Potential CO2 Storage Sites Research Articles

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.

Lateral distribution of the upper Amundsen shale in potential CO2 storage site Aurora, northern North Sea

Lateral distribution of the upper Amundsen shale in potential CO2 storage site Aurora, northern North Sea

Screening for Geologic Sequestration of CO2: A Comparison Between SCO2TPRO and the FE/NETL CO2 Saline Storage Cost Model

Meeting greenhouse gas emission reduction targets will likely require identifying and assessing subsurface storage space for sequestering billions of tonnes of CO2 each year. Accomplishing this feat could include estimating the cost and capacity for thousands to hundreds-of-thousands of potential geologic CO2 storage sites with CO2 storage screening tools. In this study, we introduce a screening tool, SCO2TPRO, and compare and contrast it to the FE/NETL CO2 Saline Storage Cost model (CSSC) using publicly available databases of saline reservoir properties in the United States. We find that the two tools use different methodologies to execute site-screening: SCO2TPRO calculates dynamic CO2 injection rates and plume evolution that are used to estimate operationally-realistic well spacing designs and CO2 storage capacities, whereas CSSC combines a volumetric storage estimation approach with geology-engineering well injectivity equations that can lead to an unrealistically high number of wells. These methodological differences translate into CSSC cost estimates that are several times higher than the SCO2TPRO estimates and around double for the capacity estimates. SCO2TPRO can also screen thousands of potential storage sites in seconds, which is thousands of times faster than CSSC. Lastly, we also find there is no single publicly available dataset of saline formation properties that can be used for screening across the United States.

Storage Readiness Levels: communicating the maturity of site technical understanding, permitting and planning needed for storage operations using CO2

A framework of Storage Readiness Levels (SRLs) is presented to communicate the entirety of technical appraisal, permitting and planning activities achieved at a potential CO2 storage site and what remains to be completed for CO2 storage operations. The schema, based on learning gained from the experience of researchers, regulators and industry from the 1990s, is described and assessed by application to 742 saline formation and hydrocarbon field sites, offshore the UK, Norway and The Netherlands. The framework is flexible to accommodate national differences in procedures and practise and the unique character of each site. It is applicable regardless of the time-scale of appraisal or scale of assessment. The framework is consistent with and extends the industry commercial project development classification to include categories for sites with a lesser level of data and evaluation. Application to the phases of appraisal of three sites illustrates that investigations may advance understanding by different pathways and rates. The standardised framework enables comparison of the experience of permitting and planning activities completed within different jurisdictions, the level of investment and the duration required to achieve permitted or permit-ready sites. It is intended that the framework of SRLs should be widely applied.

Cellular level response of the bivalve Limecola balthica to seawater acidification due to potential CO2 leakage from a sub-seabed storage site in the southern Baltic Sea: TiTank experiment at representative hydrostatic pressure

Understanding of biological responses of marine fauna to seawater acidification due to potential CO2 leakage from sub-seabed storage sites has improved recently, providing support to CCS environmental risk assessment. Physiological responses of benthic organisms to ambient hypercapnia have been previously investigated but rarely at the cellular level, particularly in areas of less common geochemical and ecological conditions such as brackish water and/or reduced oxygen levels. In this study, CO2-related responses of oxygen-dependent, antioxidant and detoxification systems as well as markers of neurotoxicity and acid-base balance in the Baltic clam Limecola balthica from the Baltic Sea were quantified in 50-day experiments. Experimental conditions included CO2 addition producing pH levels of 7.7, 7.0 and 6.3, respectively and hydrostatic pressure 900 kPa, simulating realistic seawater acidities following a CO2 seepage accident at the potential CO2-storage site in the Baltic. Reduced pH interfered with most biomarkers studied, and modifications to lactate dehydrogenase and malate dehydrogenase indicate that aerobiosis was a dominant energy production pathway. Hypercapnic stress was most evident in bivalves exposed to moderately acidic seawater environment (pH 7.0), showing a decrease of glutathione peroxidase activity, activation of catalase and suppression of glutathione S-transferase activity likely in response to enhanced free radical production. The clams subjected to pH 7.0 also demonstrated acetylcholinesterase activation that might be linked to prolonged impact of contaminants released from sediment. The most acidified conditions (pH 6.3) stimulated glutathione and malondialdehyde concentration in the bivalve tissue suggesting potential cell damage. Temporal variations of most biomarkers imply that after a 10-to-15-day initial phase of an acute disturbance, the metabolic and antioxidant defence systems recovered their capacities.

