Potential CO2 Storage Sites Research Articles

In-situ study of CO2-saturated brine reactive transport in carbonates considering the efficiency of wormhole propagation

Deep limestone aquifers are potential CO2 storage sites, but CO2-saturated brine reacts with the carbonate rock, changing its transport and storage properties. This study provided a preliminary investigation of the optimal injection rate of CO2-saturated brine in carbonate rocks. Indiana limestone cores were subjected to CO2-saturated brine injection at varied rates using an HPHT coreflooding setup with X-ray CT monitoring. The samples were characterized pre- and post-treatment in terms of porosity and pore size distribution using a gas porosimeter and NMR T2 measurements. Moreover, the reaction was evaluated by measuring the aqueous effluent calcium ions concentration as a function of throughput using ICP-OES analysis. A high-resolution micro-CT scan was used to capture the dissolution post-treatments and characterize the wormhole's size and patterns. Results showed that the wormholes broke through to the sample exit face after injecting 160, 48, and 36 pore volumes at 0.5, 1, and 2 cm3/min, respectively thereby revealing the importance of injection velocity. The ICP-OES analysis revealed that a larger dissolution rate was achieved at 2 cm3/min, which explained the fast wormhole propagation. An increase in rock porosity and the pore-size distributions was observed after coreflooding on all samples with minimum precipitation, as concluded from the NMR T2 relaxation time. A universal optimum Damköhler number can be obtained that enables calculating the optimum injection rate of CO2-saturated brine at different rock and fluid conditions. We speculated that the optimum Damköhler number could be different from the value of 0.29 proposed by Fredd and Fogler (1998). This study provides a preliminary understanding of the optimal CO2-saturated brine injection velocity that has an application for CO2 storage, water alternating gas (WAG) operations, and acid stimulation of carbonate formations.

Design Insights for Industrial CO2 Capture, Transport, and Storage Systems.

We present methods and insights for the design of CO2 capture, transport, and storage systems for industrial facilities with a case study focus on Louisiana. Our analytical framework includes (1) evaluating the scale and concentration of capturable CO2 emissions at individual facilities for the purpose of estimating the cost of CO2 capture retrofits that utilize various energy supply sources to meet parasitic demands; (2) screening to identify potential CO2 storage sites and estimate their capacities, injectivities, and costs; and (3) designing cost-minimized trucking or pipeline infrastructure connecting CO2 capture plants with storage sites, considering existing land uses, demographics, and a variety of social and environmental justice factors. Estimated levelized costs of capture at Louisiana's 190 industrial facilities range from below $50/tCO2 to above $500/tCO2, depending on facility-specific features. We identified 98 potential storage sites with storage costs ranging from $8 to $17/tCO2. We find that in most situations, pipelines are the least-costly mode of CO2 transport. When industrial facilities in a region share pipelines, aggregate pipeline mileage and average transport costs are dramatically lower than without sharing. Shared pipeline networks designed to avoid disadvantaged communities require right-of-way areas compared to those for networks that transect such communities, but result in 25% higher average per-tonne transport cost.

Strategic Qualitative Risk Assessment of Thousands of Legacy Wells within the Area of Review (AoR) of a Potential CO2 Storage Site

The subsurface confinement of anthropogenic carbon dioxide (CO2) demands robust risk assessment methodologies to identify potential leakage pathways. Legacy wells within the Area of Review (AoR) represent one potential leakage pathway. Robust methodologies require enormous amounts of data, which are not available for many old legacy wells. This study strategically categorizes 4386 legacy wells within the AoR of a potential CO2 storage site in the Illinois basin and identifies the high-risk wells by leveraging publicly available data—reports and well logs submitted to state regulatory agencies. Wells were categorized based on their proximity to the injection well location, depth, the mechanical integrity of well barriers, and the accessibility to these wells throughout the project lifecycle. Wells posing immediate risks were identified, guiding prioritized corrective actions and monitoring plans. Out of 4386 wells, 54 have high priority for corrective action, 10 have medium priority, and the remainder are of low priority. Case study results from the Illinois basin demonstrate the effectiveness and applicability of this approach, to assess the risk associated with legacy wells within the AoR of potential CO2 storage site, strategically categorizing over 4000 such wells despite data limitations.

