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Abstract Carbonate formations are usually highly fractured. The fractures exist at all length scales ranging from microscopic fissures to kilometer-size structures. Consequently, it is vitally important to rigorously characterize the multi-scale fracture system and to accurately model the fluid flow in such highly fractured porous media. In this paper, we will present an integrated workflow for characterization of natural fracture system and accurate numerical modeling of fluid flow in fractured rocks. The fracture characterization usually involves the integration of multiple data sources including core analysis, image logs and seismic interpretations etc., at different scales. The fracture mappings are thus required to perform at different length scales and resolutions. In this study, we present a systematic approach that characterizes the actual fracture distribution with seismic and log interpretations. Firstly, the small-scale fractures are interpreted using image logs and seismic anisotropy analysis with a co-Kriging and stochastic modeling approach. The small-scale fractures are initially constructed in an explicit fashion, and are then incorporated in the matrix medium using a flow-based upscaling procedure. Secondly, the large-scale fractures are mapped out from post-stack seismic data with ant-tracking and maximum curvature analysis. The reservoir is then gridded into unstructured tetrahedral or prism meshes to fully resolve these large fractures. This discrete fracture model (DFM) is employed in a reservoir simulation study based on such grid system. We applied the procedure for simulation study and history match on a portion of a carbonate gas reservoir in Longwangmiao formation in Southwest China. Currently, there are 7 horizontal and 2 vertical wells in operation. Due to the connection of some large-scale fractures to edge water, early water breakthrough and drastic water invasion were observed. We partitioned the reservoir block into 0.6 million cells, in which 153 large-scale and thousands of small-scale fractures are fully resolved. The simulation study was performed and automated history match was successfully achieved using our extended Ensemble Karman Filter algorithm based on a parameterized description of the fractures that are explicitly represented in DFM. This proposed overall procedure is able to efficiently capture such extreme flow dynamics and achieve significantly better history match results. [ABSTRACT FROM AUTHOR]

Abstract Various factors such as reservoir temperature, wettability, caprock properties, vertical to horizontal permeability ratio, salinity, reservoir heterogeneity, injection well configuration affect the CO 2 geo-sequestration efficiency. Furthermore, it was previously investigated that CO 2 storage efficiency can be improved by using water alternating CO 2 (WACO 2) technology. However, the effect of the WACO 2 ratio (the ratio of the total amount of injected CO 2 to the total amount of injected water) on CO 2 storage efficiency has not been addressed adequately. Thus, in this paper, a 3D homogeneous reservoir simulation model has been developed to study the impact of the WACO 2 ratio on CO 2 mobility and CO 2 trapping capacity using five different WACO 2 ratios (i.e. 3, 2, 1, 1/2, and 1/3). For all WACO 2 ratios tested, 9000 kton (kt) of CO 2 were injected during 3 CO 2 injection cycles (2 years each) and at an injection rate of 1500 kt per year. Each CO 2 injection cycle was followed by a 2 years water injection cycle with injection rates of 500 kt/year, 750 kt/year, 1500 kt/year, 3000 kt/year, and 4500 kt/year for the 3, 2, 1, 1/2, and 1/3 WACO 2 ratios, respectively. Then, this 12 years WACO 2 injection period was followed by a 100 years post-injection period. Our results clearly indicate, after 100 years post-injection period, that the WACO 2 ratio has an important effect on the CO 2 migration distance, CO 2 mobility and CO 2 trapping capacity. The results demonstrate that lower WACO 2 ratio leads to reduce the vertical CO 2 plume migration and CO 2 mobility. Furthermore, low WACO 2 ratio enhances the capacities of capillary and solubility trapping mechanisms. Thus, we conclude that WACO 2 has a significant impact on the geo-sequestration efficiency and less WACO 2 ratios are preferable [ABSTRACT FROM AUTHOR]

The successful exploitation of geothermal energy for power production relies on the availability of nearly zero emission and efficient technologies. Two zero emission flash plant layouts, with full reinjection of the geothermal fluid (non-condensable gas included), are considered. This paper focusses on the CO2 issue, and therefore only the carbon dioxide is considered as non-condensable gas present in the geothermal fluid; the CO2 flow is separated, compressed, and reinjected with the geothermal fluid. Both the reservoir and the power plant are simulated. A first scheme of plant presents a conventional layout in which the CO2 is separated and compressed after the condenser. The second scheme presents a plant layout that allows the separation of the CO2 at higher pressure with respect to the conventional layout, thus reducing the requested power consumption. The conventional plant scheme performs always better at higher temperature and at lower concentration of CO2. The new layout results better for low temperature and higher gas content. [ABSTRACT FROM AUTHOR]

