Prospective CO2 Storage Research Articles

Basin-scale study of CO2 storage in stacked sequence of geological formations

Commercial scale decarbonization through carbon capture and storage may likely involve many CO2 storage projects located in close proximity. The close proximity could raise concerns over caprock integrity associated with reservoir pressure buildup and interference among adjacent projects. Commercial-scale injection will also require large prospective CO2 storage resource and high injectivity in the targeted storage formations. To accommodate the need for both large resource and high injectivity, project operators could consider injecting CO2 into a stacked sequence of formations. This analysis investigates the benefits of injecting CO2 into a vertically stacked sequence of saline formations, over injecting the same amount of CO2 into a single saline formation, in addressing these challenges. Our analysis shows that injecting into the stacked sequence mitigates the extent of pressure buildup among the stacked formations, while still achieving the same or greater target CO2 storage volumes. Among cases modeled, the resulting pressure buildup front is most reduced when each storage site distributes injection volumes over several wells, each of which injects a portion of the total CO2 mass across the stacked sequence. This favorable case not only results in the smallest CO2 aerial footprint, but also shows the largest reduction in the pressure buildup at the top of perforation at the injection wells (upwards of approximately 46% compared to the single-formation storage), the result of which is crucial to maintain caprock integrity. This analysis provides insights into required decision-making when considering multi-project deployment in a shared basin.

Uncertainty Analysis of the Storage Efficiency Factor for CO2 Saline Resource Estimation

Carbon capture and sequestration (CCS) is a promising technology for reducing CO2 emissions to the atmosphere. It is critical to estimate the CO2 storage resource before deploying the CCS projects. The CO2 storage resource is limited by both the formation pore volume available to store CO2 and the maximum allowable pressure buildup for safe injection. In this study, we present a workflow for estimating the volume- and pressure-limited storage efficiency factor and quantifying the uncertainty in the estimates. Thirteen independent uncertain physical parameters characterizing the storage formation are considered in the Monte Carlo uncertainty analysis. The uncertain inputs contributing most to the overall uncertainty in the storage efficiency factor are identified. The estimation and uncertainty quantification workflow is demonstrated using a publicly available dataset developed for a prospective CO2 storage site. The statistical distributions of the storage efficiency factor for the primary storage formation and the secondary storage formation located in deeper depth are derived using the proposed workflow. The effective-to-total porosity contributes most to the overall uncertainty in the estimated storage efficiency factor at the study site, followed by the maximum allowable pressure buildup, the net-to-gross thickness ratio, the irreducible water saturation, and the permeability. While the significant uncertain input variables identified are tailored to the characteristics of the study site, the statistical methodology proposed can be generalized and applied to other storage sites. The influential uncertain inputs identified from the workflow can provide guidance on future data collection needs for uncertainty reduction, improving the confidence in the CO2 saline storage resource estimates.

Seismic reservoir characterization of the Gassum Formation in the Stenlille aquifer gas storage, Denmark — Part 1

Seismic reservoir characterization plays an important role in carbon capture and storage analysis. The Havnsø anticlinal structure in Denmark is a prospective CO2 storage site due to its proximity to two large emission sources—a coal-fired power station and a nearby refinery. Although legacy 2D seismic lines over the area outline the anticlinal structure, their quality is insufficient for quantitative interpretation. Earlier studies have shown that the natural gas stored in the Stenlille aquifer exhibits a seismic response similar to the modeled CO2 fluid in the Havnsø structure. Thus, seismic reservoir characterization carried out on the Stenlille aquifer gas storage in terms of identifying spatial distribution of gas and outlining faults would provide insight regarding value addition that seismic data can bring into the proposed CO2 storage at Havnsø. Using the available poststack seismic data, we apply an integrated reservoir characterization analysis. After performing the adequate data conditioning, the impedance of the target Stenlille Formation is estimated through generation of an accurate low-frequency model. Thereafter, multiattribute analysis was used to generate volumetric estimates of porosity, gamma ray, and water saturation within the target formation so that the spatial distribution of gas can be mapped. The resulting porosity and gamma-ray volumes indicate encouraging results and were used for Bayesian classification to predict the probability of the more important lithofacies, namely, sand, shale, moderate-porosity sand, and moderate-porosity shaly sand, which enabled the mapping of high-porosity/facies zones in the two aquifer storage levels. Independently, we make use of unsupervised machine learning applications for seismic facies prediction and compare them at the two storage levels, which will be presented in the part 2 of this paper.