Reservoir Static Modelling towards Safe CO2 Storage in Depleted Oil Reservoirs of ‘CRK’ Field, Niger Delta, Nigeria

Geological carbon storage (GCS) is gradually gaining acceptance as the technology of highest repute for the mitigation against greenhouse gas effect. This involves the injection and long-term or permanent storage of carbon dioxide (CO2) in subsurface geological formations. The development of a robust 3D reservoir model then becomes necessary to understand the facies changes and the petrophysical properties distribution of candidate CO2 storage reservoirs. This study attempts the use of static modelling technique to investigate the depleted oil and gas reservoirs of ‘CRK’ field in the Niger Delta sedimentary Basin as a potential CO2 storage site. Using an integrated approach of 3D seismic and a suit of well logs from the study area, two reservoir sands (D10C0 and D6200) were mapped. 3D static modelling of discrete and continuous property distribution of the reservoirs revealed the reservoirs are composed majorly of clean sands with water saturation ranging from 8 to 75%. The average porosity and permeability values are between 20 to 29% and 250 to 890mD respectively. A theoretical storage capacity of 24.85Mt is estimated for the two reservoirs combined, while the median effective storage capacity is 6.22Mt. Comparison of the results obtained in the study with recommended standard values show the reservoirs are suitable for CO2 storage. The property models constructed can serve as primary input for dynamic simulation of the oilfield in future studies.

Geomechanical Assessment of Potential Co2 Storage Sites in the Us Shallow Water Gulf Coast

Geomechanical Assessment of Potential Co2 Storage Sites in the Us Shallow Water Gulf Coast

Influence mechanism of interfacial organic matter and salt system on carbon dioxide hydrate nucleation in porous media

CO2 carbon sequestration in marine gas hydrate occurrence areas is a potential way to mitigate the continued growth of CO2 in the atmosphere. The organic matters of marine sediment can affect the phase equilibrium conditions of CO2 hydrate in salt system, and the organic salt system in pore medium has effect on the nucleation growth of CO2 hydrate. The organic matters on the surface of the sediment is mainly composed of lipids, proteins, carbohydrates, and unsaturated hydrocarbon organic compounds, and these polar functional groups weaken the inhibitory effect of salt ions on hydrates through coordination bonds and Ca ion complexation. The nucleation kinetics of CO2 hydrate under organic salt system in pore medium in marine environment is an important parameter determining the carbon sequestration of hydrate. In addition, experimental results show that clay surface organic matters (CSOM) can reduce the surface tension of pore water, and thus pore water migration occurs during hydrate growth and expansion. The basic background in our findings will bring a much better recognition of phase equilibrium conditions among the offshore marine sediment CO2 sequestration process and further assess the location of potential marine CO2 storage sites.

CO2 soluble surfactants for carbon storage in carbonate saline aquifers with achievable injectivity: Implications from the continuous CO2 injection study

