Geological sequestration of CO2 is one of the most promising technologies to mitigate the greenhouse effect by decreasing the anthropogenic CO2 emissions into the atmosphere. Deep saline reservoirs are a suitable target for CO2 storage because very often they can be found relatively close to today's large CO2 releasing sources. To investigate the chemical and physical impacts of a CO2-rich brine solution injection to a quartz rich sandstone, we flooded a Berea Sandstone core sample with CO2-saturated synthetic brine at the elevated temperature (60°C) and pressure (20MPa). After flooding, the porosity and permeability of the core were measured and compared to the pre-flooding values. We found that the porosity had increased by 1.8% while the permeability decreased by 5.1%. The decrease in permeability may be attributed to the movement of particles in the pore space of the sample (fines migration) and/or sample's physical compaction under net effective stress. Effluent brine samples were also collected during the core-flood experiment to be analysed for their chemical composition. We found that, on average, the concentration of Ca2+, Mg2+ and Fe2+ in the effluent samples to increase by approximately 100mg/l, 80mg/l and 95mg/l, respectively, with traces of other metals. It is believed that the Ca2+, Mg2+ and Fe2+ were liberated from the dissolution of the carbonate cement in the sample. As revealed by the differential pressure evolution of the experiment, for the quartz-rich sandstone reservoirs, where fines migration is not significant and reactive minerals are scarce, the injectivity may not be affected during the fluid injection process.
Deep saline aquifers are widely considered for injection/disposal of fluids (e.g. CO2 and wastewater) in the subsurface. However, target injection aquifers may be overlain by a regionally leaky caprock, which allows for fluid migration from the injection zone. In addition, target aquifers may also be intersected by leaky faults, which can accommodate leakage by connecting the target aquifer to other permeable zones. Leakage from the injection zone to an above permeable zone will be associated with pressure rise in that zone. The above zone pressure response has recently been extensively investigated in studying leakage in the context of CO2 geological sequestration. Both leaky fault and leaky caprock are considered as potential leakage pathways. Before analyzing above-zone pressure response for leakage characterization, it is important to determine whether the feature causing leakage is a fault or the semi-pervious caprock. The focus of this study is to provide a diagnostic tool to identify the leaky fault from a leaky caprock based on the pressure response.
A fault is a planar interface that can act as a conduit both normal and through the fault plane. Caprock is a very low permeability medium which is assumed to act as sealing layer to the reserved fluids. However, there may be heterogeneities associated with regional permeability variations in the caprock, which can accommodate leakage. An injection well makes a local high pressure region near the well that may result in significant leakage through the caprock or a fault intersecting the reservoir.
In this work, we investigate leakage from an injection layer into an overlying layer through a leaky fault and a leaky caprock based on the pressure changes. We present analytical models for pressure response to interlayer communication via a caprock and a leaky fault. The fault leakage causes a linear flow in the overlying layer. However, leakage through the cap rock is different in nature for which most leakage occurs at the vicinity of the injection well The flow regime occurred in the above-zone due to leakage are the base of our method to identify the leaky fault from the leaky caprock. Results show that fault leakage makes linear flow and caprock leakage show late-time radial flow in the above-zone. In order to detect these flow regimes by the common pressure transient analysis methods, the observed pressure in the above-zone must be normalized based on the time variable leakage rate.
Carbon dioxide sequestration (CCS) is one of the technologies utilized for pollution mitigation. Most sequestration processes take place in saline aquifers due to their availability and large storage capacity. The effectiveness of sequestration process, CO2 injectivity, plume migration and trapping is highly dependent CO2-brine displacement and formation heterogeneity. This work presents three saline formations investigated as potential candidates for CCS. These are the St. Peter sandstone formation, Knox sandstone formation, and upper sandstone and lower dolomite Sylvania formation. Composite cores of each formation were used for displacement runs and drainage CO2-brine relative permeability curves were constructed implementing steady and unsteady state techniques. The results indicate a close match of the End-points saturation and relative permeability for both steady and unsteady state techniques. The three formations show relatively low CO2 end-point relative permeability (Krg) in the range of 0.064 to 0.186 corresponding to residual brine saturations as high as 0.431 to 0.251 for St. Peter and upper interval of Sylvania formation respectively. These low values are attributed to rock heterogeneity controlling the displacement efficiency as indicated by saturation distribution profiles determined from the computer tomography scanner images. Scattered plug to plug heterogeneity and structured heterogeneity in form of layering with upward dip influence negatively the storage efficiency of St. Peter and Knox cores. Structured heterogeneity in form of layering with zero dip (parallel to flow direction) seems to have the least effect on storage capacity as seen for both facies of Sylvania formation.