Two new modelling options developed recently within the MUFITS reservoir simulator are presented. The first wellbore friction option allows a simplified modelling of wellbore hydraulics that often needs to be accounted for in horizontal wells. The second option concerns the modelling of fractured reservoirs using the double porosity, the double permeability and more general multiple interacting continua approaches. Results of the options validation against benchmark problems are presented and internal structures that MUFITS builds in kernel for such reservoir models are demonstrated. [ABSTRACT FROM AUTHOR]

The purpose of this study is to investigate the effects of the geomechanical mechanisms on the gas production of a depressurized Class-3 hydrate deposit, Four-Way-Closure Ridge. From this case study, we found that there is a lower gas production rate and a longer production plateau when geomechanics are considered in the fluid flow modeling. The Young’s modulus and Poisson’s ratio are sensitive parameters to the reservoir deformation and the seafloor subsidence. We suggest that the geomechanical issue should be well considered in a hydrate deposit development project. [ABSTRACT FROM AUTHOR]

We performed a sensitivity analysis of parameters of a CCS system with pressure relief well by design of experiments (DOE), and subsequently calculated optimal well spacing and well controls by response surface methodology (RSM). A reservoir sector model of the direct line-drive pattern for 25 years CO 2 injection with one pair of wells was constructed. Additionally, an associated pump energy calculation model was made to calculate PEU (total pump energy consumption divided by cumulative CO 2 injected) as an indicator of energy efficiency of the pump. With this workflow of simplification of modelling and calculation, we can obtain important information about the parameters at less computational cost. [ABSTRACT FROM AUTHOR]

This paper presents an integrated numerical framework to co-optimize EOR and CO 2 storage performance in the Farnsworth field unit (FWU), Ochiltree County, Texas. The framework includes a field-scale compositional reservoir flow model, an uncertainty quantification model and a neural network optimization process. The reservoir flow model has been constructed based on the field geophysical, geological, and engineering data. A laboratory fluid analysis was tuned to an equation of state and subsequently used to predict the thermodynamic minimum miscible pressure (MMP). A history match of primary and secondary recovery processes was conducted to estimate the reservoir and multiphase flow parameters as the baseline case for analyzing the effect of recycling produced gas, infill drilling and water alternating gas (WAG) cycles on oil recovery and CO 2 storage. A multi-objective optimization model was defined for maximizing both oil recovery and CO 2 storage. The uncertainty quantification model comprising the Latin Hypercube sampling, Monte Carlo simulation, and sensitivity analysis, was used to study the effects of uncertain variables on the defined objective functions. Uncertain variables such as bottom hole injection pressure, WAG cycle, injection and production group rates, and gas-oil ratio among others were selected. The most significant variables were selected as control variables to be used for the optimization process. A neural network optimization algorithm was utilized to optimize the objective function both with and without geological uncertainty. The vertical permeability anisotropy (Kv/Kh) was selected as one of the uncertain parameters in the optimization process. The simulation results were compared to a scenario baseline case that predicted CO 2 storage of 74%. The results showed an improved approach for optimizing oil recovery and CO 2 storage in the FWU. The optimization process predicted more than 94% of CO 2 storage and most importantly about 28% of incremental oil recovery. The sensitivity analysis reduced the number of control variables to decrease computational time. A risk aversion factor was used to represent results at various confidence levels to assist management in the decision-making process. The defined objective functions were proved to be a robust approach to co-optimize oil recovery and CO 2 storage. The Farnsworth CO 2 project will serve as a benchmark for future CO 2 –EOR or CCUS projects in the Anadarko basin or geologically similar basins throughout the world. [ABSTRACT FROM AUTHOR]