3D Field-Scale Geomechanical Modeling of Potential CO2 Storage Site Smeaheia, Offshore Norway

Injection-induced rock mechanical failure risks are critical in CO2 sequestration, and thus there is a need to evaluate these occurrences to ensure safe and reliable subsurface storage. A stress–strain-based numerical simulation can reveal the potential mechanical risks of any CO2 sites. This study investigated the hydromechanical effect on geomechanical failure due to injection-induced stress and pore pressure changes in the prospective CO2 storage site Smeaheia, offshore Norway. An inverted-seismic-property-driven 3D field-scale geomechanical model was carried out in the Smeaheia area to evaluate the rock failure and deformation risks in various pressure-build-up scenarios. A one-way coupling between the before- and after-injection pressure scenarios of nine different models has been iterated using the finite element method. The effect of the sensitivity of total pore volume and pore compressibility on rock mechanical deformation is also evaluated. Although various models illustrated comparative variability on failure potential, no model predicted caprock failure or fracture based on the Mohr–Coulomb failure envelope. Moreover, the lateral mechanical failure variation among different locations indicated the possibility to identify a safer injection point with less chances of leakage. In addition, the pore volume and pore compressibility significantly influence the mechanical behavior of the reservoir and caprock rocks. Although this analysis could predict better injection locations based on geomechanical behavior, a fluid simulation model needs to be simulated for assessing lateral and vertical plume migration before making an injection decision.

Assessing rock physics and seismic characteristics of the Gassum Formation in the Stenlille aquifer gas storage – A reservoir analog for the Havnsø CO[formula omitted] storage prospect, Denmark

The rock physics and seismic characteristics of prospective CO2 storage sites are important inputs to assess the feasibility of seismic reservoir characterization and monitoring of the CO2 plume. In this paper, geophysical data from the Stenlille aquifer gas storage in Denmark are used as a reservoir analog to the Gassum Formation at the Havnsø CO2 prospect. Rock physics and pore fluid modeling of the in situ natural gas and CO2 saturation was performed to obtain an initial understanding of the seismic-reservoir relationship and to model the seismic sensitivity for various pore fluid scenarios. Then, a 3D seismic survey at Stenlille was used as input to a Bayesian inversion for litho-fluid classification to outline the injected natural gas distributions in a probabilistic manner. Although only post-stack seismic data were available, the gas injected into the different reservoir zones of the Gassum Formation yields a low acoustic impedance signature that could be interpreted from the inversion results. The predictions were consistent with well log data, reported gas withdrawal and injection volumes and conforms with the geological structure. This implies good conditions for seismic reservoir characterization and monitoring CO2 saturation changes in the Gassum Formation for geological settings similar to the Stenlille aquifer.