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.

Seismic-derived geomechanical properties of potential CO2 storage reservoir and cap rock in Smeaheia area, northern North Sea

Geologic CO2 storage site selection requires reservoir, seal, and overburden investigation to prevent injection- and storage-related risks. Three-dimensional geomechanical modeling and flow simulation are crucial to evaluate these mechanical-failure-related consequences; however, the model input parameters are limited and challenging to estimate. This study focuses on geomechanical properties extracted from seismic-derived elastic property cubes. The studied reservoirs (Middle Jurassic Sognefjord, Fensfjord, and Krossfjord formation sandstones) and cap rocks (Heather and Draupne formation shales) are located in the Smeaheia area, northern North Sea, and are evaluated for a potential CO2 storage site. From the elastic property cubes, i.e., acoustic impedance, P- to S-wave velocity ratio, and bulk density, we obtained geomechanical property cubes of Young's modulus, Poisson's ratio, shear modulus, lambda-rho, and mu-rho. Petrophysical property cubes such as porosity and shale volume were also available and were extracted from the elastic property cubes using deterministic methods. We evaluated the geomechanical properties to observe their relationship with depth, compaction/cementation, and petrophysical properties to characterize the cap and reservoir rocks. We found good coherence between the geomechanical and petrophysical properties and their relationship with compaction as a function of depth. The brittleness analyses using elastic property crossplots reveal that both the cap and reservoir rocks are mainly ductile to less ductile, posing lower fracturing risk during CO2 injection. This also indicates lower risks of associated microseismic and possible CO2 leakage.

Probabilistic analysis of Vette fault stability in potential CO2 storage site Smeaheia, offshore Norway

Reliable assessment of fault stability is key for safe CO2 storage in a saline aquifer in fault-bounded structures. The Alpha structure located in the Vette fault's footwall in the Smeaheia area, offshore Norway, is one of the potential CO2 storage sites with a fault-bounded three-way closure. Assessing fault stability in the Smeaheia area is challenging because of the uncertainties associated with the subsurface fault properties (i.e., fault rock lithologies, strength and geometry of faults, etc.). Besides, CO2 injection-related pore pressure changes is another critical factor for mechanical deformation and potential failure. We employed a stochastic analytical approach to assess the probability of Vette fault failure using the Monte Carlo Simulation (MCS) and First Order Reliability Method (FORM). The possible fault smear scenarios of the Vette fault zone are evaluated by interpreting the seismic section and the detailed geological understanding. Each scenario's likelihood and the corresponding probability of failure are then integrated stochastically using an event tree method. Overall, Vette fault's system reliability shows a good to average performance range, which has a system probability of failure between 10−3 to 10-4. This finding suggests that the Vette fault will likely act as a potential barrier during CO2 injection into the Alpha structure. Moreover, the sensitivity study reveals that the stresses (both horizontal and vertical) and fault rock strength (i.e., cohesion and friction angle) are the most crucial parameters to characterize uncertainty reduction.

