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Bond D, Krevor SC, Muggeridge AH, et al., 2017, Imperial College Lectures In Petroleum Engineering: Topics In Reservoir Management, ISBN: 9781786342850
Krevor SC, Muggeridge AH, 2017, Introduction to Enhanced Recovery Processes for Conventional Oil Production, Imperial College Lectures In Petroleum Engineering, The - Volume 3: Topics In Reservoir Management, Pages: 47-107, ISBN: 9781786342850
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- Citations: 1
Budinis S, Mac Dowell N, Krevor S, et al., 2017, Can carbon capture and storage unlock `unburnable carbon'?, 13th International Conference on Greenhouse Gas Control Technologies (GHGT), Publisher: Elsevier Science BV, Pages: 7504-7515, ISSN: 1876-6102
The concept of ‘unburnable carbon’ emerged in 2011, and stems from the observation that if all known fossil fuel reserves are extracted and converted to CO2(unabated), it would exceed the carbon budget and have a very significant effect on the climate. Therefore, if global warming is to be limited to the COP21 target, some of the known fossil fuel reserves should remain unburnt. Several recent reports have highlighted the scale of the challenge, drawing on scenarios of climate change mitigation and their implications for the projected consumption of fossil fuels. Carbon Capture and Storage (CCS) is a critical and available mitigation opportunity and its contributionto timely and cost-effective decarbonisation of the energy system is widely recognised. However, while some studies have considered the role of CCS in enabling access to more fossil fuels, no detailed analysis on this issue has been undertaken. This paper presents a critical review focusing on the technologies that can be applied to enable access to, or ‘unlock’, fossil fuel reserves in a way that will meet climate targets and mitigate climate change. It also quantifies the impact of CCS in unlocking unburnable carbon in the first and in the second half of the century.
Porter RTJ, Mahgerefteh H, Brown S, et al., 2016, Techno-economic assessment of CO2 quality effect on its storage and transport: CO(2)QUEST An overview of aims, objectives and main findings, International Journal of Greenhouse Gas Control, Vol: 54, Pages: 662-681, ISSN: 1750-5836
This paper provides an overview of the aims, objectives and the main findings of the CO2QUEST FP7 collaborative project, funded by the European Commission and designed to address the fundamentally important and urgent issues regarding the impact of the typical impurities in CO2 streams captured from fossil fuel power plants and other CO2 intensive industries on their safe and economic pipeline transportation and storage. The main features and results recorded from some of the unique test facilities constructed as part of the project are presented. These include an extensively instrumented realistic-scale test pipeline for conducting pipeline rupture and dispersion tests in China, an injection test facility in France to study the mobility of trace metallic elements contained in a CO2 stream following injection near a shallow-water qualifier and fluid/rock interactions and well integrity experiments conducted using a fully instrumented deep-well CO2/impurities injection test facility in Israel. The above, along with the various unique mathematical models developed, provide the fundamentally important tools needed to define impurity tolerance levels, mixing protocols and control measures for pipeline networks and storage infrastructure, thus contributing to the development of relevant standards for the safe design and economic operation of CCS.
Al-menhali A, Menke H, Blunt MJ, et al., 2016, Pore Scale Observations of Trapped CO2 in Mixed-Wet Carbonate Rock: Applications to Storage in Oil Fields, Environmental Science & Technology, Vol: 50, Pages: 10282-10290, ISSN: 0013-936X
Geologic CO2 storage has been identified as a key to avoiding dangerous climate change. Storage in oil reservoirs dominates the portfolio of existing projects due to favorable economics. However, in an earlier related work (Al-Menhali and Krevor Environ. Sci. Technol. 2016, 50, 2727−2734), it was identified that an important trapping mechanism, residual trapping, is weakened in rocks with a mixed wetting state typical of oil reservoirs. We investigated the physical basis of this weakened trapping using pore scale observations of supercritical CO2 in mixed-wet carbonates. The wetting alteration induced by oil provided CO2-wet surfaces that served as conduits to flow. In situ measurements of contact angles showed that CO2 varied from nonwetting to wetting throughout the pore space, with contact angles ranging 25° < θ < 127°; in contrast, an inert gas, N2, was nonwetting with a smaller range of contact angle 24° < θ < 68°. Observations of trapped ganglia morphology showed that this wettability allowed CO2 to create large, connected, ganglia by inhabiting small pores in mixed-wet rocks. The connected ganglia persisted after three pore volumes of brine injection, facilitating the desaturation that leads to decreased trapping relative to water-wet systems.