Containment of injected CO 2 at the South West Hub project in Western Australia is dependent on non-structural trapping mechanisms in the 1500 m thick Wonnerup Member of the Lesueur Sandstone due to uncertainties regarding the sealing character of the ∼600 m thick overlying Yalgorup Member. Therefore, vertical migration distance and sweep efficiency and their impact on residual saturation and CO 2 dissolution need to be properly assessed through reservoir simulations. We find that conventional Darcy-flow reservoir simulations result in significantly different predictions of plume migration compared to invasion percolation modelling when injecting at the base of the Wonnerup Member. If numerical predictions of the fate of injected CO 2 are sensitive to the choice of model, care must be taken when selecting the methodology. One way to validate simulation predictions at a scale appropriate to the modelling is the use of well tests. In the Wonnerup Member a vertical migration test is recommended for consideration to confirm whether conventional reservoir simulations or percolation invasion modelling accurately predict the CO 2 migration processes at the site. This test would involve a small injection of CO 2 that is allowed to migrate upwards. The migration would be monitored with repeat pulsed neutron logging. This represents a new kind of test unique to the situation for the South West Hub site. [ABSTRACT FROM AUTHOR]

An extension of MUFITS reservoir simulator for modelling oil and gas reservoirs using black-oil approach is presented. We give an overview of multi-segment well technique implemented in MUFITS for coupled reservoir-wellbore simulations. SPE comparative studies with vertical wells are simulated in order to verify the correctness of technique implementation in the code. The simulation results, in particular calculated wells bottom-hole pressures, match results of other codes. [ABSTRACT FROM AUTHOR]

It has been suggested that injection of brine above the caprock, at a higher pressure than the CO 2 pressure in the reservoir, would create an inverse pressure gradient to reverse the flow direction and increase the solubility of CO 2 in the saline water barrier formed, and prevent or limit leakage. The effectiveness of the pressure gradient reversal (PGR) method as a potential remediation technique for CO 2 leakage from deep saline aquifers was investigated using a realistic 3D reservoir/caprock model. A hypothetical CO 2 storage operation involving CO 2 injection at 1 Mt/year for up to 30 years down-dip of a structure high in the model domain was considered. The brine injection simulation results indicate that the performance of PRG is strongly affected by how early leakage is detected from the start of injection (time-to-detection), which in turns is controlled by the detection threshold, leakage pathway permeability and the distance to the injection well. PRG is more effective the earlier leakage is detected and the closer the leakage location is to the injection well. [ABSTRACT FROM AUTHOR]

Supercritical CO 2 has good mobility and certain heat capacity, which can be used as an alternative of water for heat recovery from geothermal reservoirs, meanwhile trapping most of injected CO 2 underground to achieve environmental benefits. In this paper, different types of geothermal resources are assessed to screen reservoirs suitable for geological storage and heat mining by CO 2 injection, in terms of geological properties, heat characteristics, storage applicability, and development prospects, etc. Deep saline aquifer, geopressured reservoir and hot dry rock are selected as the potential sites, mainly due to their relatively positive geological conditions for CO 2 circulation and storage. Reservoir simulations are conducted to analyze the storage efficiency and heat extracting capacity of CO 2 in the promising geothermal reservoirs. A simple calculation method is presented to estimate the potentials of CO 2 storage and heat mining in the major prospective geothermal regions of China. The preliminary assessment results show that the recoverable geothermal potential by CO 2 injection in China is around 1.55×10 21 J with hot dry rocks as the main contributor. The corresponding CO 2 storage capacity is up to 3.53×10 14 kg with the deep saline aquifers accounting for more than 50%. CO 2 injection for geothermal production is a more attractive option than pure CO 2 storage due to its higher economic benefits in spite of that many technological and economic issues still need to be solved in the future. [ABSTRACT FROM AUTHOR]

A CO 2 storage atlas of different sectors of the Norwegian Continental Shelf has been elaborated by the Norwegian Petroleum Directorate (NPD) in the period 2011 to 2013 and is now compiled into one volume. Main objectives were to facilitate selection of sites which are suited for future CO 2 sequestration projects and to document the total storage capacity of the Norwegian sectors of the North Sea, the Norwegian Sea and the southern Barents Sea. The most attractive aquifers and structures were investigated by geomodelling and reservoir simulation. 5 case studies of different types of aquifers, structures and abandoned fields illustrate how the typical storage options were evaluated. There is a tendency that calculated storage efficiency and storage capacity based on estimates of pore volumes will decrease when the storage assessment units are matured by more detailed studies. The study was based on the assumption of no water production, and it was observed that storage capacity was usually limited by pressure build- up in the investigated aquifers. The case of pressure maintenance by water production has not been studied, but could lead to significantly higher values for storage capacity. The study indicates that CO 2 could be used to recover oil from naturally occurring residual oil zones which commonly occur in areas with deep erosion. [ABSTRACT FROM AUTHOR]