Assessment of oil and gas fields in California as potential CO2 storage sites

California's total annual greenhouse gas (GHG) emissions (425.3 MtCO2e) in 2018 were about 6.4% of the US total (6,677 MtCO2e) and around 1% of global emissions. About 39% of 2018 GHG emissions in California were from the industrial and electrical sectors. Many of these emissions were from large stationary point sources and were suitable for carbon capture retrofit with subsequent storage of the captured carbon dioxide (CO2) in geological formations. Previous studies of California found suitable geology and CO2 storage resource. This study refines and furthers prior work using a three-stage screening process of oil fields, gas fields, and underground natural gas storage (UGS) sites by combining criteria from previous studies while excluding sites that pose technical risk or are located in regions with surface restrictions including sensitive habitats and dense populations. In the first stage, 129 CO2 storage sites in California were identified using qualification criteria based upon formation properties including geological conditions and pore pressure. The second stage identified sensitive sites by applying conservative screens including seismic activity, faulting, population density, restricted lands, and sensitive habitats. During the third stage, 61 CO2 potential storage sites were identified by subtraction of stage 2 areas from stage 1. The potential storage volume in the third stage ranged from 1.0 to 2.0 GtCO2. Finally, we applied a scoring system with seven parameters to rank the 61 potential sites based on subsurface technical criteria. The scored sites are classified as high priority, medium priority, and sites for future study. Prospective CO2 storage sites with high and moderate priority were selected and linked to CO2 sources. There are 14 prospective sites (above 20 MtCO2 storage resource per site) with a total storage resource of 1024 MtCO2 distributed in Northern and Southern California. Of these sites, there are 9 potential CO2-EOR sites and 1 depleted oil field with a total estimated CO2 storage volume of ∼800 MtCO2 in the Southern San Joaquin and Ventura Basin. These 10 prospective sites with a storage resource greater than 20 MtCO2 could potentially deliver more than 20 years of storage with an average injection rate of 40 MtCO2/year. The remaining 4 highly prospective sites are in Northern California. Study results also suggest that saline formations should be re-evaluated in concert with storage in oil, gas, and natural gas storage reservoirs.

Considering the Potential for Sedimentary Basin Geothermal Power Generation When Screening for Prospective Geologic CO2 Storage Sites

Considering the Potential for Sedimentary Basin Geothermal Power Generation When Screening for Prospective Geologic CO2 Storage Sites

DeepSense: A Physics-Guided Deep Learning Paradigm for Anomaly Detection in Soil Gas Data at Geologic CO2 Storage Sites.

Driven by the collection of enormous amounts of streaming data from sensors, and with the emergence of the internet of things, the need for developing robust detection techniques to identify data anomalies has increased recently. The algorithms for anomaly detection are required to be selected based on the type of data. In this study, we propose a predictive anomaly detection technique, DeepSense, which is applied to soil gas concentration data acquired from sensors being used for environmental characterization at a prospective CO2 storage site in Queensland, Australia. DeepSense takes advantage of deep-learning algorithms as its predictor module and uses a process-based soil gas method as the basis of its anomaly detector module. The proposed predictor framework leverages the power of convolutional neural network algorithms for feature extraction and simultaneously captures the long-term temporal dependency through long short-term memory algorithms. The proposed process-based anomaly detection method is a cost-effective alternative to the conventional concentration-based soil gas methodologies which rely on long-term baseline surveys for defining the threshold level. The results indicate that the proposed framework performs well in diagnosing anomalous data in soil gas concentration data streams. The robustness and efficacy of the DeepSense were verified against data sets acquired from different monitoring stations of the storage site.

Directional Hydraulic Characteristics of Reservoir Rocks for CO2 Geological Storage in the Pohang Basin, Southeast Korea

This study conducted core sampling of an offshore borehole for geological reservoir characterization of a potential CO2 storage site in southeast Korea. From this, two promising geological formations at ~739 and ~779 m were identified as prospective CO2 storage reservoirs. Injection efficiency and CO2 migration were evaluated based on directional measurements of permeabilities from core plugs. The directional transport properties were determined using both a portable probe permeameter and a pressure cell capable of applying different in situ confining pressures. Both steady state and unsteady state measurements were used to determine permeability—the method selected according to the expected permeability range of the specific sample. This expected range was based on rapid screening measurements acquired using a portable probe permeameter (PPP). Anticipated performance of the prototypical CO2 injection site was evaluated based on flow modeling of the CO2 plume migration pathway including CO2 transport through the overlying formations based on the measured directional hydraulic properties. These analyses revealed that the injection efficiency at a depth of 739 m was double that at 779 m. These correlations among and distributions of the directional permeabilities of the potential CO2 geological storage site can be utilized for the assessment of CO2 storage capacity, injectivity, and leakage risk.

