Geologic Storage Reservoirs Research Articles

Research Progress on CO2 Geological Storage Reservoir and Caprock Mechanics: Methods and Status

ABSTRACTGreenhouse gas (GHG) emissions have caused serious global climate change, and countries worldwide are taking steps to mitigate the greenhouse effect caused by carbon emissions. CO2 geological storage (CGS) is emerging as a large‐scale technology for reducing GHG emissions and is gradually becoming one of the most important means of mitigating the greenhouse effect. There are several problems in the implementation of this technology, among which the geomechanical problems caused by injection sequestration cannot be ignored. This article reviews the impacts and hazards of geomechanical problems caused by injection and sequestration in CGS, which can lead to risks, including changes in reservoir and caprock mechanical properties, reservoir stability, caprock closure, fault activation, and induced seismicity during CO2 injection and sequestration. This article reviews the above studies and summarizes the research methods of CGS geomechanical problems and generation mechanisms, which can help to comprehensively understand the risks faced in the CGS process and provide references and guidance for the operation, monitoring, and research of CGS in the future.

Graph theory based estimation of probable CO2 plume spreading in siliciclastic reservoirs with lithological heterogeneity

Estimating plume spreading in geological CO2 storage reservoirs is critical for several reasons including the assessment of pore space utilization efficiency, preferential CO2 migration pathways and trapping. However, plume spreading critically depends on lithological heterogeneity of the reservoir and CO2 injection rate. It might require numerous high fidelity full physics numerical simulations to constrain the uncertainty in plume spreading for a given reservoir. This might not always be practical due to computational limitations. Hence, reduced physics approaches, such as invasion-percolation method and machine learning, could be useful to answer certain questions on plume spreading in the subsurface. This study presents a new reduced physics approach based on graph theory for estimating probable CO2 plume migration under very low and very high injection rates. The two end-member scenarios are assessed by performing random walk in the 3D reservoir space to constrain 20,000 possible paths of CO2 flow away from the injection well. The resistance to CO2 flow associated with each path is computed for viscous, capillary and gravity forces. The resistances are then transformed into the likelihood of CO2 migration along the path. The algorithm was applied to 45 reservoir models with varying degrees of lithological heterogeneity and the results were compared to those from full physics and invasion percolation simulations. The graph theory results showed a close match with the results from full physics approach for both flow regimes and with results from invasion-percolation approach for capillary-gravity dominated flow regime. The algorithm was further applied to answer key questions on reservoir screening such as pore space utilization potential. The graph theory approach was also integrated with machine learning to predict CO2 saturation. Testing suggested that the graph theory approach can be as much as 50 and 20 times faster than the full physics numerical simulations and invasion-percolation simulations, respectively.

Reservoir Characterisation and Modelling for CO2 Sequestration in ‘‘Han’’ Field, Onshore Niger Delta, Nigeria

Geoscientists working in the oil and gas industry have a crucial role in combating climate change. In particular, by carrying out regional and local characterization and field projects to demonstrate that different types of geologic storage reservoirs distributed over different basins can permanently and safely store CO2. Therefore, this work is aimed at determining the storage capacity, injectivity, and containment of the reservoir intended for CO2 sequestration. Well logs and 3D seismic data were used to analyze a depleted oil field, (the “HAN” field), in the Niger Delta, Nigeria. Petrophysical analysis was done on the well logs to estimate the net thickness, porosity, water saturation, and injectivity of the reservoirs. Structural interpretation was done on the seismic data, and the volumetric method was used to estimate the storage capacity of the delineated reservoirs. The fault's sealing capacity was determined, and the resulting containment of the reservoirs was estimated. Two sand reservoirs, RES 1 and RES 2, of average thicknesses of 79 m and 93 m, respectively, were delineated across the three analysed wells. The reservoirs effective porosity was 18% and 19%, respectively, and water saturation was 18% and 35%, respectively. The storage capacity of RES 1 was estimated to be 28 MT, and RES 2 was 22 MT. The assessed storage capacity for both reservoirs gave “HAN” field a total storage capacity of approximately 50 MT. The injectivity for RES 1 and RES 2 was determined to be 337 mD and 323 mD, respectively. Based on the threshold set by the International Energy Agency, parameters obtained were observed to be greater than 10 m, 10%, 10%, 200 mD, and 4 MT for thickness, effective porosity, water saturation, injectivity, and storage capacity, respectively. The Han field is suggested as a good field for CO2 sequestration. Furthermore, the Shale Gouge Ratio (SGR) was estimated to be 29% (poor sealing zone) and 44% (moderately sealing zone) in Fault F9 for regions with RES 1 and 2, respectively, to validate their containment. It is evident from the SGR that F9 can serve as a barrier to the migration of CO2 away from the reservoir at deeper depths.