Continuous CO2 injection (CCI) into saline aquifers suffers from low sweep efficiency. While utilizing foam can effectively address this issue, a relatively potent foam design may undesirably reduce the injectivity of CO2. In this study, the potential of CO2-soluble surfactants assisted carbon storage in carbonate saline aquifers was evaluated by core flooding tests and numerical simulations. It is found that foam can be generated at the displacement front during continuous CO2 injection with 0.39 g/L surfactant (CCI + S, fg = 100 %). The CO2 saturation can reach 60 % after 1.0 pore volume of CCI + S, approximately 50 % higher than that of CCI. The maximum pressure gradient is around 1.5 psi/ft at an injection rate of 1.0 ft/d in 162 mD Indiana Limestone for CCI + S. The effects of surfactant concentration, foam quality, and rock permeability were also investigated by core flooding. Moreover, the influence of surfactant partitioning and adsorption on CO2 transport behavior was systematically evaluated by numerical simulation in synthetic and geological models, using modeling parameters that are realistic for field applications. The advantage of injecting surfactant with CO2 is more evident in heterogeneous saline aquifers. Such novel injection strategy provides a promising approach for carbon sequestration in saline aquifers by controlling the mobility of CO2 at the displacement front and simultaneously maintaining acceptable injectivity in the field. The CCI + S process may also impose less risk to the caprock. Expanding the potential CO2 storage sites to heterogeneous saline aquifers could be a game-changer. Our understanding of foam dynamics in porous media could also be advanced.

Induced Seismicity Hazard Assessment for a Potential CO2 Storage Site in the Southern San Joaquin Basin, CA

California’s Central Valley offers vast opportunities for CO2 storage in deep saline aquifers. We conducted an induced seismicity hazard assessment for a potential injection site in the southern San Joaquin Basin for 18 years of injection at 0.68 MtCO2/yr and 100 years of monitoring. We mapped stress, faults, and seismicity in a 30 km radius around the site to build a geomechanical model and resolve the stresses on major faults. From a 3D hydromechanical simulation of the CO2 plume, we calculated the change in pressure over time on these faults and determined the conditions for safe injection. Lacking any subsurface imaging, we also conducted a probabilistic fault slip analysis using numerous random distributions of faults and a range of geomechanical parameters. Our results show that the change in probability of fault slip can be minimized by controlling the size, migration, and magnitude of the pressure plume. We also constructed a seismic catalog for the last 20 years around the site and characterized the natural patterns of seismicity. We use these results to establish criteria for evaluating potential-induced events during the storage period and to develop a traffic light response system. This study represents a first-order procedure to evaluate the seismic hazards presented by CO2 storage and incorporate uncertainties in hydrological and geomechanical parameters.

Reactive Transport Modeling and Sensitivity Analysis of CO2–Rock–Brine Interactions at Ebeity Reservoir, West Kazakhstan

This study investigated the reactive transport modeling of CO2 injection into the Kazakhstan reservoir to identify mineralogical and porosity changes due to geochemical reactions. Additionally, sensitivity analysis was performed to test the effect of the surface area and gas impurity on the CO2 storage capability. Despite the current need to investigate carbon sequestration in Kazakhstan, a limited number of studies have been conducted in this field. The Ebeity oil reservoir sandstone formation in the Pre-Caspian Basin has been tested as a potential CO2 storage site. The 1D PHREEQC simulation results of 10,000 years suggest that reservoirs with a higher abundance of these secondary carbonates may be better suited for long-term CO2 sequestration. The concentration of Fe3+ fluctuated, influenced by magnetite and siderite dissolution, leading to ankerite precipitation at 20 and 40 m. The porosity increased from 15% to 18.2% at 1 m and 20 m, favoring a higher CO2 storage capacity, while at 40 m, it remained stable due to minor mineral alterations. A reduced surface area significantly limits the formation of dawsonite, a crucial secondary mineral for CO2 trapping. For instance, at λ = 0.001, dawsonite formation dropped to 6 mol/kgw compared to 24 mol/kgw at λ = 1. Overall, the results of this study can play an essential role in future geological analyses to develop CO2 storage in Kazakhstan for nearby reservoirs with similar geological characteristics.