How to Evaluate and Quantify Safe CO2 Storage? Workflow Demonstration on the Smeaheia Area, Offshore Norway

A question that is often raised during discussing around underground CO2 storage in saline quifers, is whether the stored CO2 will stay in place, and how to evaluate and quantify safe storage and ensure acceptable low seepage. In this study a workflow has been tested on a potential subsurface CO2 storage site at the Smeaheia area, offshore Norway. The effect of the pressure depletion from the giant gas Troll Field, starting production in 1995 has been simulated. As a conformance test, the simulated pressure has been compared with measured pressures from a newly drilled exploration well in the study area, with good match. Simulated pressures have used as input to simulate CO2 injection and saturation varying the reservoir heterogeneities. Different conformance tests have been discussed using bottom hole pressure to evaluate potential CO2 injection, or collection new seismic.

A Study of Temperature Effects in the Bunter Closure 36, a Potential Large-scale CO2 Storage Site in UK

This paper reports on numerical thermal studies of cold CO2 injection into the Bunter Closure 36 prospect, analysing temperature effects during the injection and assessing the time required by the aquifer to recover the initial natural temperature. Fluid flow properties and pressure variation in the injection area are analysed, assessing different cooling scenarios that might occur depending on the thermal properties of the geology surrounding the storage site. Different thermal modelling approaches are presented, discussing some aspects of input data and setup. Information from thermal simulation studies might feed injection design, geo-mechanical analysis, and monitoring of CO2 migration.

Containment Risk Assessment of the Northern Lights Aurora CO2 Storage Site

Assessment of containment (storage site integrity) is a key activity in the evaluation, and a requirement for approval, of potential CO2 storage sites. Here we present the workflow used for, and key results of, the containment risk assessment (CRA) in the Northern Lights project, which is the transport and storage part of the Norwegian “Longship” full-scale CCS project. In the Northern Lights project, CO2 storage is planned to take place at the Aurora site (Exploitation license EL001), southwest of the Troll Field. Injection is planned into the sandstone-rich Johansen Formation (Lower Jurassic Dunlin Group). The argillaceous upper member of the Dunlin Group, the Drake Formation, provides the main seal for the storage reservoir. Several further barrier and baffle units and intervening sandstones are present between the Drake Fm. and the sand-rich units of the Viking Group, which contain the giant Troll field with a high level of depletion to date. The injection site is located downdip of – and stratigraphically deeper than – the Troll West gas province (TWGP). Injected CO2 is expected to move slowly over time buoyancy-driven up-dip (northwards), with a small proportion reaching eventually the structural trap underneath the TWGP. A key method utilized in the Aurora CRA is the bowtie method. Bowties were prepared for each identified “leakage” pathway (according to the definition in the EU CO2 Storage Directive, thus not implying any emission to the water column) instead of per “leakage” mechanism, as has been the case in previous CO2 storage CRAs. The bowties were designed to allow for updates, which took place as new data or interpretations became available. A major update occurred after drilling of a confirmation well at the planned injection site. Key results of the CRA are that the probability of any emissions into the water column due to “leakage” of CO2 out of the storage complex is very low to negligible. Important arguments for this conclusion are (i) the hydraulic separation of the Johansen Formation from the shallower, depleted Viking Group, as attested by pressure data in the confirmation well, and (ii) the proven effectiveness of the seal to the Viking Group sandstones, which have accumulated and stored hydrocarbons over geological time. Further, any CO2 reaching and blending into the hydrocarbon accumulations nearby (such as the Troll Field) is regarded to also have very low probability. Storage Complex Monitoring (SCM) is an integral element of the CRA to enable mitigating actions in case of indications for unpredicted behaviour or “leakage” of the injected CO2.