High-resolution geoelectrical characterization and monitoring of natural fluids emission systems to understand possible gas leakages from geological carbon storage reservoirs

Gas leakage from deep geologic storage formations to the Earth’s surface is one of the main hazards in geological carbon sequestration and storage. Permeable sediment covers together with natural pathways, such as faults and/or fracture systems, are the main factors controlling surface leakages. Therefore, the characterization of natural systems, where large amounts of natural gases are released, can be helpful for understanding the effects of potential gas leaks from carbon dioxide storage systems. In this framework, we propose a combined use of high-resolution geoelectrical investigations (i.e. resistivity tomography and self-potential surveys) for reconstructing shallow buried fracture networks in the caprock and detecting preferential gas migration pathways before it enters the atmosphere. Such methodologies appear to be among the most suitable for the research purposes because of the strong dependence of the electrical properties of water-bearing permeable rock, or unconsolidated materials, on many factors relevant to CO2 storage (i.e. porosity, fracturing, water saturation, etc.). The effectiveness of the suggested geoelectrical approach is tested in an area of natural gas degassing (mainly CH4) located in the active fault zone of the Bolle della Malvizza (Southern Apennines, Italy), which could represent a natural analogue of gas storage sites due to the significant thicknesses (hundreds of meters) of impermeable rock (caprock) that is generally required to prevent carbon dioxide stored at depth from rising to the surface. The obtained 3D geophysical model, validated by the good correlation with geochemical data acquired in the study area and the available geological information, provided a structural and physical characterization of the investigated subsurface volume. Moreover, the time variations of the observed geophysical parameters allowed the identification of possible migration pathways of fluids to the surface.

Evaluation and optimization of a horizontal well-triplet for CO2 plume geothermal harvest: Comparison between open and close reservoirs

Depleted oil/gas reservoirs can be used for CO2 sequestration and utilization; CO2 plume geothermal (CPG) production from a CO2 geological storage reservoir has emerged as a viable approach owing to its favorable thermodynamic properties. However, most oil/gas reservoirs are separated by faults into geological blocks, and the impact of these fault boundaries on CPG performance remains unclear. This study evaluated and compared the technical performances of a horizontal well-triplet placement and CPG operation in a thin geothermal reservoir between open and close boundaries. A meta-model simulation–optimization framework was also applied for the economic assessment of both systems. For each boundary system, 200 samples of the horizontal well-triplet design, including injection well overpressure, horizontal perforation length of injection and production wells, and distance between injection and production well, were derived from a 4D-parameter space constrained by particular ranges. These 200 samples of input parameters yielded 200 numerical models for the simulation of CPG operations. A suite of technical metrics, including lifespan, injected, produced, and stored CO2, recovered heat energy, and produced heat flux, were computed from the model simulations for technical performance evaluations. Meta models for economic objectives were developed based on the 200 input–output datasets and used in optimization. A multi-objective particle swarm optimization (MOPSO) approach was utilized to obtain the appropriate optimal designs of the well-triplet for the two boundary systems. The results indicated that performance of both systems was controlled by the well space, which was positively correlated to CO2 storage and total heat recovery but negatively to power plant capacity. High horizontal well lengths and overpressure facilitated CO2 storage, heat recovery, and plant capacity. The open system could generate much more overall profit than the close system owing to CO2 storage income.