Palynology of the Triassic–Jurassic transition of the Danish Basin (Denmark): a palynostratigraphic zonation of the Gassum–lower Fjerritslev formations

The Upper Triassic–Lower Jurassic succession in the Danish Basin is penetrated by many deep wells that were drilled during former hydrocarbon exploration campaigns, but it is today targeted for geothermal energy and storage of CO2. The Stenlille salt dome on Sjælland sandstones of the Gassum Formation, sealed by the overlying Fjerritslev Formation mudstones, has been used for decades as a seasonal storage for natural gas. With its comprehensive dataset of seismics, geophysical well logs and conventional core data from 20 wells, the Stenlille succession serves as a model for other salt domes currently being evaluated as potential CO2 storage sites in the basin. Over the last decade the cored Triassic–Jurassic boundary succession has contributed to the understanding of environmental and palynological events during the end-Triassic mass extinction. Core, sidewall core and cutting samples from several of the closely situated Stenlille wells are here used to establish a high-resolution palynostratigraphic zonation scheme covering the entire Rhaetian to Sinemurian succession by integrating new analyses with previously published data. The palynological dataset has allowed the recognition of nine formally described spore-pollen zones, of which eight are new, while two previously described dinoflagellate cyst zones are subdivided into three informal subzones each. The palynological zonation is integrated with a sequence stratigraphic framework and will form the basis for the dating of future well sections in the Danish Basin and other basins and for correlation to outcrops. The large palynological dataset further shows that the vegetation around the Danish Basin was remarkably stable during the early to middle Rhaetian, but that events related to the emplacement of the Central Atlantic Magmatic Province accelerated ecosystem changes for c. 175 ky in the late Rhaetian and earliest Hettangian, including ∼25 ky of successional recovery before the terrestrial ecosystem had again stabilised.

The Kimberlina synthetic multiphysics dataset for CO2 monitoring investigations

AbstractWe present a synthetic multi‐scale, multi‐physics dataset constructed from the Kimberlina 1.2 CO2 reservoir model based on a potential CO2 storage site in the Southern San Joaquin Basin of California. Among 300 models, one selected reservoir‐simulation scenario produces hydrologic‐state models at the onset and after 20 years of CO2 injection. Subsequently, these models were transformed into geophysical properties, including P‐ and S‐wave seismic velocities, saturated density where the saturating fluid can be a combination of brine and supercritical CO2, and electrical resistivity using established empirical petrophysical relationships. From these 3D distributions of geophysical properties, we have generated synthetic time‐lapse seismic, gravity and electromagnetic responses with acquisition geometries that mimic realistic monitoring surveys and are achievable in actual field situations. We have also created a series of synthetic well logs of CO2 saturation, acoustic velocity, density and induction resistivity in the injection well and three monitoring wells. These were constructed by combining the low‐frequency trend of the geophysical models with the high‐frequency variations of actual well logs collected at the potential storage site. In addition, to better calibrate our datasets, measurements of permeability and pore connectivity have been made on cores of Vedder Sandstone, which forms the primary reservoir unit. These measurements provide the range of scales in the otherwise synthetic dataset to be as close to a real‐world situation as possible. This dataset consisting of the reservoir models, geophysical models, simulated time‐lapse geophysical responses and well logs forms a multi‐scale, multi‐physics testbed for designing and testing geophysical CO2 monitoring systems as well as for imaging and characterization algorithms. The suite of numerical models and data have been made publicly available for downloading on the National Energy Technology Laboratory's (NETL) Energy Data Exchange (EDX) website.

The impact of potential leakage from the sub-seabed CO2 storage site on the phosphorus transformation in marine sediments – An experimental study