A pilot CCS project in Indonesia will be implemented in Gundih area, Central Java Province in Indonesia. Before the CO 2 injection, the reservoirs for CO 2 injection must be characterized carefully by conducting geophysical exploration as well as reservoir simulation, in order to make sure that the reservoir is suitable for CO 2 storage. Here we report results of reservoir characterization and simulation for the determination of CO 2 injection site in the Gundih area. Subsurface structures imaged on seismic reflection profiles indicate that the Ngrayong formation is one of the candidates for CO 2 injection. We observed the outcrop of the Ngrayong formation and measured hydrological and geophysical properties (e.g., permeability, seismic velocity) of the rock samples obtained from outcrop and wells. The Ngrayong formation has layered structure and heterogeneous characteristics. Using (1) hydrological properties, (2) subsurface structures (i.e., geometry of the Ngrayong formation) and (3) physical properties predicted by integrating seismic and logging data via acoustic impedance inversion, we applied reservoir simulation and evaluated security of the CO 2 injection sites. [ABSTRACT FROM AUTHOR]

Trinidad and Tobago (T&T) has over one hundred years of experience in oil production. In addition, the nation was one of the first to employ enhanced oil recovery via CO 2 flooding. In recent times however, oil production has decreased and the early implemented CO 2 -EOR projects have all ceased. Since T&T is a rapidly developing energy intensive economy, it is amongst the top ten in the world in terms of CO 2 equivalent emissions on a per capita and per GDP basis. Many researchers within the nation and elsewhere have conceptualized that T&T can ironically use its rich history of oil production and CO 2 -EOR to help reduce its emissions. However, to effectively do this, key parameters must be found robustly and scientifically. The paper attempts to do this by outlining a framework for investigating the feasibility of implementing CO 2 -EOR in T&T from flus gas sources. This is done through the use of reservoir simulation in CMG to obtain key parameters needed to investigate this feasibility. An existing natural gas turbine fired power plant in Point Lisas was selected as the CO 2 source allowing actual CO 2 volumes and properties germane to this plant to be used. However, a hypothetical field was chosen as the appropriate sink since the use of actual field data was prohibited by relevant companies in T&T. While this is not ideal, the values used closely resemble actual field data and can easily be modified once permission to use actual field data is acquired. For this hypothetical field, a detailed reservoir model was built. The model was executed, and various scenarios were simulated to determine the optimum number of producers for primary production and the best location of the CO 2 -EOR injectors. Many key parameters were reported from this investigation. These included OIIP, forecasted production and primary recovery, CO 2 utilization rate and total sequestered CO 2 . [ABSTRACT FROM AUTHOR]

Numerical simulations of multiphase flow in porous media often face convergence difficulties in the nonlinear Newton solver, including erratic time stepping, large number of (Newton) iterations, and timestep cuts. Such convergence problems can lead to unacceptably large computational time and are often the main impediment to performing simulation studies of large scale problems, such as oil/gas recovery, groundwater remediation, and CO 2 geological sequestration. We analyze the nonlinearity of the discrete transport (mass conservation) equation for immiscible, two-phase flow in porous media in the presence of viscous, buoyancy, and capillary forces. The critical features that cause oscillations and divergence of the Newton iterations are identified and located. Based on the analysis, we develop a nonlinear solver that guides Newton iterations safely and efficiently, such that convergence is achieved for arbitrary timestep sizes. [ABSTRACT FROM AUTHOR]

Abstract: CO2 miscible flooding is one of main technologies in both the secondary and tertiary floods for Enhanced Oil Recovery (EOR). In addition, it is also an important alternative for a geological CO2 storage. In the recent twenty years, the fundamental research for visualized CO2-EOR has been launched by using mainly the Magnetic Resonance Imaging (MRI). In this study, we simulated a CO2 miscible model by using Eclipse reservoir simulation software based on the MRI coreflood test. We modified the numerical model of CO2 miscible flooding by changing the parameters to improve the CO2 miscible flood simulation results. [Copyright &y& Elsevier]