Efficient screening of locations with the best pressure dissemination potential in geological CO2 storage reservoirs with lithological heterogeneity

Efficient and safe disposal of CO2 in the subsurface depends on several conditions including a low-pressure build-up to avoid the risk of induced seismicity. CO2 storage reservoirs commonly comprise lithological heterogeneity which may contribute to pressure build-up during CO2 injection. The presence of certain rock types restricting CO2 flow, known as flow barriers, can limit the migration of CO2 leading to reservoir pressure build-up particularly near the injection point. Identifying suitable injection locations away from such rock types could require numerous high-fidelity numerical simulations due to the uncertainty of the distribution of such barriers. This study presents a new computationally efficient reservoir screening approach to minimize the probability of enhanced pressure build-up resulting from lithological heterogeneity near the CO2 injection point. The approach utilizes graph network algorithm to identify the path of the least resistance to CO2 flow between the injection location and the top of the reservoir. This path accounts for lithological heterogeneity and was coupled to the results from 50 reservoir-scale numerical simulations, capturing a range of reservoir property distributions, to derive a classification criterion for predicting grid-cell scale injectivity index. Testing showed that the approach could accurately predict the spatial variability of the injectivity index with a computational boost of up to 10,000 times.

Risk evaluation of CO2 leakage through fracture zone in geological storage reservoir

CO2 storage in saline aquifers is an effective way to reduce the emission of CO2 into the atmosphere. The potential leakage problems are the main challenge for CO2 storage projects. However, the quantitative evaluation and analysis of the driving forces for the potential CO2 leakage problems are still lacking. In this paper, a stratified model embedded with a highly-permeable fracture zone was constructed to simulate CO2 leakage in the post-injection period. The acting forces and dimensionless numbers were systematically analyzed, and four stages were defined based on the leakage characteristics. Ultimately, a novel regression model was developed to predict the percentage of secure storage for CO2 at any dimensionless numbers. Results showed four distinct CO2 leakage stages: fast CO2 leakage stage (T1); decreasing CO2 leakage stage (T2); fast water sink stage (T3); and stable countercurrent flow stage (T4). Viscous force, gravity force, and capillary force were the dominant driving forces in turn in the first three stages. A stable countercurrent flow and CO2 leakage were maintained in the last period. In addition, the turning point of the flow pattern was delayed, and Gravity number (Gr) and Bond number (Bo) decreased obviously with the increase of initial pressure gradient. More importantly, most of the leaked CO2 was trapped in riskier forms (i.e. structural and residual trapping), and heavy acidification occurred in the shallow aquifer. The novel regression model showed that the percentage of secure storage could be enhanced by increasing Gr and/or decreasing the Ca. It is suggested that the pressure gradient at the end of injection should be optimized to store more CO2 and decrease the leakage risk simultaneously.

The effect of original and initial saturation on residual nonwetting phase capillary trapping efficiency

Injection of supercritical carbon dioxide (CO2) into geological formations is a strategy for both atmospheric greenhouse gas reduction (climate change mitigation) and enhanced oil recovery. To understand CO2 trapping efficiency, the capillary trapping behaviors that immobilize subsurface fluids were analyzed at the pore-scale using pairs of proxy fluids representing the range of in situ nonwetting and wetting fluid properties encountered in geologic storage reservoirs. The pairs of fluids were cycled through imbibition and drainage processes using a flow cell apparatus containing a sintered glass bead column. Computed x-ray microtomography (microCT) was used to identify immobilized nonwetting fluid after imbibition and drainage events. From microCT images, the trapped residual (post-secondary imbibition) nonwetting phase was spatially correlated to both the original (post-primary imbibition) and the initial (post-primary drainage) nonwetting phase; this relationship is referred to here as the original saturation dependence (SO-dependence) and initial saturation dependence (SI-dependence), respectively. Significant trends of decreasing SO- and SI-dependence with increasing wetting and nonwetting fluid phase viscosities were observed. This finding implies that the amount of CO2 injected and ultimately trapped is dependent on the nonwetting phase (e.g. oil or gas) already present in the formation, as well as on the manner in which supercritical CO2 is initially injected, which are factors not considered in current trapping models. To explore the potential effect that varying viscosity and interfacial tension (IFT) might have on this process, we report on a variety of fluid pairs with different viscosities and IFT.