Carbon Capture and Storage (CCS) in the sub-seabed geological formations is a method of mitigation of carbon dioxide (CO2) emissions to avoid anthropogenic climate change. While CCS can be one of the most promising technologies to reduce atmospheric CO2 in the short and medium term, it raises serious concerns about the potential leakage of gas from storage sites. In the present study, the impact of acidification induced by CO2 leakage from a sub-seabed storage site on geochemical pools, and thus the mobility, of phosphorus (P) in sediment was investigated during laboratory experiments. The experiments were conducted in a hyperbaric chamber at a hydrostatic pressure of 900 kPa, which simulates pressure conditions at a potential sub-seabed CO2 storage site in the southern Baltic Sea. We performed three separate experiments in which the partial pressure of CO2 was: 352 μatm (corresponding pH = 7.7); 1815 μatm (corresponding pH = 7.0), and 9150 μatm (corresponding pH = 6.3). Under pH 7.0 and 6.3, apatite P is transformed into organic and non-apatite inorganic forms, which are less stable than CaP bonds and can be more easily released into the water column. At pH 7.7, P released during mineralization of organic matter and microbial reduction of FeP phases is bound with Ca, and the concentration of this form increases. The obtained results indicate that acidification of bottom water can reduce the efficiency of P burial in marine sediments, which contributes to an increase in P concentration in the water column and promote eutrophication especially in shallow areas.

Numeric determination of relative permeability of heterogeneous porous media with capillary discontinuities

Performance assessment of CO2 storage sites requires realistic modelling of the impact of heterogeneous aquifer properties on brine-CO2 flow. Heterogeneity gives rise to non-uniform saturation distributions that are affected by the balance of capillary, gravitational, and viscous forces. Since equivalent relative permeability and capillary pressure depend on saturation, their shape also varies with flow rate and gravitational phase segregation. This must be considered during performance assessment.Here we present a new workflow for the computation of equivalent relative permeability from force-balance controlled saturation distributions in heterogeneous rocks, computed with a novel continuum-scale flow solver with special provisions for material interfaces. Instead of simulating core flooding, the solver is used to recirculate phases across periodic boundaries until their distribution is in equilibrium with the applied forces.Our workflow is demonstrated on a segmented X-ray scan of a core sample of a laminated sandstone from a potential CO2 storage site in the Surat Basin, Australia, and an outcrop analogue model from Argentina. This application highlights how heterogeneity manifests in multi-phase flow functions, confirming rate dependence after eliminating capillary end effects.

Deep-learning-based 3D fault detection for carbon capture and storage

Fault analysis plays an important role in determining the location of potential CO2 storage sites in which long-term storage feasibility is critical. The presence of faults and fracture zones can potentially lead to the gradual migration of CO2 from the storage reservoir to the atmosphere through the overburden strata. Traditional methods such as manual picking of faults are time-consuming and labor-intensive tasks, which can be costly for the CO2 storage site assessment process. To help address this concern, we develop a process for automating fault picking using deep neural networks. We implement two different deep neural networks based on the architectures of UNet and Deeplab v3+. We train the networks using synthetic data and labels and augment them using linear transformations and elastic deformations. We implement an ensemble-based approach to improve the generalization ability of our method. We also incorporate uncertainty estimation into the framework to aid in the risk management aspect of the decision-making process. We use data sets from different regions across the globe which help us to improve the methodology, with the ultimate aim to help 3D fault detection in the Smeaheia Field, a potential site for CO2 storage scale-up on the Horda Platform, offshore Norway.

APPLICATION OF MUD GAS DATA AND LEAKAGE PHENOMENA TO EVALUATE SEAL INTEGRITY OF POTENTIAL CO2STORAGE SITES: A STUDY OF CHALK STRUCTURES IN THE DANISH CENTRAL GRABEN, NORTH SEA