Carbon Storage Resource Assessment of the Mid-Atlantic U.S. Offshore Region

Carbon capture and storage (CCS) is a critical technology for ensuring a range of clean energy options are available to meet future energy demands. Offshore storage can be linked to large point-sources of carbon dioxide (CO2) while avoiding many of the logistical difficulties and potential risks encountered when siting onshore projects, especially in densely populated areas of the East Coast of the United States. Offshore storage along mid-Atlantic region was studied under the U.S. Department of Energy (DOE) funded Mid-Atlantic U.S. Offshore Carbon Storage Resource Assessment Project (MAOCSRAP) and as a subtask under the Midwest Regional Carbon Sequestration Partnership (MRCSP). The assessment was conducted as a technical collaboration between Battelle, Rutgers University, Lamont-Doherty Earth Observatory at Columbia University, state geological surveys of Delaware, Maryland and Pennsylvania, United States Geological Survey-Woods Hole Coastal and Marine Science Center, and Harvard University. Major objectives were to complete a systematic carbon storage resource assessment of the of the mid-Atlantic offshore coastal region from the Georges Bank Basin (GBB) through the Long Island Platform (LIP) to the southern Baltimore Canyon Trough (BCT), examine offshore storage risk factors, and engage industry and regulatory stakeholders through development of a Road Map to assist future project planning and implementation. Various publicly available data sets, such as seismic data, well-logs, and core data, were integrated to define geologic characteristics of candidate storage sites and calculate prospective CO2 storage resources for Cretaceous- and Jurassic-age sandstone sequences of the mid-Atlantic offshore sub-regions. The combined dataset helped to identify and map potential storage zones within sequences of the Logan Canyon, Missisauga, and Mohawk formations, as well as the regionally extensive caprock comprised of the Dawson Canyon shale. Prospective storage resource estimates and formation-specific storage efficiency values were calculated with static volumetric and dynamic methods. Regional-scale estimates range from 150 to 1136 gigatonnes (Gt) for the combined storage zones, with high estimated storage resource (≥ 2.4 megatonnes [Mt] CO2/km2) occurring in the northern BCT near the Great Stone Dome (GSD) structure. Results of local scale simplified dynamic reservoir simulation in the GSD indicate that injection rates of 1 Mt CO2/year may be sustained within the time and pressure constraints assumed for a commercial storage project. An initial, qualitative assessment of technical risk factors present in mid-Atlantic offshore areas was conducted. Overall, the mid-Atlantic offshore area benefits from the large spatial extent, thick sequences of sands, lack of previous oil and gas wellbores, and distance from populated development. Geomechanical stability, reservoir variability, and soft sediment deformation were identified as moderate risk factors in some areas. No highly critical risk factors were identified that would impede CO2 storage along the study areas. Input and participation from government, industry, and environmental groups helped to address next steps needed for future CCS project planning and implementation in the study region. Recommended near-term actions are to develop site screening through advanced geologic modeling, implement stakeholder outreach and risk mitigation strategies, identify industry and research goals, and develop regulatory pathways. Recommended mid-term actions are to validate subsurface properties with new data, conduct a cost-benefit analysis, and develop a monitoring, verification, and accounting (MVA) plan. Long term-recommended actions are to implement a plan for large-scale CCS operations using the previous findings, conduct site design, permitting, and construction, and upscale infrastructure. This project represents an important first step by completing a high-level CO2 storage resource assessment and building the knowledge infrastructure necessary to support the development of full-scale offshore carbon storage.

An image-based equation for estimating the prospective CO2 storage resource of organic-rich shale formations