CCS is a promising technology practiced to control greenhouse gases emissions. Over a billion tons of CO2 is to be sequestered annually if CCS is practiced in large scale. This is equivalent to 250 folds increase over the amount sequestered annually (Benson and Cole, 2008). Carbon dioxide can be stored in different geological structures. Among these are the saline aquifers known to be the largest in term of their huge storage capacity immediately ready when carefully characterized. (IPCC, 2005).
Al-Menhali, Ali (Carbon Storage Research Center, Department of Earth Science & Engineering, Imperial College London) | Krevor, Samuel (Carbon Storage Research Center, Department of Earth Science & Engineering, Imperial College London) | Carbonates, Qatar (Carbon Storage Research Center, Department of Earth Science & Engineering, Imperial College London)
Capillary trapping has been identified as a key storage process that leads to the immobilisation of CO2 as a non-wetting droplets surrounded by brine in the water-wet porous rocks of saline aquifers limiting the extent of CO2 plume migration and enhancing the storage security. On the other hand, CO2 injection into commercial oil fields have several advantages and account for the majority of the current portfolio of CO2 storage sites and likely to remain the dominate storage options for the initial phase storage projects. Oil fields are well characterized and have the infrastructure that can be repurposed for CO2 injection for enhanced oil recovery (EOR) and carbon storage. In contrast, oil reservoirs, most of which in carbonate rocks, are characterised by a mixed-wet state in which the capillary trapping of nonpolar fluids have been observed to be significantly reduced relative to trapping in water-wet rocks typical of saline aquifers unaltered by the presence of hydrocarbons. There are, however, no observations characterising the extent of capillary trapping that will take place with CO2 in mixed-wet rocks. We use X-ray computed tomography (CT) at the core scale and microtomography (μCT), at high voxel resolutions upto 2 ^m, to investigate the pore-scale arrangement of supercritical CO2 droplets and measure the contact angles in situ comparing water-wet and mixed-wet carbonates at temperatures and pressures representative of subsurface oil reservoirs and saline aquifers. The measurements were made while maintaining chemical equilibrium between the fluids (CO2 and brine) and rock phases to prevent reaction with the core sample and replicate conditions far away from the injection site. Initial-residual (IR) CO2 characteristic curves were measured first on the sample at original water-wet state, then were measured again after altering the wetting properties to a mixed-wet system. In particular, CO2 trapping was characterized before and after wetting alteration so that the impact of the wetting state of the rock is directly observed. The measurements were also compared with trapping of N2. Here we show that residual CO2 trapping of supercritical CO2 in a limestone altered to a mixed-wet state with oil is significantly less than trapping in water-wet systems characteristic of saline aquifers. We anticipate this work to highlight a controversial issue for the early deployment of carbon storage - that those sites which are economically most appealing as initial project opportunities are the very locations in which the contribution of capillary trapping to storage security will be minimised. This should serve as a starting point for modelling studies to incorporate the reduced impact of capillary trapping on CO2 injection projects using hydrocarbon reservoirs.