Depleted chalk oilfields and chalk structures in the Danish Central Graben, North Sea, are potential CO2storage sites. In most of these fields, the main reservoir is the Upper Cretaceous – Danian Chalk Group and the Eocene – Miocene mudstones of the Horda and Lark Formations constitute the primary seal. In a few fields, the reservoir is composed of the Lower Cretaceous Tuxen and Sola Formations. Here the main seal is assumed to be the Chalk Group which however has poor gas sealing characteristics; the Horda and Lark Formations constitute an efficient secondary seal although they are quite high in the section. This study documents a workflow that may help to evaluate the seal integrity of the structures from an integration of mud gas data from wells with seismic data. Mud gas data provide detailed information about the distribution and types of gas (biogenic or thermogenic) throughout the seal section and overburden. The presence of higher carbon number gases (C3–C5, propane to pentane) in the seal indicates migration of thermogenic gas into the thermally immature sealing mudstones; whereas the dominance of C1(methane) and partly C2(ethane) likely reflects the presence of in situ generated biogenic gas in the mudstones, thus indicating that there are no seal integrity issues. The vertical thermogenic gas migration front has been determined, and a “traffic light” indicator system has been used for seal integrity evaluation. Where no or minor migration of thermogenic gas into the primary seal has occurred and a primary seal >30 m thick is present, the seal is considered to have good matrix seal integrity (green). If some significant thermogenic gas migration has occurred into the primary seal but more than 30 m of primary seal is present above the thermogenic gas migration front, the seal integrity is reduced (yellow). In structures where thermogenic gas migration is recorded through the primary seal and into the overburden, seal integrity is considered to be poor (red). In areas where significant leakage of thermogenic gas has occurred into the seal, high density, low porosity carbonate beds frequently occur encapsulated within the sealing mudstones and are interpreted to be composed of methane‐derived authigenic carbonates (MDACs). Seismic data show that there is a convincing correlation between leakage as indicated from mud gas data and the presence of vertical wipe‐out zones (gas chimneys), bright zones (gas‐charged sediments or MDACs), and depressions (pockmarks). In general, potential CO2storage sites in the study area in tectonically inverted structures show good seal integrity, but this may locally be reduced and require additional analyses. Storage sites associated with salt diapirs generally show poor seal integrity and are likely to be poor candidates for CO2storage. In combination, mud gas and seismic data are therefore powerful tools to investigate (palaeo‐) leakage phenomena and provide support for seal integrity evaluation at local to regional scales.

Sources and concentrations of methane, ethane, and CO2 in deep aquifers of the Surat Basin, Great Artesian Basin

Understanding the occurrence and sources of methane in aquifers is an international issue, especially in regions that host oil and gas reservoirs. Multi-isotopic studies are important to understand sources and concentrations of dissolved gases in aquifers of basins that host oil and gas extraction; or future CO2, natural gas, hydrogen storage, or compressed air energy storage. The largest artesian basin in the world, the Great Artesian Basin, extends across more than one fifth of Australia providing a fresh water source from various aquifers. The Precipice and Hutton sandstones, aquifers of the Surat Basin in the eastern Great Artesian Basin, are important water resources for town water supply, agriculture, mines, feedlots, and private landholders in Queensland. Overlying and underlying formations host gas extraction. The southern part of the basin in Queensland additionally hosts an oil field, and potential CO2 storage sites, therefore understanding the aquifer gas concentrations, processes and sources is important for fluid management. The dissolved concentrations of methane and ethane in the Hutton Sandstone were up to 96 mg/L and 1 mg/L respectively, and in the Precipice Sandstone methane ranged up to 2100 mg/L and ethane 6.5 mg/L in the southern Surat Basin. Dissolved gas concentrations were measured by an open and closed sampling method, with the concentrations lower from open sampling, and the gas wetness parameter systematically slightly lower. The Hutton Sandstone aquifer dissolved gas isotopic signatures are mainly consistent with primary microbial CO2 reduction generating methane in situ, with fractionation factors indicating acetate fermentation in a few cases. The Hutton Sandstone δ13C-DIC, δ13C-CO2, and δ13C-CH4 have an enrichment trend with increasing depth that indicate a microbial substrate depletion effect. Moonie Oil Field Precipice Sandstone and Evergreen Formation samples plot in the thermogenic region, with enriched δ13C-CO2 indicating microbial biodegradation is also occurring. The Precipice Sandstone aquifer samples have a mixed microbial CO2 reduction and early mature thermogenic gas signature in both isotope cross plots and gas wetness diagrams, with a subset of sampled δ13C-C2H6 and isotope factors consistent with early mature thermogenic gas. A potential historic source of thermogenic gas is the underlying gas reservoir of the Bowen Basin. Large volumes of water are abstracted from these aquifers, hence dissolved gases may contribute to greenhouse gas emissions.

