted oil reservoir through the use of coupled multiphase fluid flow and geomechanical modeling. Both single-phase and multiphase fluid flow analyses coupled with geomechanics were carried out at the West Pearl Queen depleted oil reservoir site, and modeling results were compared with available measured data. The site geology and the material properties determined on the basis of available geophysical data were used in the analyses. Modeling results from the coupled multiphase fluid flow and geomechanical analyses show that computed fluid pressures match well with available measured data. The hydro-mechanical properties of the reservoir have a significant influence on computed fluid pressures and surface deformations. Hence, an accurate geologic characterization of the sequestration site and determination of engineering properties are important issues for the reliability of model predictions. The computed fluid pressure response is also significantly influenced by the relative permeability curves used in multiphase fluid flow models. While the multiphase fluid flow models provide more accurate fluid pressure response, single-phase fluid flow models can be used to obtain approximate solutions. The ground surface deformations obtained from single-phase fluid flow models coupled with geomechanics are slightly lower than those predicted by multiphase fluid flow models coupled with geomechanics. However, the advantage of a single-phase model is the simplicity. Limited field monitoring of subsurface fluid pressure and ground surface deformations during fluid injection can be used in calibrating coupled fluid flow and geomechanical models. The calibrated models can be used for investigating the performance of large-scale CO2 storage in depleted oil reservoirs

Coupled geomechanical reservoir simulation

Founded by Department Of Energy, the Plains CO₂ Reduction (PCOR) Partnership is investigating the Williston Basin as a candidate for sequestering CO₂ emissions from power plants. The State of Missouri, a member of PCOR, lies at the outermost point on the proposed transportation route and consequently faces the highest CO₂ compression and transportation costs. In order to minimize the cost of CO₂ sequestration, it is desirable to find a storage site within the state. The Lamotte sandstone is identified as a suitable sequestration aquifer formation in Missouri with acceptable permeability, porosity, extension, rock strength and water salinity. Using the finite element analysis package ABAQUS for the geomechanical analysis and the fluid flow simulator Eclipse for pore pressure determination, this work looks at pore pressure - stress coupling which has significant implications for failure mechanism, fault reactivation and caprock integrity. The present work also suggests the use of Pressure Transient Analysis (PTA) to quantify the lateral fluid flow boundary type and differentiating between open, closed and infinite systems. The present work also suggests a new boundary condition, Semi-Open, which is a transitional lateral boundary condition between Fully Open and Closed boundary conditions. Results of the present work provide a coupling module that can be used to conduct coupled geomechanical analysis for CO₂ sequestration projects, facilitate the building of 3D mechanical earth models and provide insight into the role of boundary conditions with respect to CO₂ storage capacity. The coupling procedure is utilized to evaluate CO₂ storage potential and assess the geomechanical risks for CO₂ sequestration in a candidate storage site in the North-Eastern part of the state of Missouri for sustainable CO₂ sequestration --Abstract, page iv

Modeling of caprock seal failure due to fluid injection

The past, present, and projected trends of increasing carbon dioxide (CO2) concentration levels in the atmosphere have raised serious concerns about global warming. Several efforts are being made to stabilize the current levels of CO2 emissions. Geologic sequestration of CO2 in deep saline aquifers is considered to be one of the potential options to reduce greenhouse gas emissions in the atmosphere. A tight, low-permeability caprock layer overlying the CO2-targeted reservoir limits the upward migration of CO2 and acts as a primary seal layer to trap CO 2. Large volumes of fluid or CO2 injected in the subsurface may over-pressurize the reservoir and increase the potential for mechanical seal failure. Such a scenario could lead to CO2 leakage with time.;In the present study, coupled single-phase and multi-phase fluid flow and geomechanical models were constructed to investigate the fluid flow and ground deformation behavior. Axisymmetric and three-dimensional fluid flow and deformation models were constructed. Coupled multi-phase fluid flow and deformation modeling was used to estimate the maximum sustainable injection pressure. Coupled multi-phase fluid flow and geomechanical models were also used to investigate the mechanical seal failure caused by CO2 injection. A parametric study was conducted on the geomechanical failure properties that cause shear failure in the caprock layer during CO2 injection. Parametric study of geomechanical properties such as cohesion, angle of friction and permeability show that these material properties have significant influence on shear failure of caprock layer. Also, finite element techniques were used to model shear failure of an inclined fracture or a fault zone during fluid injection. Results show the development of plastic strains when injected fluid migrates to the fault zone

Numerical study of underground CO2 storage and the utilization in depleted gas reservoirs