An image-based volumetric equation for estimating the prospective CO2 mass storage resource potential for organic-rich shale formations has been developed using data obtained from advanced image analysis of Bakken Formation shale samples. The equation is a modification of the U.S. Department of Energy (DOE) National Energy Technology Laboratory’s (NETL’s) volumetric equation methodology for estimating the prospective CO2 mass storage resource for shale formations. The current equation enhances DOE’s version by systematically deriving expressions for calculating efficiency factors based on analysis of high-resolution field-emission scanning electron microscopy (FESEM) shale images. FESEM images are used to obtain improved nanoscale porosity estimates for the shale matrix and OM. The calculation of the efficiency factors associated with free-phase storage and CO2 adsorption onto solid surfaces are based on a ratio of connected-to-nonconnected porosity and the newly developed shared border analysis (SBA) method, respectively. The image-based equation described herein is structured so that it can be adapted and applied to other formation types by considering the specific mineralogy or matrix characteristics. Preliminary data used to illustrate the newly developed equation show that the Upper Bakken Shale (UBS) may have a lower prospective CO2 storage resource potential than the Lower Bakken Shale (LBS) by about 65 %. Although these results are neither optimized for each lithofacies nor represent the Bakken formation regional scale, they are encouraging for unfractured shale samples and serve as a useful starting point for future evaluations at the regional scale.

Methodology for estimating the prospective CO2 storage resource of residual oil zones at the national and regional scale

Residual oil zones (ROZs) are increasingly gaining interest as potential reservoirs for carbon dioxide (CO2) storage. Here, we present a national- and regional-scale methodology for estimating prospective CO2 storage resources in residual oil zones. This methodology uses a volumetric equation that accounts for CO2 storage as a free phase in pore space and as a dissolved phase in oil and does not assume any oil production associated with CO2 storage. Reservoir modeling and the CO2-SCREEN tool are used to demonstrate that CO2 storage in residual oil zones will predominantly take place in the free phase (approximately 92–97%) with some storage as dissolution in oil (approximately 3–8 %). Based on this preliminary demonstration, the CO2 storage efficiency for ROZs using this national- and regional-scale method ranges from 0.61 to 7.1 %. This range indicates ROZs have a similar efficiency potential for storing CO2 as deep saline formations (0.51–5.4 %).

Numerical estimations of storage efficiency for the prospective CO2 storage resource of shales

Hydrocarbon-bearing shale formations might be an attractive geologic reservoir for permanent carbon dioxide (CO2) storage. Shale formations applicable for storage require previous hydrocarbon production to deplete a reservoir, hydraulic fracturing to provide a highly-permeable stimulated zone, sufficient depths (generally > 800 m or 2600 feet) to maintain CO2 in a supercritical state, and an overlying seal to prevent CO2 migration to underground sources of drinking water and into the atmosphere. CO2 is stored in shale as a free phase within fractures and matrix pores, and as a sorbed phase on organic matter and clay minerals. Recently in our previous work, we presented a screening-level assessment methodology for CO2 storage in shales using a volumetric approach. The approach deals with reduction of CO2 storage through estimations of efficiency factors based on petrophysical properties (i.e., bulk volume, porosity, sorption, etc.) and their limitations on fluid transport. Here, we conducted numerical simulations using the FRACGEN/NFFLOW simulator to study the CO2 injection into a depleted hydro-fractured shale reservoir to estimate storage efficiencies using a range of reservoir parameters and injection scenarios. Specifically, the ranges for two efficiency factors, Eϕ and ES, measure the effectiveness of free and sorbed CO2 storage. These efficiency factors were estimated to have P10 to P90 probability ranges of 0.15 to 0.36 for Eϕ and 0.11 to 0.24 for ES, reported after 60 years of CO2 injection.

CO2-SCREEN tool: Application to the oriskany sandstone to estimate prospective CO2 storage resource

The ability to accurately predict the CO2 storage resource in saline formations is important to make high-level, energy-related government policy and business decisions. CO2-SCREEN (Storage prospeCtive Resource Estimation Excel aNalysis) is a tool developed by the United States Department of Energy − National Energy Technology Laboratory (US-DOE-NETL) to screen saline formations for prospective CO2 storage resources. CO2-SCREEN uses DOE methods and equations to serve as a consistent mechanism for calculating prospective CO2 storage resources. CO2-SCREEN is comprised of two files: an Excel file used for inputs and outputs and a GoldSim Player file used to run Monte Carlo simulations. CO2-SCREEN requires input of physical geologic parameters (i.e. thickness, porosity) as well as efficiency factor ranges (i.e. net-to-gross thickness) to calculate a mass storage estimate. An application of CO2-SCREEN is demonstrated here using well log data from the Oriskany Sandstone portion in Pennsylvania. The Oriskany Sandstone is divided into 20 km x 20 km grid cells in which 151 cells contain well log data. CO2-SCREEN calculates prospective CO2 storage resource for each grid cell based on the well log data and uses lithology and depositional environment information for efficiency factor ranges. The Oriskany Sandstone CO2 storage resource estimate for Pennsylvania, calculated by CO2-SCREEN, ranges from 0.07 to 1.28 gigatons (Gt) with a P50 value of 0.32 Gt. This resource assessment analysis is done to demonstrate the use of CO2-SCREEN and results are comparable to previous studies which encourages the application of CO2-SCREEN to other saline formations and warrants exploring the expansion of this tool to assess the CO2 storage resource in other formations such as shale and depleted oil and gas reservoirs.