Boon M, Bijeljic B, Niu B, et al., 2016, Observations of 3-D transverse dispersion and dilution in natural consolidated rock by X-ray tomography, Advances in Water Resources, Vol: 96, Pages: 266-281, ISSN: 0309-1708
Recent studies have demonstrated the importance of transverse dispersion for dilution and mixing of solutes but most observations have remained limited to two-dimensional sand-box models. We present a new core-flood test to characterize solute transport in 3-D natural-rock media. A device consisting of three annular regions was used for fluid injection into a cylindrical rock core. Pure water was injected into the center and outer region and a NaI solution into the middle region. Steady state transverse dispersion of NaI was visualized with an X-ray medical CT-scanner for a range of Peclét numbers. Three methods were used to calculate Dt: (1) fitting an analytical solution, (2) analyzing the second-central moment, and (3) analyzing the dilution index and reactor ratio. Transverse dispersion decreased with distance due to flow focusing. Furthermore, Dt in the power-law regime showed sub-linear behavior. Overall, the reactor ratios were high confirming the homogeneity of Berea sandstone.
Budinis S, Krevor S, Mac Dowell N, et al., 2016, Can technology unlock unburnable carbon?
In 2015, the Conference Of the Parties in Paris (COP21) reached a universal agreement on climate change with the aim of limiting global warming to below 2 °C. In order to stay below 2 °C, the total amount of carbon dioxide (CO2) released, or ‘carbon budget’ must be less than 1,000 gigatonnes (Gt) of CO2. At the current emission rate, this budget will be eroded within the next thirty years. Meeting this target on a global scale is challenging and will require prompt and effective climate change mitigation action.The concept of ‘unburnable carbon’ emerged in 2011, and stems from theobservation that if all known fossil fuel reserves are extracted and converted to CO2 (unabated), it would exceed the carbon budget and have a very significant effect on the climate. Therefore, if global warming is to be limited to the COP21 target, some of the known fossil fuel reserves should remain unburnt.Several recent reports have highlighted the scale of the challenge, drawing on scenarios of climate change mitigation and their implications for the projected consumption of fossil fuels. Carbon capture and storage (CCS) is a critical and available mitigation opportunity that is often overlooked. The positive contribution of CCS technology to timely and cost-effective decarbonisation of the energy system is widely recognised. However, while some studies have considered the role of CCS in enabling access to more fossil fuels, no detailed analysis on this issue has been undertaken.This White Paper presents a critical review focusing on the technologies that can be applied to enable access to, or ‘unlock’, fossil fuel reserves in a way that will meet climate targets and mitigate climate change.The paper includes an introduction to the key issues of carbon budgets and fossil fuel reserves, a detailed analysis of the current status of CCS technology, as well as a synthesis of a multi-model comparison study on global climate change mitigation strat
Al-Menhali AS, Krevor S, 2016, Capillary trapping of CO2 in oil reservoirs: observations in a mixed-wet carbonate rock, Environmental Science & Technology, Vol: 50, Pages: 2727-2734, ISSN: 1520-5851
Early deployment of carbon dioxide storage is likely to focus on injection into mature oil reservoirs, most of which occur in carbonate rock units. Observations and modeling have shown how capillary trapping leads to the immobilization of CO2 in saline aquifers, enhancing the security and capacity of storage. There are, however, no observations of trapping in rocks with a mixed-wet-state characteristic of hydrocarbon-bearing carbonate reservoirs. Here, we found that residual trapping of supercritical CO2 in a limestone altered to a mixed-wet state with oil was significantly less than trapping in the unaltered rock. In unaltered samples, the trapping of CO2 and N2 were indistinguishable, with a maximum residual saturation of 24%. After the alteration of the wetting state, the trapping of N2 was reduced, with a maximum residual saturation of 19%. The trapping of CO2 was reduced even further, with a maximum residual saturation of 15%. Best-fit Land-model constants shifted from C = 1.73 in the water-wet rock to C = 2.82 for N2 and C = 4.11 for the CO2 in the mixed-wet rock. The results indicate that plume migration will be less constrained by capillary trapping for CO2 storage projects using oil fields compared with those for saline aquifers.