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

In this study (IGCCS), we evaluate the feasibility of micro-seismic (MS) monitoring of CO2 injection into storage candidates in the North Sea to ensure safe operations. MS monitoring relies on measuring seismic signals resulting from abrupt subsurface movements such as the (re)-activation of faults and fractures. To be successful, MS monitoring technique requires a broad quantitative characterization of the subsurface behavior concerning its geology, geomechanics, and seismicity. Hence, we performed advanced triaxial tests combining with acoustic emission (AE) acquisition, followed by advanced coupled flow-geomechanics simulations to understand micro-seismicity more quantitatively. The test results are then scaled up and applied to a synthetic field-scale seismic data study. We tested shale, mudstone, and sandstone cores under confining and pore fluid pressure, with loading conditions that are representative of potential CO2 storage sites in the North Sea. Our work focuses on quantifying the effects of injected fluid type and temperature on mechanical behaviour and associated MS response of subsurface sediments. The current manuscript covers only the main findings and insights obtained during IGCCS, and for more details, refers to relevant publications resulting from IGCCS.

Organic-rich shale caprock properties of potential CO2 storage sites in the northern North Sea, offshore Norway

Assessment of the geomechanical properties of organic-rich shale caprocks is critical for a successful CO2 storage into a saline aquifer. In this study, we investigated the geochemical properties of the organic-rich shale caprocks of the Draupne and Heather formations, overlying the potential sandstone reservoirs of Sognefjord, Fensfjord, and Krossfjord formations in the northern North Sea, offshore Norway. The caprock's depositional variations within the sub-basins are established by analyzing the gamma-ray shape and stacking patterns. The effect due to differences in depositional environments, on the caprock compaction behavior is investigated by integrating petrographical analysis of core and cutting samples from 3 wells and by rock physical analysis of wireline log data from 27 exploration wells. Three rock physics templates are used where the wireline log data are interpreted using the published background trends. The effect of kerogen type, maturation level, and deposition environment on caprock properties within the study area are also evaluated. Moreover, the caprock property, such as brittleness, is estimated by using four mineralogy and elastic property-based, empirical relations, which is a quantitative measure of caprock property with respect to changes in stress-state. Finally, the seismic inversion method is assessed for the possibility of extracting caprock properties from surface seismic data. Regardless of compaction processes, the results indicate that the Heather Formation is mechanically stronger than the Draupne Formation. However, both formations appear to be ductile in nature. The depositional environments control the mineralogical composition and fabric of the Draupne and Heather formations, which influence the caprock properties significantly. Results also show that the effect of TOC on caprock properties is insignificant in the study area. The brittleness of the organic-rich shale caprocks in the study area follows a different trend compared to the published trends. We also observed an excellent correlation between the log-derived elastic properties and geomechanical parameters. Still, it is difficult to assess the caprock elastic properties from seismic due to the overlap of data clusters. The evaluation of caprock geomechanical behaviors is challenging as these properties are site-specific and also influenced by other factors such as exhumation, in-situ stress conditions, the existence of natural fractures, and their orientations.

Structural analysis of the Smeaheia fault block, a potential CO2 storage site, northern Horda Platform, North Sea

Smeaheia, a prominent fault block located on the Horda Platform, northern North Sea is identified as a potential subsurface CO2 storage site. We utilise the GN1101 3D seismic survey to generate a high-resolution subsurface geomodel to inform the structural style and evolution of the fault block, to investigate geological controls on proposed CO2 storage and provide a geometric framework as a basis for future analyses. Two basement-involved (first-order) north-south trending fault systems, the Vette Fault Zone (VFZ) and the Øygarden Fault Complex (ØFC), bound the 15 km-wide fault block. The VFZ bifurcates down-section where it is hard-linked with two separate basement structures, a phenomenon we term as “dual rooted”. Apart from activity during the Permo-Triassic (Rift Phase 1) and the Late Jurassic–Early Cretaceous (Rift Phase 2), we present evidence that rifting in this part of the North Sea continued into the Late Cretaceous with minor reactivation in the Palaeocene–Eocene. Two segments of the VFZ interacted and linked at a relay ramp during Rift Phase 2. Second-order (thin-skinned) faults show basement affinity and developed during Rift Phase 2 in two distinct pulses. A population of polygonal faults intersects the overburden and developed during the Eocene to middle Miocene. We have revised the areal extent of two structural closures that define the Smeaheia fault block, Alpha (VFZ footwall) and Beta (ØFC hanging wall) which consist of Upper Jurassic Viking Group target formations. Simplified cross-fault juxtaposition analysis of the VFZ and second-order intra-block faults are presented and inform pressure communication pathways between the Smeaheia and Tusse fault block, as well as reservoir integrity and compartmentalisation. The geomodel further identifies important geological controls on CO2 storage in the fault block including a thinning caprock above the Alpha structure, and identification of hard-linkage between deep tectonic faults and shallow polygonal faults.