Bedayat, H. (Louisiana State University) | Hosseini, S. A. (Bureau of Economic Geology, Jackson School of Geosciences, The University of Texas) | Moghadam, M. (Bureau of Economic Geology, Jackson School of Geosciences, The University of Texas)
The mechanical response of the target formations during Carbon geological storage strongly depends to the fluid pore pressure alterations in the formation. The storage formations must have sufficient capacity and could avoid migration of CO2 to the surface. When the highly pressurized CO2 is injected into the geological repository the fluid pressure increases in the formation, which results in changes in stresses and deformation of the medium. From geomechanics point of view, the pressure caused by CO2o injection, should not exceed the formation strength and should not cause activation of existing faults. Therefore, finding a realistic estimation of alteration of stresses during the CO2 injection job, has been subject of several studies in the literature. Most of the analytical methods available in the literature to calculate the stress distribution are well established for single-phase flows, but it requires extension when a second fluid, in this case CO2, is also flowing. In the current work, an approximate analytical model is developed for calculating different stresses caused by injection of CO2 in a saline formation, assuming two phase flow pressure regime. Here, we investigated the stress regime under induced fluid pressure and temperature alterations during the injection time.
Carbon dioxide storage or carbon dioxide sequestration refers to the processes by which captured CO2 is securely stored in deep geologic formations. Carbon dioxide storage in geologic formations includes oil and gas reservoirs, unmineable coal seams, and deep saline reservoirs. It has been reported by The Intergovernmental Panel on Climate Change (IPCC) that the global capacity of deep saline storage sites is more than thousands of gigatons of CO2, which is hundreds of times greater than the annual CO2 emissions from industrial sources [1–3]. Therefore studying the behavior of CO2 when stored in these sites are crucial for the industry.
Coupling between fluid flow and mechanical deformation in porous media plays a critical role in subsurface hydrology, oil and gas operations and seismic activity in the Earth's crust. For carbon capture and storage (CCS) projects, these coupled phenomena determine the interactions between the underground injection of CO2, the geomechanical properties of the reservoir and the stability of existing faults. As a result of the inherent uncertainty that is present in complex geological structures, assessing fault stability and the potential for induced seismicity is a fundamental challenge in any modeling effort for CCS projects. Here we present a formal framework for uncertainty analysis and data assimilation, which relies on a two-way-coupled computational modeling strategy for fluid flow and poromechanics of faults. We first quantify the sensitivity of key earthquake attributes (time of triggering, hypocenter location, and earthquake magnitude) to geologic properties such as rock permeability and coefficient of friction of the fault. We then perform a Bayesian inversion that combines Gaussian Processes with Markov Chain Monte Carlo (MCMC), from which we determine the posterior distribution of the system parameters. We show that this posterior distribution correctly combines information from the synthetic earthquake observations with a priori knowledge about the unknown parameters.
Geologic CO2 sequestration is regarded as a promising technology to prevent rising CO2 concentration in the atmosphere from industrial emissions. While various types of underground geological formations have been considered for permanent storage of supercritical CO2 (IPCC, 2005), deep saline aquifers provide the most attractive option for gigatonne-scale storage, given their capacity and ubiquitous nature (Szulczewski et al., 2012).
A principal concern expressed about the practical implementation of CO2 sequestration in deep geological formations is the difficulty in evaluating potential geomechanical risk and the possibility of generating induced or triggered seismicity through stress perturbations in the underground system (NRC, 2013; Zoback and Gorelick, 2012). Complex computational models that combine multiphase flow and fault poromechanics have been proposed to analyze this type of problems (e.g., Cappa and Rutqvist, 2011; Jha and Juanes, 2014). A fundamental challenge associated to the coupled flow-geomechanics models is the inherent uncertainty associated with model parameters, which stems from the always-difficult description of complex geological structures in the subsurface. In addition, for problems where seismicity could be potentially associated to a CO2 storage project, the problem of data assimilation (i.e., model inversion using the observed seismic data) becomes a challenging task due to the complex characteristics of the seismic waveform signals.