New direction for regional reservoir quality prediction using machine learning - Example from the Stø Formation, SW Barents Sea, Norway

Recently, the petroleum industry has focused on deeply buried reservoir discoveries and exploring potential CO2 storage sites close to existing infrastructure to increase the life span of already operating installations to save time and cost. It is therefore essential for the petroleum industry to find an innovative approach that exploits the existing core- and well log data to be successful in their endeavor of effectively characterizing and predicting reservoir quality. Continuous data sources (e.g. wireline logs) have a huge potential compared with expensive, time inefficient and sporadic data from cores in determining reservoir quality for use in a regional context. However, whereas core analysis offers in-depth knowledge about rock properties and diagenetic processes, continuous data sources can be difficult to interpret without a formation-specific framework. Here, we demonstrated how the pre-existing core data could be effectively used by integrating petrographic- and facies data with a pure predictive machine learning (ML) based porosity predictor. The inclusion of detailed core analysis is important for determining which reservoir parameter(s) that should be modeled and for the interpretation of model outputs. By applying this methodology, a framework for deducing lithological and diagenetic attributes can be established to aid reservoir quality delineation from wireline logs that can be used in frontier areas. With the ML porosity model, a Random Forest Regressor, the square of the correlation was 0.84 between predicted- and helium porosity test data over a large dataset consisting of 38 wells within the Stø Formation across the SW Barents Sea. By integrating the continuous ML porosity logs and core data, it was possible to differentiate three distinct bed types on wireline log responses within the Stø Formation. Particularly, the relationship between Gamma ray (GR) and porosity was effective in separating high porosity clean sand-, low porosity cemented clean sand and more clay and silt rich intervals. Additionally, in the P-wave velocity (VP) - density domain, separation of high porosity clean sand- and heavily cemented low porosity clean sand intervals were possible. The results also show that the ML derived porosity curves coincide with previously published and independent facies data from a selection of the wells included in the study. This demonstrates the applicability of the model in the region, because the Stø Formation has been described to exhibit similar lithological- and mineralogical properties over large parts of the Western Barents Sea area. Even though, continuous porosity data could be estimated from other sources like VP, neutron or density logs, this would generally require matrix and fluid information. This study demonstrated the effectiveness of the ML model in generating continuous porosity logs that are useful for characterizing and predicting reservoir properties in new wells. This methodology offers a workflow for exploiting already acquired core and well log data for frontier exploration that can be adapted to other formations and exploration scenarios worldwide.

Top seal assessment of Drake Formation shales for CO2 storage in the Horda Platform area, offshore Norway

Evaluating top seal integrity is crucial for successful subsurface CO2 storage. Caprock shale geomechanical properties are complex and influenced by various parameters and processes. It is challenging to understand the role of various factors affecting the geomechanical properties; therefore, an integrated approach is required to evaluate top seal shales. In this study, we investigated the caprock properties of the Early Jurassic shaly Drake Formation overlying the reservoir sandstones of Early Jurassic Cook and Johansen formations. The study area is the potential CO2 storage site Aurora (the Longship CCS project), located in the Horda Platform area, offshore Norway. Based on lithological variations, the Drake Formation is subdivided into upper and lower Drake units. Variations of the geomechanical properties are investigated using wireline logs from 50 exploration wells, two 3D seismic cubes, and several 2D seismic lines. Elastic property-based brittleness indices of the Drake Formation caprock shales are evaluated to identify possible top seal quality. Moreover, seismic attributes and gas leakage scenarios are investigated qualitatively to assess the possibility of injected CO2 escaping from the reservoir. Low brittleness indices value of the Drake Formation shale near the Aurora injection site indicated that the seal rock might diffuse the injection-related stress change and act as an effective top seal. Based on the integrated qualitative assessment, it is likely that the Drake caprock shale will be acted as an effective top seal in and around the Aurora storage site. However, due to the complex nature of caprock shales, we recommend field-scale numerical simulation to evaluate the injection-induced stress-strain effect.