Petrophysical characterization of deep saline aquifers for CO2 storage using ensemble smoother and deep convolutional autoencoder

Carbon dioxide sequestration in deep saline aquifers requires accurate and precise methods to monitor carbon capture and storage and detect leakage risks. The assessment of the CO2 plume location during injection and storage depends on the accuracy of the spatial distribution model of petrophysical properties, such as porosity and permeability. This work focuses on stochastic methods for petrophysical characterization and presents a method for the prediction of porosity and permeability using borehole observations and surface geophysical data. This study utilizes injection and monitoring measurements at the borehole locations and time-lapse seismic surveys. The proposed method is based on a stochastic approach to inverse problems with data assimilation, namely the ensemble smoother with multi-data assimilation. Ensemble-based methods are generally unfeasible when applied to large geophysical datasets, such as time-lapse seismic surveys. In the proposed approach, a machine learning method, namely the deep convolutional autoencoder, is applied to reduce the dimension of the seismic data. The ensemble smoother is then applied in a lower dimensional data space to predict the aquifer petrophysical properties. This method updated predictions of porosity and permeability every time new data, either seismic surveys or borehole data, are available, to reduce the uncertainty in the CO2 plume prediction. The method is tested and validated on a synthetic geophysical dataset generated for the Johansen formation, a potential large-scale offshore site for CO2 storage.

Quantifying Intraformational Seal in a Coal-Rich Sedimentary System

The Gippsland Basin, situated in Bass Strait, Australia, contains excellent potential CO2 storage sites in a nearshore zone where there is optimum development of reservoir and seal units. A particular focus for the CarbonNet project is intraformational seals of the Middle Eocene (and older) Traralgon sequence in this nearshore zone. The seals are a combination of conventional shale seals (including seat earths) and coal beds. Thick units of coal with interbedded shale function are proven to contain oil and gas accumulations for millions of years in the local area and display pressure and salinity evidence of seal behaviour between different subsurface aquifers. 3D seismic mapping of the seal units demonstrates that they are continuous across wide areas, but that there are local minor faults and fractures. Studies of shale and coal properties, fault geometries, and interactions with the low-permeability units and varied lithologies demonstrate that the Traralgon sequence contains valid seals for large columns of CO2 and will store CO2 for extended periods before final dissolution into meteoric offshore aquifers.

Characterization and Classification of CO2 Storage Sites on the Norwegian Continental Shelf

Depending on their specific geological properties, several types of geological formations can be used to store CO2. In the North Sea Basin, the greatest potential capacity for CO2 storage will be in deep saline-water saturated formations or in depleted oil and gas fields. The results presented in the CO2 Storage Atlas are based on studies of all relevant geological formations and hydrocarbon fields on the Norwegian Continental Shelf (NCS). Norwegian Petroleum Directorate (NPD) has access to all data collected from the petroleum industry and has a national management responsibility for these data. This is vested in the Norwegian Petroleum Law. More than 50 years of petroleum activity has generated a large quantity of data. These data and analyses together with many years of dedicated work to establish geological play models, have given us a good basis for the characterization and classification of potential CO2 storage sites. The first step in site selection is the screening of potentially suitable formations and structures using specific criteria. In the site selection process, it should be demonstrated that the potential sites have sufficient capacity to store the expected CO2 volume and sufficient injectivity for the expected rate of CO2 capture and supply. The integrity of the site must be assessed for the period required by the regulatory authority to avoid any unacceptable risks to the environment, human health or other uses of the subsurface. The aquifers were evaluated regarding reservoir quality and presence of relevant sealing formations. Those aquifers that may have a relevant storage potential in terms of depth, capacity and injectivity have been considered. The most attractive aquifers and structures were investigated by geomodelling and reservoir simulation. In all models, it is assumed that there will be no water production. The volumes of injected CO2 are constrained by the fracturing pressure. Our estimates of fracturing pressures are based on a large data base of leak-off tests and pore pressures in exploration wells. The regional fracture pressure trends are quite similar in North Sea and Norwegian Sea shelf, and somewhat lower in deeply eroded areas in the Barents Sea. The scores for capacity, injectivity and seal quality are based on evaluation of each aquifer/structure. The checklist for reservoir properties gives a more detailed overview of the important parameters regarding the quality of the reservoir. These parameters are set into different checklists for detailed grading.