Chang, C. (Chungnam National University) | Jo, Y. (Chungnam National University) | Quach, N. (Chungnam National University) | Shinn, Y. J. (Korea Institute of Geoscience and Mineral Resources) | Song, I. (Korea Institute of Geoscience and Mineral Resources) | Kwon, Y. K. (Kongju National University)
We are conducting a small-scale CO2 injection demonstration project in offshore Pohang Basin, SE Korea to test various techniques related to CO2 sequestration, which include reservoir characterization and modelling, drilling and completion, and monitoring systems. The target brine aquifer for CO2 storage is 60 m thick sandstone/conglomerate formations at a depth range between 770 and 830 mbsf (meter below seafloor), which were verified by a seismic survey and a cored borehole (980 m deep). A number of steeply dipping and NE-striking faults cross the target aquifer. To analyze potential risk of shear activation along the faults, we characterize in situ stress state at the site. Borehole image logs showed borehole breakouts along the whole logged section to ~700 mbsf, which consistently indicate an average maximum horizontal principal stress (SHmax) direction of NW-SE. A leak-off test conducted at the bottom of a casing shoe (700 mbsf) yielded the magnitude of the minimum horizontal principal stress (Shmin) lower than the vertical stress (Sv). For the given Shmin and Sv conditions, we used the logged breakout widths and laboratory determined rock compressive strength to constrain possible SHmax magnitudes that could create the observed breakouts. We utilized our estimated stress conditions to analyze slip tendency of the faults. Additional information obtained from LOT is cap rock permeability, which suggests the formation above the storage reservoir is suitable for a leakage barrier. All regional scale faults turn out to have relatively low slip tendency under the given stress condition, suggesting a relatively low risk of triggering shear activation of faults during CO2 injection.
The geological storage of carbon dioxide (CO2) has been proposed as a potential method of reducing greenhouse gas emissions (Bachu et al, 2007; Bachu, 2008). In many carbon capture and storage (CCS) projects, when captured CO2 is injected into deep saline aquifer, we need to consider the potential risks of geomechanical problems induced by an increase in formation pore pressure, such as slip reactivation along pre-existing faults, triggered earthquakes, and possibility of cap-rock hydraulic fracturing (Streit and Hillis, 2004; Vidal-Gilbert et al., 2010; Vilarrasa et al., 2011; Zoback and Gorelick, 2012). Because such risk factors can be latent leakage path of injected CO2, it is important to characterize geomechanical aspects of the integral part of the reservoir including cap-rock integrity, potential aquifer capacity and existing fault stability (Hawkes et al., 2005; Streit and Siggins, 2005; Orlic, 2009).
The offshore basin in Pohang, SE Korea, has been accepted as a potential storage site of CO2 by Korean government and many researchers (Han and Keehm, 2013; Kim et al., 2014; Lee and Kwon 2014; Choi et al., 2015; Park et al., 2015; Song et al., 2015). Followed by the acceptance, a small-scale CO2 injection demonstration project is underway in this basin. As a preliminary study, we conducted geomechanical characterization for the potential reservoir system, which includes in situ stress estimation and in situ permeability estimation using an offshore borehole, as well as fault characterization, in order to assess fault stability issues. Our study demonstrates that the offshore reservoir is suitable for CO2 storage.
Ennin, Edward (Petroleum Recovery Research Center, New Mexico Institute of Mining and Technology) | Grigg, Reid B. (Petroleum Recovery Research Center, New Mexico Institute of Mining and Technology) | Petmecky, Christopher (Petroleum Recovery Research Center, New Mexico Institute of Mining and Technology)
Understanding fluid/fluid and rock/fluid interactions in a reservoir are required to evaluate CO2 storage potential and safety. This paper examines the effect of salinity of reservoir brine on CO2 storage and the level of salinity best for CO2 storage. Relative permeability imbibition and drainage curves were generated to further understand the interaction between CO2 and brine in a reservoir.
A core flooding set up was built to replicate reservoir conditions of the Farnsworth Unit (FWU) in Texas, USA. The research involved three reservoir pay zone rocks obtained from depths of about 7687ft that were pieced together to undergo core flooding at 4400psi and a temperature of 168°F. During the 6 tests conducted the core was flooded with supercritical CO2 and brine of salinities 3000ppm, 6000ppm and 35000ppm to generate relative permeability curves to represent imbibition and drainage. Imbibition and drainage relative permeability curves are generated from the co-injection of CO2 and brine of varying salinity at different ratios and volumes.
After analyses of the imbibition and drainage relative permeability curves for the different salinities it is seen that the relative permeability curves looked very similar, in that all three relative permeability curves looked the same for imbibition tests and also for all the drainage tests regardless of the brine salinity. The volume of CO2 stored in the core was almost the same for the six different tests. From this research it can be concluded that CO2 storage, at least for these particular reservoir rocks, is not affected significantly by the salinity of the formation brine. It appears that the interaction between supercritical CO2 and different salinities of brine is not substantially different for the same rock sample.