Modeling CO2 migration in a site-specific shallow subsurface under complex hydrodynamics

Potential pathways in the subsurface may allow upward migrating CO2 from deep geological storage reservoirs into shallow subsurface aquifers. Detailed simulations of CO2 migration in the near surface are necessary for monitoring design where the near-surface groundwater flow field is usually complicated by rainfall and pumping wells. This work studied the CO2 migration under complex hydrodynamic conditions by numerical simulation for a specific site. Results shows that in a coupled soil and aquifer formation, the leakage rate of CO2 dominates the whole migration process, especially in the vadose zone. The groundwater velocity determines the lateral distance of CO2 migration with the groundwater flow, and simultaneously weakens the upward migration trend. Under certain conditions, such as the leakage rate of 1 × 10−5 kg/s and the groundwater velocity of 6.7 × 10−8 m/s, upward migration of CO2 is completely suppressed, therefore it will not leak to the surface. Both rainfall and pumping wells affect the migration indirectly by changing the groundwater flow field, while the impact of the latter is greater. When the well extraction increases or the well is downstream of the leak, CO2 will be extracted to the well. The permeability heterogeneity will also promote migration. Complex groundwater environments require more attention in the monitoring work.

Evaluation of CO2 sequestration and circulation in fault-bounded thin geothermal reservoirs in North Oman using response surface methods

In the past decade, techno-economic feasibility of using CO2 as a working fluid to harvest geothermal energy has been studied and demonstrated in both hot-dry rock and deep brine aquifers. Potential geothermal resources have been suggested by hydrogeological surveys in North Oman area. Many depleting petroleum reservoirs in this area provide excellent candidates as CO2 geologic storage and geothermal reservoirs, considering well-characterized and sealed geological structures and existing on-site infrastructure. In this study, we aim to conduct a comprehensive evaluation of reservoir performances during CO2 sequestration and circulation with possible field conditions in North Oman foreland basin. Continuous response surfaces of performance indicators are developed using 1000 CO2 sequestration-circulation models. Each model input file is assigned a set of values sampled using Latin-Hypercube method from high-dimensional parameter space bounded by ranges of key property parameters of reservoirs, including reservoir dip angle, depth, permeability, thickness, lateral boundaries, bounded fault permeability, and geothermal temperature gradient. Using response surfaces, key performance indicators, including CO2 injection, production, storage, fault leakage, well space, pressure, temperature, produced thermal flux, and lifespan, are quantitatively evaluated corresponding to various reservoir conditions represented by input parameters. The findings provide a quantitative guidance on site selection, geothermal field development and operation, and associated leakage risk assessment and techno-economic analysis for potential CO2 sequestration, geothermal exploration and utilization in North Oman foreland basin and other similar fields.