Overview of Investigation of Potential CO2 Storage Sites Offshore Japan

Japan CCS Co., Ltd. (hereinafter “JCCS”) has been conducting the investigation of potential CO2 storage sites in Japan undercontract to the Ministry of the Environment (hereinafter “MOE”) and Ministry of Economy, Trade and Industry (hereinafter“METI”) of Japan since 2014. We have been conducting a number of 2D/3D seismic surveys and geological interpretation at pre-selected areas in offshore Japan, in order to identify prospective sites from among these areas. Several candidate sites will be selected from these prospective sites, and exploratory wells will be drilled to confirm the presence of geological conditions necessary for storage. The drilling will be followed by the construction of a geological model and flow simulation. The final goal of the current scope of work is to recommend three potential sites for CO2 geological storage to MOE and METI by around 2021. The main selection criteria of a potential storage site are as follows: > The potential sites should be located in offshore areas > Capacity of each site is to store over 100 million tonnes of CO2 > There are no active faults close to the site > The existence of a CO2 emission source near the site is not taken into consideration > The method of CO2 transportation to the site is not taken into consideration > Producing oil and gas fields are excluded (site is not for EOR purpose) > There is no environmental protected area around the site In addition, a preferable condition is whether the site can be reached by directional drilling from onshore, as is the case for the Tomakomai CCS Demonstration Project. In this project, two directional CO2 injection wells were drilled with horizontal reach of over 3,000 meters, saving considerable construction cost as it was not necessary to bring in an offshore drilling rig, or to lay expensive subsea pipelines and related offshore facilities. The 2D/3D seismic survey conducted in the investigation of potential sites is the most effective method to delineate the geological features of the subsurface. 2D seismic surveys are conducted to grasp the regional geological features over a wide range such as 50 x 100 km, and if prospective structures for CO2 geological storage are identified, 3D seismic surveys over a smaller range (e.g., 10 x 10 km) will be executed to delineate the geological features more precisely. When necessary, we employ state-of-art seismic acquisition and processing technology utilized in the oil and gas industry to accomplish our objectives. In one of the 3D seismic surveys, we have conducted a seamless 3D seismic survey across the transition zone between shallow marine and onshore. As the possible presence of active faults was suspected in the transition zone, there was a need to collect data from the shallow marine continuously to the onshore area. Although the survey has taken time and effort, we were able to fill the gap in the existing seismic data between offshore and onshore with data of reasonable resolution utilizing an Ocean Bottom Cable (OBC). The geological interpretation found that the subsurface of the transition zone was a narrow synclinal valley along the current coastline with no active faults present, and therefore that it was possible to store CO2 in the offshore area as it was safely isolated from the populated onshore area. At another prospective site, we have conducted a 3D seismic survey utilizing broadband technology; the first application of this state-of-art technology in Japan. Because the target sandstone reservoirs in the survey area are composed of deep marine sediments such as turbidites and submarine fans, high-resolution 3D seismic data is required to differentiate the sandstone types. The high resolution data may be further utilized for special processing such as acoustic impedance (AI) inversion and amplitude versus offset (AVO) analysis which is help to evaluate rock properties in order to reduce geological risk. The high resolution near surface data acquired in broadband technology is also useful in identifying shallow gas hazards in the area. In BroadSeisTM(*), the broadband seismic technology we adopted, the slanted streamer cables are deployed deeper than conventional seismic surveys, mitigating the effects of sea surface swells and wave noises under rough sea conditions. As a result, we were able to reduce drastically the downtime due to rough weather during the survey period. (*: trademark of CGG) In summary, the application of state-of-art seismic acquisition technology in the investigation of potential CO2 storage sites is expected to reduce geological risk as well as contribute towards saving acquisition costs.