Abstract: Enhanced coalbed methane (ECBM) production by CO2 injection offers the potential of increasing recovery of the gas in place over primary recovery methods and at the same time storing CO2. A field ECBM trial via CO2 storage has been carried out in the east margin of the Ordos Basin, Shanxi province, China. A unique aspect of the trial was using a multi-lateral horizontal well, which was clearly beneficial for production or injection for low permeability formations. This paper described a reservoir model constructed to simulate the CO2 injection behaviour using the coal seam reservoir simulator SIMED II. The simulation work included history matching the bottomhole pressure while using injection rate as control. A complexity in the modelling was representation of the multi-lateral horizontal well as its branches were not aligned with x or y coordinates. Thus approximation was taken to represent the well in the model. The simulation result showed good match for some data but could not match well the whole range of data, suggesting possible well opening or closing to flow during injection and shut-in periods. It has been suggested that the permeability decrease due to gas adsorption induced coal swelling may play an important role in the gas flow behaviour, especially near the wellbore where the amount of CO2 adsorbed was highest. However, due to the coarse grid size applied in this finite difference model and the difficulty to refine them near the well branches while maintaining overall size of the model, the permeability loss due to adsorption induced coal swelling was diluted by the relatively large grid size. Thus this may not accurately reflect the permeability change and the quality of the history matching results are affected. A suggestion is to use refined grid blocks near wellbore to examine the impact of swelling on the overall CO2 flow behaviour for this project. [Copyright &y& Elsevier]

Abstract: It is very important to evaluate the soundness of the injection site by simulating the behavior of carbon dioxide injected into the reservoir. Monte Carlo approach is often used for the statistical evaluation of reservoir because its models include much uncertainty. This approach requires a large number of simulations and it is very time consuming. Therefore we accelerated the simulation with GPU (Graphics Processing Unit) computing technology. We used the simulator called TOUGH2/ECO2N. As a result, we achieved acceleration rate more than 8 times with the simulation for the three -dimensional reservoir model of the Nagaoka project site having 110,000 grids. [Copyright &y& Elsevier]

Abstract: The Illinois Basin – Decatur Project (IBDP), funded by the United States Department of Energy National Energy Technology Laboratory, aims to inject one million tonnes of carbon dioxide (CO2) into the Mount Simon Sandstone. The injection of CO2 started in November 2011 and will extend over three years. Pre-injection reservoir modeling and uncertainty analysis has been carried out to obtain probabilistic predictions of storage performance indicators. Key characteristics of the storage site such as capacity, injectivity and containment are often evaluated based on the modeling results. Simulation studies for IBDP started in 2007 using general regional knowledge. Over time, simulations have increased in complexity and have become more representative of the Mount Simon Sandstone as more data have been acquired. In this study, a high resolution reservoir model consistent with all available data was developed. Water injection/fall-off tests were used to history match and calibrate the petrophysical properties of the injection zone. Using a high-resolution grid around the wellbore in the injection zone allowed us to quantify uncertainties in plume shape and size. Lateral and vertical extent of the model was sufficient to account for the injection induced differential pressure front defined by regulatory requirements. Using two hundred realizations, a detailed uncertainty analysis was performed to provide probabilistic evaluation of the storage site performance. Irreducible water (H2O) saturation, residual CO2 saturation, CO2 relative permeability at the residual H2O saturation, and horizontal-vertical permeability ratio were among the parameters considered uncertain. These parameters were studied to quantify the uncertainties of performance factors including containment of CO2, injectivity, and dynamic mass partitioning (mobile, residually trapped, and dissolved). On the reservoir scale, we analyze uncertainty in CO2 saturation and pressure profiles, and its potential implications for regulatory requirements for Area of Review (AoR) evolution during the life of the project. [Copyright &y& Elsevier]