Krevor S, Reynolds C, Al-Menhali A, et al., 2016, The impact of reservoir conditions and rock heterogeneity on CO2-Brine multiphase flow In permeable sandstone, Petrophysics, Vol: 57, Pages: 12-18, ISSN: 1529-9074
Djabbarov S, Jones ADW, Krevor S, et al., 2016, Experimental and numerical studies of first contact miscible injection in a quarter five spot pattern
Copyright 2016, Society of Petroleum Engineers. We quantify the impact of mobility, simple heterogeneities and grid orientation error on the performance of first contact miscible gas flooding in a quarter five spot configuration by comparing the outputs from experimental and numerical models. The aim is to quantify the errors that may arise during simulation and to identify a workflow for minimizing these when conducting field scale fingering studies. A commercial reservoir simulator was validated by comparing its predictions with the results obtained from physical experiments. An uncorrelated, random permeability distribution was used to trigger fingering in the simulations. The physical experiments were carried out using a Hele-Shaw cell (40x40cm) designed and constructed for this study. The impact of a square low permeability inclusion (20x20cm) on flow was investigated by varying its permeability, location and orientation. For lower mobility ratios (M=2 to M=10) the commercial numerical simulator was able to reproduce the experimental observations within the uncertainty range of the permeability distribution used to trigger the fingers, provided a nine-point scheme was used for the pressure solution. At higher mobility ratios (M=20 to M=100) the grid orientation effect meant that the simulator overestimated the areal sweep even when a nine-point scheme was used. The introduction of a square, low permeability inclusion near the injection well reduced the discrepancy between experimental and numerical results, bringing it back within uncertainty limits in some of the cases. This was mainly because the real flow was then forced to move parallel to the edges of the Hele-Shaw cell and thus parallel to the simulation grid. Breakthrough times were well predicted by the numerical simulator at all mobility ratios.
Agada S, Kolster C, Williams G, et al., 2016, Modelling basin-scale CO2 storage in the Bunter Sandstone of the UK Southern North Sea
In this paper, a reservoir simulation model of the large-scale Bunter Sandstone in the UK Southern North Sea is used to evaluate the dynamics of regional CO2 plume transport and storage. We have tested the sensitivity of injection capacity to a range of target CO2 injection rates and the number of sites at which injection is deployed. In addition to geology, the model is constrained by local bottom-hole-pressure (BHP) limits and site spacing. Large-scale pressure buildup limitations and the impact of brine production on storage capacity are also evaluated. Furthermore, monitoring of the CO2 plume at multiple injection sites indicates important subsurface controls on plume migration in the context of short-term (approx. 50 years) and long-term CO2 storage (approx. 1000 years).
Al-Menhali A, Krevor S, 2016, The impact of crude oil induced wettability alteration on remaining saturations of CO<inf>2</inf> in carbonates reservoirs: A core flood method
Oil is an essential commodity in modern economies but the magnitude of carbon emissions associated with its consumption is significantly increasing the challenges of climate change mitigations. Carbon storage is well recognized as an important technology for CO2 emissions reduction on industrial scales. Observations and modeling have shown that residual trapping of CO2 through capillary forces within the pore space of saline aquifers, characterized as water-wet, is one of the most significant mechanisms for storage security and is also a factor determining the ultimate extent of CO2 migration within the reservoir. In contrast, most of the major CO2 storage projects in operation and under construction are in depleting oil reservoirs utilizing CO2 for enhanced oil recovery (EOR). Carbon utilization and storage has a significant energy and economic benefits and is considered as an important component in achieving the widespread commercial deployment of carbon storage technology. However, there are no observations characterizing the extent of capillary trapping of CO2 in mixed-wet carbonate systems, a characteristic of most conventional oil reservoirs in the world. In this work, residual trapping of supercritical CO2 is measured in water-wet and mixed-wet carbonate systems on the same rock sample before and after wetting alteration with crude oil. In particular, CO2 trapping was characterized before and after wetting alteration so that the impact of the wetting state of the rock is observed directly. A reservoir condition core-flooding laboratory was used to make the measurements. The setup included high precision pumps, temperature control, stir reactor, the ability to recirculate fluids for weeks at a time and an X-ray computed tomography (CT) scanner. The wetted parts of the flow-loop were made of anti-corrosive material that can handle co-circulation of CO2 and brine at reservoir conditions. The measurements were made while maintaining chemical equilibrium between t
Li X, Yi T, Giddins M, et al., 2016, A novel approach for waterflood management optimisation using streamline technology
This paper presents a new streamline-based workflow to cover the two main aspects of waterflood management optimisation: infill drilling well location identification and injection rate allocation. Streamline properties are used in every step of the evaluation and decision-making process in the workflow. A novel ranking scheme, weighted by streamline 'remaining mobile oil in pattern', is developed in this study. The well ranking criteria are not only based on the properties of individual well completion cells as in a traditional quality map, but also account for connectivity between injector/producer pairs. In such a way, candidate producers at high-quality map locations, but with poor connectivity or limited swept area, can be screened out. The other main component of the workflow is to perform dynamic pattern injection reallocation in response to the changed well pattern resulting from newly introduced producers. A unique insight for utilization of a multi-zone waterflood for a vertically heterogeneous field is also provided. 2D and 3D heterogeneous models were used to develop and validate the workflow for its general implementation on real field models. The final oil recovery and net present value (NPV) analysis show that the oil recovery can be increased significantly compared to traditional optimisation methods.