The emission of atmospheric CO2 is the main contributor to global warming and climate change. Carbon capture and storage (CCS) is considered as the most promising technology for slowing down the atmospheric CO2 emissions. Meanwhile, CCS is beneficial for the circulation carbon economy. However, CCS has not been implemented on large scale because of the related risks and the lack of economic incentives. This thesis attempts to focus on these two problems and provide some strategies to address them. Regarding the risks associated with CCS, a parametric uncertainty analysis for CO2 storage was conducted and the general role of different geomechanical and hydrogeological parameters in response to CO2 injection was determined. Regarding the financial incentives of CCS operation, this thesis attempts to increase the cost-effectiveness of CCS through co-injecting CO2 with impurities associated with enhanced gas recovery (CSEGR) and using CO2 as cushion gas in the underground gas storage reservoir (UGSR). In order to understand the thermal-hydrological-mechanical (THM) process of CO2 storage, the THM coupled simulator TOUGH2MP (TMVOC)-FLAC3D was developed. By using the developed TOUGH2MP (TMVOC)-FLAC3D simulator, numerical simulation for hundreds of sampled data was performed for results generated by the Quasi-Monte Carlo method. Based on the simulation results, the general role of different geomechanical and hydrogeological parameters was determined in response to CO2 injection using distance correlation. In addition, a risk factor was defined to characterize the risks of the caprock due to CO2 injection. The results showed that the reservoir permeability and the injection rate are the two most important factors in determining the pressure change. Moreover, the reservoir Young’s modulus plays the most vital role in formation deformation including vertical displacement. The pressure change exhibits a much closer correlation with the risk factor in comparison to the formation deformation, indicating the importance of pressure change in the integrity assessment of the caprock. By using the machine learning approach in support vector regression (SVR), the SVR surrogate model was well-trained based on the data regarding simulated results, and its reliability was verified using the test data. Thereafter, the formation response including the pressure change as well as formation deformation, can be predicted using the trained SVR surrogate model within a very short time. The methods and working scheme applied in this work can be used to guide time and effort spent mitigating the uncertainty in these parameters to acquire trustworthy model forecasts and risk assessments in CCS projects. Attempting to decrease the cost of CCS operation, CO2 injection with impurity gas, i.e., N2 and O2, into a depleted gas reservoir was investigated. The impacts of the key parameters on the performance of CO2 storage and CSEGR were analyzed in detail. The results showed that the effect of impurities on CO2 storage capacity is dependent on the reservoir pressure and temperature conditions, and the concentration of impurities. The depleted gas reservoir with a relatively low temperature and low irreducible water saturation is favorable to the CO2 storage capacity. A low primary gas recovery for the depleted gas reservoir is in favor of CSEGR, while it is suitable for dedicated CO2 storage when the primary gas recovery is high. In addition, it is suggested to produce the CH4 as possible before the operation of CO2 storage and CSEGR. The chromatographic partitioning phenomenon may occur when N2 and O2 were co-injected with CO2 into depleted gas reservoirs, which could be used as a monitoring strategy for the CO2 front and potential CO2 leakage. In addition to the solubility and concentration of the impurity gas would affect this phenomenon, there is a critical water saturation for the occurrence of significant chromatographic partitioning phenomenon associated with determined type and concentration of impurity gas. To increase the cost-effectiveness of CCS, the suitability of utilizing CO2 as the cushion gas in the UGSR was analyzed based on the geological parameters of Donghae depleted gas reservoir in Korea. The cyclic CH4 production and injection were conducted over a period of 15 years to acquire the mixing behavior of CO2 and CH4 in a relatively long-term period. The results showed that the maximum CO2 concentration that can be used for cushion gas is 9% under the condition of production and injection for 120 and 180 days in a production cycle at a rate of 4.05 and 2.7 kg/s, respectively. The typical curve of the mixing zone thickness can be divided into four stages, i.e., the increasing stage, smooth stage, suddenly increasing stage, and periodic change stage. The CO2 fraction in the UGSR, reservoir permeability, and production rate have a significant effect on the breakthrough of CO2 in the production well, while the effect of water saturation and temperature is neglectable. For the purpose of utilizing more CO2 as cushion gas in the UGSR, CO2 is supposed to be injected for supplementation during the operation of UGSR. Generally, the parametric uncertainty analysis conducted in this thesis is beneficial for the risk assessments in CCS projects. Co-injecting CO2 with impurities associated with CSEGR and utilizing CO2 as cushion gas in UGSR are favorable for improving the economic incentives of CCS operation. Therefore, this thesis is beneficial for promoting the application of CCS and mitigating the atmospheric CO2 emissions