Abstract: Water extraction is one possible means of enhancing storage capacity and managing carbon dioxide (CO2) storage reservoirs. This study investigates the efficacy of water extraction in CO2 storage applications through the use of dynamic simulations under various conditions on conceptual heterogeneous geological models based on four CO2 storage sites in different basins of the world. The simulations indicate that the CO2 storage capacities can be increased, and pressure and plume management can likely be accomplished through the use of water extraction. [Copyright &y& Elsevier]

Abstract: The Bunter Sandstone Formation in the Southern North Sea is folded into a number of simple 4-way dip-closed structures (domes). Most of these structures are saline water-bearing, although some of them do contain significant gas accumulations, suggesting that the brine-saturated domes may have potential for the long-term storage of CO2. This study investigates the effect of geological structure and heterogeneity on CO2 storage through the use of geological models and reservoir simulation. Dynamic modeling focussed on the determination of the storage efficiency of a particular dome and from this, its CO2 storage capacity. Under initial modeling conditions, a storage efficiency of around 19% was derived, though this is shown to be highly sensitive to a range of uncertain parameters. An interesting interplay exists between the reservoir heterogeneity and dome structure, whereby the evolving CO2 plume is prevented from rising buoyantly to the top of the formation by the presence of impermeable horizons, which facilitates rapid migration towards the structural spill-points. Sensitivity analysis further emphasizes the importance of characterizing reservoir heterogeneity in studies for long-term carbon capture and storage. [Copyright &y& Elsevier]

Abstract: Spectra Energy Transmission and the Energy & Environmental Research Center, through the Plains CO2 Reduction Partnership, are investigating potential commercial-scale carbon capture and storage in a saline formation near Fort Nelson, British Columbia, Canada, by conducting detailed modeling and predictive simulations of injection at the Fort Nelson site. The results of the Fort Nelson modeling activities are providing insight regarding the movement of sour CO2; the potential effects that large-scale sour CO2 injection may have on neighboring natural gas production fields; and the deployment of selected monitoring, verification, and accounting techniques. [Copyright &y& Elsevier]

Abstract: Surface uplift has been detected over all three of the In Salah CO2 injection wells with corresponding subsidence also observed over the gas production area. In particular, it has been noted that the surface uplift over KB-502 displays two distinctive lobes aligned along the direction of the maximum principal stress in the region, originating from the heel and the toe of the horizontal wellbore respectively. As part of the work programme within the EU funded CO2ReMoVe project, Imperial College has carried out short-term reservoir simulations of CO2 injection into the aquifer portion of the C10.2 sandstone formation, initially focusing on history match of injection well pressure at KB-502 and CO2 breakthrough at the nearby KB-5 observation well (now fully decommissioned) along the heel-side lobe. In view of the satellite monitoring data of the surface deformation at the Krechba gas field and published findings of the inversion modelling work, the reservoir model is further improved to account for the pressure distribution inferred from the surface uplift data, as well as the reservoir-based field data. Specifically, the permeability pattern inverted from the surface uplift data has been used to further constrain the reservoir model to improve prediction of the CO2 plume migration around KB-502, so that it is consistent with the surface monitoring data, as well as reservoir-based observations (injection pressures and CO2 breakthrough at KB-5). [Copyright &y& Elsevier]

Abstract: For risk associated with storage of CO2 under the Earth’s surface, the impervious cap is one of the most significant factors. Geological structures such as faults can provide conduits for CO2 to escape through the cap. When conductive faults intersect the storage formation and overlying permeable layers, CO2 leaks may exhibit three distinct behaviors: initial upward migration of fluids through the fault, lateral fluid movement through permeable layers, and continued movement of CO2 along the fault above the leakage pathways. To quantify this behavior, especially the attenuation, we develop a quasi-1D model for migration of buoyant fluid from a reservoir along a conductive fault. The fault can intersect multiple shallower formations. The model accounts for flow from the fault into a permeable formation using the concept of leakoff. The leakoff coefficient depends on the geometry and on the petrophysical properties of the formation. We use a commercial simulator (GEM from CMG) to run 2D verification studies of the 1D model. We present a series of examples that illustrate the controlling mechanisms for leakage rate from the reservoir and its attenuation by flux into shallower layers. Leakage flux and its attenuation vary nonlinearly with the permeability of the fault and the permeability of the shallower layers intersected by the fault. Permeable layers near the CO2 storage reservoir exhibit the greatest attenuation. While there is a nonlinear relationship between flux through the fault and the size of the leakoff coefficient, there is a linear relationship between the percentage which leaks off into neighboring formations and the ratio of fault permeability to leakoff coefficient. The rate of attenuation of CO2 leakage depends on geometric and/or petrophysical properties of highly permeable structures as well as reservoir properties. An analytical derivation of the leak-off coefficient based on Darcy’s equation compares favorably with 2D simulations. On the other hand, in the case of tilted permeable layers, calculation of the leakoff coefficient is less straightforward due to preferential flow within the layer (lighter CO2 rising above heavier brine). [Copyright &y& Elsevier]