Aquifer-CO2 leak project: Physicochemical characterization of the CO2 leakage impact on a carbonate shallow freshwater aquifer

This work is part of the Aquifer CO2-Leak project and aims to understand, quantify and model the environmental impact of a CO2 leak on water quality in the carbonate freshwater aquifer as well as CO2-water-carbonate interactions. The experiment has been performed within an Oligocene carbonate underground quarry located in Saint-Emilion (France).A water charged with dissolved CO2 was injected in the aquifer through a borehole. Downstream, seven wells were fitted with in-situ probes which automatically measured physicochemical parameters. Periodic water samplings in all wells have been undertaken to determine the elemental concentrations by ion chromatography.The spread of CO2 in the groundwater was monitored as a function of time and was observed to influence the various physicochemical parameters. Five parameters seem to be excellent indicators for monitoring a gas plume during CO2 geological storage in regard to our results: electrical conductivity and pH, and Ca2+, HCO3−, and CO2(aq) concentrations.The interaction between CO2 and limestone is highlighted by a saturation index (SI) calculated with PhreeqC software. It shows (i) a slight trend to dissolution of calcite in the injection well (SI < 0) linked to the reaction process between CO2-H2O-CaCO3 and (ii) a transport process via diffusion for the observation wells with a SI≃0.The evolution of physicogeochemical signatures in the aquifer allows us to understand the reactive and transport processes that occur during the migration of a gasified water plume in the context of leakage from a geological storage reservoir. Our results will make possible to model a leakage in a complex natural reservoir.

Downhole pressure and chemical monitoring for CO2 and brine leak detection in aquifers above a CO2 storage reservoir

We assess the effectiveness of downhole monitoring of pressure and chemistry for detecting CO2 and brine leakage into underground sources of drinking water (USDW) overlying a geologic CO2 storage (GCS) reservoir. This assessment uses synthetic data sets generated in an uncertainty quantification (UQ) model framework. This framework combines the results of three model types: (1) a model of a hypothetical, 50-yr, 5-MT/yr GCS operation in the Vedder Fm. at the Kimberlina site in the southern San Joaquin Basin in California, USA, (2) models of CO2/brine leakage in legacy wells into overlying aquifers, and (3) models of CO2/brine plume migration in those aquifers. Leakage into overlying aquifers causes changes in pressure, CO2 saturation, and total dissolved solids (TDS), the latter being related to the solubility and speciation of CO2. This study captures the influence of leakage depth along the legacy well, regional groundwater flow, and aquifer heterogeneity on leak detection using downhole pressure and TDS monitoring.We consider CO2/brine leakage for legacy wells located at various distances from the CO2 injector at the Kimberlina site. Because gaseous CO2 is much less dense than supercritical CO2, the depth where leakage occurs along the wellbore is a key factor affecting the CO2, TDS, and pressure plumes. Supercritical CO2 that migrates upwards to depths less than 800 m undergoes a phase change to gaseous CO2, with the large volumetric expansion causing a large rise in pressure and a large spread in the TDS and pressure plumes. Because the pressure and TDS plumes migrate with the CO2 plume, they are strongly affected by regional groundwater flow and aquifer heterogeneity.We evaluated the likelihood of leak detection over a wide range of CO2/brine leakage-mass magnitude for downhole monitoring at various sensor depths, as well as for locations upgradient, downgradient, and laterally from the leaking well. Leak-detection effectiveness of downhole monitoring improves as the volumes of the CO2 and TDS plumes increase with cumulative CO2/brine leakage mass, groundwater gradient, and aquifer permeability. The effectiveness of pressure monitoring also increases strongly with CO2 leakage rate and can be useful for early detection of large leaks. Because TDS and pressure plumes migrate with the regional groundwater flow, downgradient monitoring wells are more effective than lateral or upgradient wells. Pressure monitoring is found to be more effective than TDS monitoring for shallow depths, while TDS monitoring is more effective at depths greater than about 600 m for this site. The addition of two monitoring depths to a single-depth monitoring well greatly improves leak detection. Monitoring three (shallow, medium, and deep) depths in the same well is found to be equally effective for pressure and TDS for the Kimberlina site. However, these comparisons are affected by the choice of detectable TDS and pressure thresholds, which depend on the level of unfilterable background noise for a specific site. For GCS sites like the Kimberlina site, with a thick sequence of overlying aquifers, unbroken by confining, low-permeability aquitard layers, an effective use of an individual monitoring well would be to monitor pressure at a shallow (<600 m) depth and to monitor TDS at a medium-depth (600−900 m) interval and for at least one deep (>900 m) interval. Because pressure and TDS changes evolve so gradually, continuous monitoring is not necessary.