Three‐dimensional geophysical characterization of the La Rambla and Zafra de Záncara anticlines (Loranca Basin, Central Spain)

ABSTRACTThe Zafra de Záncara anticline (also known as the El Hito anticline), located in the Loranca Cenozoic Basin (part of the Tagus Basin, Central Spain), had been studied by several oil companies during the late 1960s and early 1970s. In 2009, within the ‘Plan for selection and characterization of suitable structures of CO2 geological storage’, this anticline was selected as a potential CO2 storage site. A preliminary three‐dimensional geological model, based on five geological cross sections that were constrained with the interpretation of the available seismic profiles (that are rather old and do not have very good quality), was created. With the aim of improving the geological knowledge of the Zafra de Záncara anticline and helping to investigate the suitability of a nearby anticline, namely La Rambla, as another structural closure that might make it a possible CO2 storage site, a local gravity survey (1 station every km2) was carried out in the area, seven new geological cross sections, based on these existing seismic profiles and field geology, were build, and a new three‐dimensional geological model that included both anticlines, improved through three‐dimensional stochastic gravity inversion, was constructed. The densities needed for the geological formations of the model come from the analysis of rock samples, logging data from El Hito‐1 drillhole and petrophysical information from Instituto Geológico y Minero de España database. The inversion has improved the knowledge about the geometry of the anticlines’ traps and seals as well as the geometry of the basement relief and the structural relationship between basement and cover.

Chemo‐mechanical behavior of clay‐rich fault gouges affected by CO2‐brine‐rock interactions

AbstractThe impact of long‐term CO2‐brine‐rock interactions on the frictional properties of faults is one of the main concerns when ensuring safe geological CO2 storage. Mineralogical changes may alter the frictional strength and seismogenic potential of pre‐existing faults bounding a storage complex. However, most of these reactions are too slow to be reproduced on laboratory timescales and can only be assessed using geochemical modeling. We combined modeling of CO2‐charged formation water and fault gouges (1–1000 years residence time, i.e. 10–106 pore volume flushes) with friction experiments on simulated fault gouges (T = 22–150°C; σneff = 50 MPa; Pf = 25 MPa; V = 0.2‐100 μm/s), having mineralogical compositions as predicted by the models. As an analogue for clay‐rich caprocks overlying potential CO2 storage sites in Europe, we used the Opalinus claystone. Our experiments showed that, although significant mineralogical changes occurred, they did not significantly change the frictional behavior of faults. Instead, initial fault‐gouge mineralogy imposed a stronger control on clay‐rich fault behavior than the extent of CO2‐brine‐rock interactions, even under chemical conditions allowing for significant reaction. We demonstrated that the impact of mineralogical changes due to CO2‐brine‐rock interactions on the frictional behavior and seismogenic potential of faults could be assessed using our combination of geochemical modeling and friction experiments. Note that a complete understanding requires evaluation of additional effects, such as that of shear velocity, effective normal stress, and other fault characteristics (maturity, shear strain). © 2018 The Authors. Greenhouse Gases: Science and Technology published by Society of Chemical Industry and John Wiley & Sons, Ltd.