Carbon dioxide (CO2) can be injected into the subsurface to achieve enhanced oil recovery (EOR), possibly with geological CO2 storage. This procedure brings about a set of unique challenges with respect to well construction, operation, and remediation. As compared with normal production, CO2 injection imposes lower temperatures and stronger temperature variations on wells. This is especially prevalent if the injection is not continuous. Downhole-temperature variations will result in expansion or contraction of casings and well-barrier materials, which can cause them to crack or debond at interfaces. To avoid leakage paths through wells, it is therefore important to understand within which temperature intervals it is safe to operate. In the present paper, we describe a heat-conduction model for calculating heat transfer from the well to the casing, annular seal, and rock formation. These materials have dissimilar thermal properties, and will behave differently with respect to downhole-temperature variations. The model is discretized by use of a finitevolume method developed especially for accurate calculation of heat conducted radially in a well. This allows us to predict temperatures and temperature variations at various locations in and around a given well during CO2 injection. To validate the numerical model, we compare our simulation results with the time-varying temperatures measured in our laboratory. Good agreement is found between the numerical predictions and the measured data. Simulation results are presented for different combinations of formations and well-barrier materials (cement and alternative types of annular sealants) to display their effect on the well temperature. It is found that, by replacing cement with an annular sealant material with higher thermal conductivity, the temperature difference across the seal can be significantly reduced. A high-conductivity formation such as halite/rock salt can also reduce thermal gradients in the well materials.
Zhang, Liang (China University of Petroleum (Huadong)) | Li, X. (China University of Petroleum (Huadong)) | Ren, B. (University of Texas at Austin) | Cui, G. D. (China University of Petroleum (Huadong)) | Ren, S. R. (China University of Petroleum (Huadong)) | Chen, G. L. (PetroChina)
The block H-59 in the Daqingzijing region was selected as a pilot site for the first stage of the CCS project in Jilin oilfield after an extensive assessment. This block is a light oil reservoir with a low permeability. The performance of water flooding after the primary oil recovery was very poor. Therefore, CO2 injection has been started since April 2008 for EOR associated with CO2 storage for environmental benefits. This paper is aimed at assessing the current CO2 storage capacity and distribution at different states in the oil reservoir after 6-year injection until April 2014. Based on various CO2 trapping mechanisms, an evaluation method of CO2 storage potential is established to calculate the theoretical and effective CO2 storage capacities in target oil reservoir. the current amount of CO2 buried in the H-59 block was calculated according to the field data. The reservoir numerical simulation was used to analyze the distribution and existing state of CO2 underground. The assessment results show that the theoretical capacity of CO2 storage in the H-59 block is 72.32×104 t, and the effective capacity of CO2 storage is 26.37×104 t. The calculation of effective CO2 storage capacity in oil reservoir considers the engineering practice of field operation during project life. The coverage factor of well pattern (k1) and the sweep coefficient of CO2 within the well pattern (k2) have been introduced in the method. Meanwhile, the mineral trapping was neglected for short-term storage of CO2 based on a preliminary geochemical simulation analysis. There are 17.45×104 t CO2 which has been buried in the block until April 2014. The distribution of buried CO2 between the injection and production wells is mainly determined by the reservoir physical properties and the total amount of CO2 injected in each well. Reservoir simulations indicate that 61.0% of CO2 buried in the oil reservoir has been trapped at supercritical state, and the amounts of CO2 dissolved in oil and water account for 24.4% and 14.6% respectively. These proportions of CO2 at different states are very close to the calculation results of effective CO2 storage capacity. In comparison to the effective CO2 storage capacity, it is thought that the block H-59 still has a certain storage potential of 8.92×104 t at present. For the assessment methods, the parameters k1 and k2 for calculation of effective CO2 storage capacity deserve for further discussion. It should be also noted that the accuracy of CO2 distribution predicted by reservoir simulation greatly depends on the accuracy of geological model. It needs more efforts to improve the understanding of the target reservoir properties.