The global overlap of bioenergy and carbon sequestration potential

Bioenergy with carbon capture and storage (BECCS) is a negative emissions technology that is a largely untested but prominent feature of ambitious climate change mitigation scenarios. This strategy involves capturing carbon dioxide (CO2) from stationary bioenergy facilities and sequestering it in suitable geological formations, effectively removing CO2 from the atmosphere. Many factors potentially limit BECCS deployment including obstacles to building pipeline networks that move large quantities of liquefied CO2 over long distances. Here, we examine the BECCS opportunity that exists in regions overlapping storage basins. Under current conditions, the equivalent of 22.9 GtCO2 y−1 of net primary production (NPP), a measure of biomass growth, overlies highly prospective CO2 storage basins, representing a sustainably harvestable total of approximately 7.6 GtCO2 y−1. Most land overlying basins is either forested or linked to food production. If only marginal agricultural lands, those inconsistently under agricultural production, are used to source biomass, the scale of the available resource is approximately 1 GtCO2 y−1. If transportation of biomass or CO2 is constrained, and if BECCS is not developed on forests or prime croplands, then BECCS deployments will be limited to a small, but meaningful fraction (~10%) of the levels typical in cost-optimized model trajectories that stabilize warming at 2 °C or less above pre-industrial temperatures. Marginal agricultural lands over storage basins can be an entry point for maturing the engineering technologies and financial markets needed for BECCS.

Mid-Atlantic U.S. Offshore Carbon Storage Resource Assessment

Attention to offshore prospects for geologic storage of carbon dioxide (CO2) in the U.S. is required to address numerous large point sources located along the U.S. Atlantic Coast. Research is underway to develop a reliable method for screening candidate storage formations with the greatest potential for effective, permanent storage of CO2, and producing data-driven regional-scale estimates of the prospective CO2 storage resource that exists offshore of the Mid-Atlantic U.S. This paper introduces the Mid-Atlantic U.S. Offshore Carbon Storage Resource Assessment project, describes the technical approach to achieve project goals, and presents preliminary results. The existing data set and challenges for data collection and analysis also are discussed.

U.S. DOE NETL methodology for estimating the prospective CO2 storage resource of shales at the national and regional scale

While the majority of shale formations will serve as reservoir seals for stored anthropogenic carbon dioxide (CO2), hydrocarbon-bearing shale formations may be potential geologic sinks after depletion through primary production. Here we present the United States-Department of Energy-National Energy Technology Laboratory (US-DOE-NETL) methodology for screening-level assessment of prospective CO2 storage resources in shale using a volumetric equation. Volumetric resource estimates are produced from the bulk volume, porosity, and sorptivity of the shale and storage efficiency factors based on formation-scale properties and petrophysical limitations on fluid transport. Prospective shale formations require: (1) prior hydrocarbon production using horizontal drilling and stimulation via staged, high-volume hydraulic fracturing, (2) depths sufficient to maintain CO2 in a supercritical state, generally >800m, and (3) an overlying seal. The US-DOE-NETL methodology accounts for storage of CO2 in shale as a free fluid phase within fractures and matrix pores and as an sorbed phase on organic matter and clays. Uncertainties include but are not limited to poorly-constrained geologic variability in formation thickness, porosity, existing fluid content, organic richness, and mineralogy. Knowledge of how these parameters may be linked to depositional environments, facies, and diagenetic history of the shale will improve the understanding of pore-to-reservoir scale behavior, and provide improved estimates of prospective CO2 storage.