A review of geochemical–mechanical impacts in geological carbon storage reservoirs

AbstractGeological carbon storage (GCS) refers to the technology of capturing man‐made carbon dioxide (CO2) emissions, typically from stationary power sources, and storing such emissions in deep underground reservoirs. GCS is an approach being explored globally as a defense mechanism against climate change projections, although it is not without its critics. An important focus has been recently placed on understanding the coupling between rock–fluid geochemical alterations and mechanical changes for CO2 storage schemes in saline aquifers. This article presents a review of the current state of knowledge regarding CO2‐induced geochemical reactions in subsurface reservoirs, and their potential impact on mechanical properties and microseismic events at CO2 storage sites. This review focuses, in particular, on the current state of the art in fluid–rock interactions within the GCS context. Key issues to be addressed include geochemical reactions and the alteration of transport and mechanical properties. Specific review topics include the swelling of clays, the prediction of dissolution and precipitation reaction rates, CO2‐induced changes in porosity and permeability, constitutive models of chemo–mechanical interactions in rock, and correlations between geochemical reactions and induced seismicity. The open questions in the field are emphasized, and new research needs are highlighted. © 2019 Society of Chemical Industry and John Wiley &amp; Sons, Ltd.

Near well-bore sealing in the Bečej CO2 reservoir: Field tests of a silicate based sealant

A silica gel was applied in a porous gas reservoir, with the purpose of testing mitigation and remediation of CO2 leakage from geological storage reservoirs. The gel has a high strength and a very low water-like viscosity, that extends its applicability to small pore diameters and low permeability media. The gel was prepared and applied on-site with oilfield equipment. Mixing was upscaled from laboratory- to field-scale, including one unsuccessful attempt. Environmental concerns and additional health and safety requirements were modest as the formulation was composed only of the non-toxic commercial silica-based product Betol K28 T, acetic acid and fresh water. A well was selected and prepared in the Bečej natural CO2 field in Serbia, the well and reservoir were prepared and the gel was placed into a 600 m deep CO2- and CH4-bearing sandstone layer. The reservoir was selectively sealed to the gas cap through a fast, CO2-selective gelation, while the hydraulic pathways of the liquid-filled part of the reservoir remained open. In the regions where no CO2 was present the gelation reaction was slower and the kinetic was temperature-accelerated. A numerical model was used to simulate the impact of the pre-injection operational procedures and to quantify the impact on the temperature-dependent gelation time. The workflow aligns the needs of a research project with the interests and practical priorities of an operating company.

PERMEABILITY, SELECTIVITY AND DISTINGUISHING CRITERION OF SILICONE MEMBRANE FOR SUPERCRITICAL CO2 AND N2 IN THE POROUS MEDIA

The possibility of leakage of CO2 from a geological storage reservoir is of serious concern to stakeholders. In this work, high–pressure-temperature laboratory experiments were performed to demonstrate the application of a silicone membrane-sensor system in the monitoring of subsurface gases, especially in the leakage scenario. Mass permeation, membrane resistance to gas permeation, and the gas flux across the membrane are reported for two gases, namely, CO2 and N2. Mass permeation of CO2 through the membrane was more than ten times higher than that of N2, under similar conditions. It was also found to increase with the geological depths. The gas flux remains higher for CO2 as compared to N2. From the results, a simple criterion for distinguishing the presence of the different gases at various geological depths was formulated based on the rate of permeation of gas through the membrane. Results and techniques in this work can be employed in the detection/monitoring of subsurface gas transport, especially in geological carbon sequestration.