Induced-seismicity geomechanics for controlled CO2 storage in the North Sea (IGCCS)

The aim of the current study, IGCCS (2017–2020), is to evaluate the feasibility of micro-seismic (MS) monitoring of CO2 injection into representative storage candidates in the North Sea, based on broad and quantitative characterization of relevant subsurface behavior with respect to geology, geomechanics and seismicity. For this purpose, we first group potential CO2 storage sites in the North Sea into three different depths. Then, advanced triaxial rock mechanical tests are performed together with acoustic emission (AE) acquisition under representative loading for CO2 storage sites in the North Sea and for formations of each depth group, covering shale, mudstone and sandstone cores. Our work focuses particularly on quantifying the effects of injected fluid type and temperature on mechanical behavior and associated MS response of subsurface sediments. The experiment results show that each depth group may behave differently in responses to CO2 injection. Particularly, the occurrence of detectable MS events is expected to increase with depth, as the combined effects of rock stiffness and temperature contrast between the host rock and injected CO2 are increasing. In addition, lithology plays an important role in terms of the MS response, i.e. high AE event rate is observed in sandstones, while aseismicity in shale and mudstone. The test results are then scaled up and applied to advanced coupled flow-geomechanics simulations and a synthetic field-scale MS data study to understand micro-seismicity at fracture, reservoir and regional scales. The numerical simulation of scCO2 injection scenario shows quite different stress-strain changes compared to brine injection, resulting mainly from the thermally-induced behavior. Furthermore, the numerical simulation study via so-called Cohesion Zone Modeling (CZM) approach shows strong potential to improve our understanding of the multiphase-flow-driven fracture propagation. Our synthetic MS data study, focused on slow-earthquake scenario, also suggests that sensors with high sensitivity at low frequency might be necessary for better signal detection and characterization during CO2 injection. This manuscript covers the main findings and insights obtained during the whole study of IGCCS, and refers to relevant publications for more details.

Effect of overburden spatial variability on field-scale geomechanical modeling of potential CO2 storage site Smeaheia, offshore Norway

Although geological CO2 sequestration is an essential solution for reducing anthropogenic carbon dioxide from the atmosphere, the method needs critical evaluation of injection-induced mechanical risks for safe and reliable CO2 storage. 3D field-scale geomechanical modeling is a preeminent solution for assessing mechanical risks of subsurface geological CO2 storage. However, data scarcity of seals and overburden rocks might limit building the 3D field-scale geomechanical model. This study focuses on seismic data-derived 3D field-scale geomechanical modeling of potential CO2 storage site Smeaheia, offshore Norway. The geomechanical properties inverted from seismic data are resampled in the 3D grid to consider spatial variabilities of seal and overburden rock properties. This method allows us to investigate the effect of overburden rock spatial variability imposed in seismic data on the 3D geomechanical model of Smeaheia. The model was built in Petrel-2019, while the one-way geomechanical simulation is iterated using the finite element method. Simplified constant overburden property models are also constructed to analyze the sensitivity of the overburden rock properties. The results reveal that the seismic data-driven spatially distributed overburden properties model workflow used in this study is a convenient and robust solution for 3D field-scale geomechanical modeling. The maximum vertical estimation of rock deformation is doubled in the simplified (isotropic) overburden rock property model compared to the new spatially variable (anisotropic) overburden rock property model. The Mohr-Coulomb failure envelope reveals that the new modeling approach is less prone to failure than the simplified (isotropic) model, which might influence the project decision. Moreover, our study demonstrates the importance of considering the spatial variability of overburden rock properties in building the 3D field-scale geomechanical model.