Characterization and Estimation of CO2 Storage Capacity for the Most Prospective Aquifers in Sweden

Based on NORDICCS selection of the most prospective CO2 storage sites in the Nordic region, two saline aquifers in southern Sweden were subject to further investigations in an attempt to update the first static estimates of CO2 storage capacity and to improve the general understanding of the reservoir behavior. Two approaches were applied: capacity estimates for the structural and stratigraphic traps using the basin modeling software SEMI and capacity estimates using the full dynamic reservoir simulation software ECLIPSE 100, showing very different results regarding CO2 storage capacities. Hence, the SEMI modeling, depending on structural and stratigraphic traps, achieved a comparable poor CO2 storage capacity whereas the ECLIPSE simulation, countering all the main trapping mechanisms, achieved much higher estimated capacities.

Retention capacity of seals from hydrocarbon field analogues for appraisal of saline aquifers

Saline aquifers have very large potential as stores for carbon dioxide, but the seals are untested. The effectiveness of typical sealing lithologies can be assessed using natural hydrocarbon reservoirs. The heights of the hydrocarbon columns in many natural reservoirs are limited by a spill point or by the limited thickness of the reservoir; however, amongst the remaining reservoirs the range of calculated limiting porethroat radii correspond with measured literature values worldwide. This suggests that capillary leakage is the limiting factor in the retention of hydrocarbons in many natural accumulations, and is at least potentially the limiting factor in CO2 storage. The distribution of limiting porethroat radii for oil and gas fields of the UK North Sea could be used with caution as a generic input for statistical assessment of a prospective CO2 storage location at an early stage of investigation, before measured site-specific data is available. The calculated limiting porethroat radii show only a weak decrease with burial depth and no correlation to the degree of faulting of the seal. There is a strong correlation with seal lithology; calculated radii for halite seals are significantly smaller than for the majority of shale seals. There is no difference between the calculated limiting porethroat radii for fields with at least some degree of fault sealing, compared to those with no reported fault sealing.

Application of CO2-Saturated Water Flooding as a Prospective Safe CO2 Storage Strategy

Abstract In this study, According to the results of CO2 solubility measurement tests at constant temperatures, an increase in CO2 solubility values was observed for CO2–brine and CO2–oil systems when the equilibrium pressure increases. Furthermore, it was revealed that for both aforementioned systems, the solubility of CO2 reduces when temperature increased. It was found that introducing CO2 to the oil reservoirs through injection water provides great opportunity to lock large quantity of CO2 inside the porous medium with high retention factor. Results of this study showed that both secondary and tertiary scenarios of CO2-saturated water flooding are favourable with the storage capacity between 34% to 45% of the injected CO2 in the sand-pack model. In addition, the solubility trapping was shown to be the main CO2 trapping mechanism during CO2-saturated water flooding. According to the results of this study, most of the injected CO2 was trapped in the porous medium through dissolution in the reservoir fluids, i.e., solubility trapping. As an example, the flooding tests conducted in secondary mode at P = 10.3 MPa and T = 25 °C, showed that about 95% of the injected CO2 can be trapped by dissolution mechanism into the reservoir oil and brine. In terms of oil recovery, it was found that the ultimate oil recovery factor of CO2-saturated water flooding is consistently more than that of conventional water flooding leading this technique to be a more viable option as a means of improved oil recovery technique. In this study, flooding tests conducted at pressure of P = 10.3 MPa and temperature of T = 25 °C, verified that injection of CO2-saturated water resulted in improving the conventional water flooding oil recovery factor by about 19.0% and 12.5% of OOIP for secondary and tertiary scenarios, respectively. Based on the results obtained in this work, it was concluded that mixing CO2 with injected water noticeably provides permanent, safe, and practical CO2 storage together with considerable oil recovery improvement in light oil systems.