Abstract: The Atzbach–Schwanenstadt gas field has been investigated in the CASTOR project with respect to its suitability for safe, long-term underground CO2 storage. Storage capacity of the reservoir has been estimated to 14.5 million tonnes of CO2. Potential nearby CO2 sources emit together about 300 000 tonnes of CO2 per year. Assuming that reservoir would be filled up until its initial reservoir pressure the available storage capacity would be sufficient to store all CO2 produced during the next 48 years. Results from the reservoir simulation of the storage showed that during 30 years of injection 8.2 million tonnes of CO2 could be stored. A CO2-EGR effort in the field could in theory increase gas production and therefore enlarge the available storage capacity for CO2. However, none of the conducted reservoir simulations could prove that CO2 injection would enhance gas recovery at the Atzbach–Schwanenstadt field. CO2 breakthrough to the production wells is very quick and occurs almost immediately after start of injection. The fraction of CO2 in produced gas increases rapidly and this limits production of the clean gas. Compared to the simulation with no CO2 injection, EGR cases give lower production of the clean gas. Therefore use of CO2 for the enhanced gas recovery is not recommended for the Atzbach–Schwanenstadt field. The long-term storage simulation shows that reservoir pressure stabilizes shortly after injection stops. During the period of 1500 years after the end of injection only 10% of injected CO2 will dissolve in the immobile reservoir water. In a scenario of potential leakage four abandoned wells were selected to mimic leaking wells. Simulation results show that if CO2 reaches the abandoned wells, and this would lead to leakage, as much as 5.6% of injected CO2 could escape from the reservoir during a period of 1500 years. [Copyright &y& Elsevier]

Abstract: The hydrodynamic site characterization for the CO2CRC Otway Project demonstrating geosequestration in the depleted Naylor gas field determined the pre-production Darcy-flow-velocity in the target reservoir and identified pressure decline due to regional hydrocarbon production. Wellhead pressure measurements showed the depleted reservoir to be recovering much faster than predicted by the reservoir model calibrated by the production history. To provide sufficient aquifer support to match the observed recovery, the dynamic reservoir simulation required the inclusion of a dual aquifer system. This was supported both by the interpreted hydrodynamic model and by the observation of a paleo-gas column extending below the structural spill point of the Naylor gas field. [Copyright &y& Elsevier]

Abstract: The feasibility to recover stored CO2 from the Utsira formation at Sleipner has been studied by reservoir simulation of a 15 years injection (until 2011) and a subsequent scenario where the CO2 is produced from a horizontal well under the cap rock. There are three important aspects related to the recovery of the stored CO2: [-] Performance of temporary storage of CO2 for EOR purposes. [-] Reproduction of mobile CO2 from formations that turn out to be less suitable for storage than anticipated. [-] The reproduction simulation can resemble an open leaking well. The simulations are based on experimental drainage and imbibition curves for the corresponding injection and production phase. The results show that until 47.7% of injected CO2 can be reproduced during a seven year non-stop production period. The results are based on a 15 year injection period, an irreducible water saturation of 5% and a residual CO2 saturation after imbibition of 25%. Also the amount CO2 reproduced was found to be increasing with decreasing values of irreducible water saturation. Data from pre-injection seismic, well logs and petrophysical data are used to build a reservoir model. The Utsira formation is intersected by thin horizontal discontinuous shale layers that impede the vertical migration and cause entrapment of the CO2 in flat plumes. The transport properties of these shales are obtained by history matching the size of the plumes observed from seismic monitoring. To accommodate the necessary amount of CO2 the lateral size of the model had to be 5.2 km×7.9 km. To minimize numerical dispersion a relatively fine grid was required giving 2.1 million grid blocks in the model. The CO2 plume may be reached by a new well from the Sleipner A platform or through a sidetrack of the existing CO2 injection well and convert it to a producer. Placement of the producer is optimized for maximum reproduction by utilizing the local topography of the top seal. A producer could be drilled to avoid penetration of the cap-rock close to or above the CO2 plume and thereby avoid a potential leakage point after abandonment. The formation is high-permeable and relatively flat. The injected CO2 will therefore accumulate in thin plumes with large lateral extensions. Accordingly, recovery efficiency is low and the formation is less suitable for reproduction of CO2 compared to formations with a significant dome seal or dipping structures sealed by faults. The results give an important confirmation that it is possible to reproduce a significant amount of the mobile CO2 as a remediation option if a serious lack of integrity of the cap rock is detected. [Copyright &y& Elsevier]