Soil gas investigation of an alleged gas migration issue on a residential farm located above the Weyburn-Midale CO2 enhanced oil recovery project

Stable (13C) and radiogenic (14C) carbon isotope tracers are recognized approaches to identify gas sources using soil gas monitoring techniques; however, definitive characterization from a subsurface injection/storage reservoir can be complicated by processes that produce and consume CO2. Few studies assess the combined use of compositional (fixed gases, hydrocarbons, and sulphurous compounds) and isotopic (13C, 18O and 14C) indicators from soil gases as tools to evaluate CO2 storage reservoir leaks. Compositional and isotopic indicators from soil gases were compared at an investigation site (IS) alleged to be impacted by CO2 leaking from an underlying injection reservoir with a baseline control site (BCS) outside of the injection area. Soil gas δ13CCO2 values collected from the IS (−23.4‰to −22.6‰) were comparable with the range observed at the BCS (−22.8‰ and −23.3‰), falling within the range anticipated for both biogenic and injected CO2. 14C values were also comparable between IS (98.0 pMC to 107.0 pMC) and BCS (102.8 pMC to 105.3 pMC) sites, representing a modern carbon source that was distinct from the CO2 injection gas (0.34 pMC). The results provide several lines of evidence that CO2 fluxes in soil gases at the IS were related to naturally occurring processes and were not caused by a gas migration issue from a geological CO2 storage reservoir.

Predicting Effective Diffusion Coefficients in Mudrocks Using a Fractal Model and Small‐Angle Neutron Scattering Measurements

AbstractThe determination of effective diffusion coefficients of gases or solutes in the water‐saturated pore space of mudrocks is time consuming and technically challenging. Yet reliable values of effective diffusion coefficients are important to predict migration of hydrocarbon gases in unconventional reservoirs, dissipation of (explosive) gases through clay barriers in radioactive waste repositories, mineral alteration of seals to geological CO2 storage reservoirs, and contaminant migration through aquitards. In this study, small‐angle and very small angle neutron scattering techniques have been utilized to determine a range of transport properties in mudrocks, including porosity, pore size distributions, and surface and volume fractal dimensions of pores and grains, from which diffusive transport parameters can be estimated. Using a fractal model derived from Archie's law, we calculate effective diffusion coefficients from these parameters and compare them to laboratory‐derived effective diffusion coefficients for CO2, H2, CH4, and HTO on either the same or related mudrock samples. The samples include Opalinus Shale from the underground laboratory in Mont Terri, Switzerland, Boom Clay from a core drilled in Mol, Belgium, and a marine claystone cored in Utah, USA. The predicted values were compared to laboratory diffusion measurements. The measured and modeled diffusion coefficients show good agreement, differing generally by less than factor 5. Neutron or X‐ray scattering analysis is therefore proposed as a novel method for fast, accurate estimation of effective diffusion coefficients in mudrocks, together with simultaneous measurement of multiple transport parameters including porosity, pore size distributions, and surface areas, important for (reactive) transport modeling.

The impact of time-varying CO2 injection rate on large scale storage in the UK Bunter Sandstone

Carbon capture and storage (CCS) is expected to play a key role in meeting targets set by the Paris Agreement and for meeting legally binding greenhouse gas emissions targets set within the UK (Energy and Climate Change Committee, 2016). Energy systems models have been essential in identifying the importance of CCS but they neglect to impose constraints on the availability and use of geologic CO2 storage reservoirs. In this work we analyse reservoir performance sensitivities to varying CO2 storage demand for three sets of injection scenarios designed to encompass the UK's future low carbon energy market. We use the ECLIPSE reservoir simulator and a model of part of the Southern North Sea Bunter Sandstone saline aquifer. From a first set of injection scenarios we find that varying amplitude and frequency of injection on a multi-year basis has little effect on reservoir pressure response and plume migration. Injectivity varies with site location due to variations in depth and regional permeability. In a second set of injection scenarios, we show that with envisioned UK storage demand levels for a large coal fired power plant, it makes no difference to reservoir response whether all injection sites are deployed upfront or gradually as demand increases. Meanwhile, there may be an advantage to deploying infrastructure in deep sites first in order to meet higher demand later. However, deep-site deployment will incur higher upfront cost than shallow-site deployment. In a third set of injection scenarios, we show that starting injection at a high rate with ramping down, a low rate with ramping up or at a constant rate makes little difference to the overall injectivity of the reservoir. Therefore, such variability is not essential to represent CO2 storage in energy systems models resolving plume and pressure evolution over decadal timescales.

Impacts of relative permeability formulation on forecasts of CO2 phase behavior, phase distribution, and trapping mechanisms in a geologic carbon storage reservoir

A critical aspect in the risk assessment of geologic carbon storage, a carbon-emissions reduction method under extensive review and testing, is effective multiphase CO2 flow and transport simulation. Relative permeability is a flow parameter particularly critical for accurate forecasting of the multiphase behavior of CO2 in the subsurface. The relative permeability relationship assumed and especially the residual saturation of the gas phase greatly impacts predicted CO2 trapping mechanisms and long-term plume migration behavior. A primary goal of this study was to evaluate the impact of the selection of relative permeability formulations on the efficacy of regional-scale CO2 sequestration models. To accomplish this, we selected the San Rafael Swell area of East-central Utah as a case study to evaluate the impact of relative permeability formulations on CO2 plume movement and behavior. A 2D vertical cross section model was built to simulate injection of CO2 into a brine aquifer for 30 years followed by 970 years of post-injection monitoring. We evaluated five different relative permeability relationships to quantify their relative impacts on forecasted flow results of the model, with all other parameters maintained uniform and constant. Because of the interdependence between phase saturation and relative permeability in numerical simulations we expected to see some variation in phase behavior, phase distribution, and CO2 trapping mechanisms. An almost 60% difference in residually trapped gas was observed across the different relative permeability relationships. Large variations of up to 40% in the saturation of both dissolved phase and mobile supercritical phase CO2 were also observed. The pressure buildup and decay observed was not significantly affected by the relative permeability formulation until after injection pressures have dissipated. Results of this analysis suggest that CO2 plume movement and behavior are significantly dependent on the specific relative permeability formulation assigned, including the assumed residual saturation values of CO2 and brine. More specifically, different relative permeability relationships translate to significant differences in CO2 plume behavior and corresponding trapping mechanisms. © 2016 Society of Chemical Industry and John Wiley & Sons, Ltd

Leakage risks of geologic CO2 storage and the impacts on the global energy system and climate change mitigation

This study investigated how subsurface and atmospheric leakage from geologic CO2 storage reservoirs could impact the deployment of Carbon Capture and Storage (CCS) in the global energy system. The Leakage Risk Monetization Model was used to estimate the costs of leakage for representative CO2 injection scenarios, and these costs were incorporated into the Global Change Assessment Model. Worst-case scenarios of CO2 leakage risk, which assume that all leakage pathway permeabilities are extremely high, were simulated. Even with this extreme assumption, the associated costs of monitoring, treatment, containment, and remediation resulted in minor shifts in the global energy system. For example, the reduction in CCS deployment in the electricity sector was 3% for the “high” leakage scenario, with replacement coming from fossil fuel and biomass without CCS, nuclear power, and renewable energy. In other words, the impact on CCS deployment under a realistic leakage scenario is likely to be negligible. We also quantified how the resulting shifts will impact atmospheric CO2 concentrations. Under a carbon tax that achieves an atmospheric CO2 concentration of 480 ppm in 2100, technology shifts due to leakage costs would increase this concentration by less than 5 ppm. It is important to emphasize that this increase does not result from leaked CO2 that reaches the land surface, which is minimal due to secondary trapping in geologic strata above the storage reservoir. The overall conclusion is that leakage risks and associated costs will likely not interfere with the effectiveness of policies for climate change mitigation.