Abstract: The MOVECBM field pilot project, which is the successor of the RECOPOL project, has been completed. Here, we summarize the main results from the field tests in Poland and Slovenia. In the RECOPOL project, the CO2 has been injected continuously over a period of two months into the coal seam. In MOVECBM, the focus is on the verification of containment of the CO2 herein. The injector has been back-produced and the gas composition has been analyzed. The CH4/CO2 ratio of this gas was higher than expected. Flow rates were very low indicating coal swelling. Next to the field pilot in Poland, several lab studies were conducted at several universities (Mons, RWTH-Aachen, U-Utrecht and SKLCC-CAS) determining the key coal parameters for modeling the field tests. Also, a CO2 injection experiment was conducted in the Velenje mine in Slovenia (1 injector + 3 producers). Coal swelling was observed during CO2 injection, which totally impaired the flow into the coal seam. However, weeks after the experiment improved pressure communication between the injector and producers was observed indicating that CO2 injection had created new fractures in the coal. [Copyright &y& Elsevier]

Abstract: The injected CO2 in a target formation can continue to migrate through permeable pathways due to geological heterogeneity as well as buoyancy. This movement drives a countercurrent flow of brine leading to increased residual phase trapping. The purpose of this simulation study is to understand the effects of geological structures, especially faults, on the dynamic behavior of the buoyancy-driven CO2 plume and the amount of residual trapping. We studied the behavior of CO2 plumes (speed, direction, saturation at displacement front, residual phase trapping) in 2D and 3D formations with a range of fault properties (conductive vs. sealing, angle relative to dip, distance from initial plume location). Before CO2 plumes enter the fault-influenced region of the aquifer, the reservoir properties determine the plume behavior. The analytical approach for estimating plume movement based on Buckley-Leverett theory compares favorably with the simulation results; thus, it can explain the basic behavior of CO2 plume in this simplified reservoir model, which is homogeneous, anisotropic and tilted. If the plume encounters a fault within the reservoir, the fault can create new virtual source (CO2 build-up at the plume/fault intersection) for migration. It also leads to more complicated fluid movement, including counter current flow and/or dissolution. A sealing fault, which acts as another boundary for CO2 plume, divides the aquifer into two parts: fault-independent zone and fault dependent zone. The analytical solution can predict the properties of CO2 plume in the first zone, but not in the latter one due to the countercurrent flow. In both cases of a declined and an inclined fault, CO2 accumulates along the fault due to anisotropy causing dominantly parallel migration. The build-up continues until saturation approaches the endpoint dictated by the relative permeability curves (forming a virtual source), and then CO2 moves upward along the fault. According to Land’s model the larger the gas saturation reached as gas invades, the larger the residual gas saturation when water invades. Therefore, the saturation of CO2 plumes moving in the reservoir will determine the efficiency of residual saturation trapping. On the other hand, a conductive fault, which acts as a new pathway for migration, may cause considerable leakage of CO2 toward the top boundary of the reservoir (inclined fault) or increase the width of CO2 plume (declined fault). In the latter case, the CO2 plume passes through larger area, which improves the efficiency of residual saturation trapping. To understand the dynamics of CO2 behavior, especially countercurret flow, in the faulted reservoir we analyze flow vectors of both CO2 and brine phases, which explain the process of CO2 phase build-up and/or leakage due to structural heterogeneity. [Copyright &y& Elsevier]