Al-Menhali A, Krevor S, 2016, The impact of crude oil induced wettability alteration on remaining saturations of CO<inf>2</inf> in carbonates reservoirs: A core flood method
Oil is an essential commodity in modern economies but the magnitude of carbon emissions associated with its consumption is significantly increasing the challenges of climate change mitigations. Carbon storage is well recognized as an important technology for CO2 emissions reduction on industrial scales. Observations and modeling have shown that residual trapping of CO2 through capillary forces within the pore space of saline aquifers, characterized as water-wet, is one of the most significant mechanisms for storage security and is also a factor determining the ultimate extent of CO2 migration within the reservoir. In contrast, most of the major CO2 storage projects in operation and under construction are in depleting oil reservoirs utilizing CO2 for enhanced oil recovery (EOR). Carbon utilization and storage has a significant energy and economic benefits and is considered as an important component in achieving the widespread commercial deployment of carbon storage technology. However, there are no observations characterizing the extent of capillary trapping of CO2 in mixed-wet carbonate systems, a characteristic of most conventional oil reservoirs in the world. In this work, residual trapping of supercritical CO2 is measured in water-wet and mixed-wet carbonate systems on the same rock sample before and after wetting alteration with crude oil. In particular, CO2 trapping was characterized before and after wetting alteration so that the impact of the wetting state of the rock is observed directly. A reservoir condition core-flooding laboratory was used to make the measurements. The setup included high precision pumps, temperature control, stir reactor, the ability to recirculate fluids for weeks at a time and an X-ray computed tomography (CT) scanner. The wetted parts of the flow-loop were made of anti-corrosive material that can handle co-circulation of CO2 and brine at reservoir conditions. The measurements were made while maintaining chemical equilibrium between t
Li X, Yi T, Giddins M, et al., 2016, A novel approach for waterflood management optimisation using streamline technology
This paper presents a new streamline-based workflow to cover the two main aspects of waterflood management optimisation: infill drilling well location identification and injection rate allocation. Streamline properties are used in every step of the evaluation and decision-making process in the workflow. A novel ranking scheme, weighted by streamline 'remaining mobile oil in pattern', is developed in this study. The well ranking criteria are not only based on the properties of individual well completion cells as in a traditional quality map, but also account for connectivity between injector/producer pairs. In such a way, candidate producers at high-quality map locations, but with poor connectivity or limited swept area, can be screened out. The other main component of the workflow is to perform dynamic pattern injection reallocation in response to the changed well pattern resulting from newly introduced producers. A unique insight for utilization of a multi-zone waterflood for a vertically heterogeneous field is also provided. 2D and 3D heterogeneous models were used to develop and validate the workflow for its general implementation on real field models. The final oil recovery and net present value (NPV) analysis show that the oil recovery can be increased significantly compared to traditional optimisation methods.
Djabbarov S, Jones ADW, Krevor S, et al., 2016, Experimental and numerical studies of first contact miscible injection in a quarter five spot pattern
We quantify the impact of mobility, simple heterogeneities and grid orientation error on the performance of first contact miscible gas flooding in a quarter five spot configuration by comparing the outputs from experimental and numerical models. The aim is to quantify the errors that may arise during simulation and to identify a workflow for minimizing these when conducting field scale fingering studies. A commercial reservoir simulator was validated by comparing its predictions with the results obtained from physical experiments. An uncorrelated, random permeability distribution was used to trigger fingering in the simulations. The physical experiments were carried out using a Hele-Shaw cell (40x40cm) designed and constructed for this study. The impact of a square low permeability inclusion (20x20cm) on flow was investigated by varying its permeability, location and orientation. For lower mobility ratios (M=2 to M=10) the commercial numerical simulator was able to reproduce the experimental observations within the uncertainty range of the permeability distribution used to trigger the fingers, provided a nine-point scheme was used for the pressure solution. At higher mobility ratios (M=20 to M=100) the grid orientation effect meant that the simulator overestimated the areal sweep even when a nine-point scheme was used. The introduction of a square, low permeability inclusion near the injection well reduced the discrepancy between experimental and numerical results, bringing it back within uncertainty limits in some of the cases. This was mainly because the real flow was then forced to move parallel to the edges of the Hele-Shaw cell and thus parallel to the simulation grid. Breakthrough times were well predicted by the numerical simulator at all mobility ratios.
Agada S, Kolster C, Williams G, et al., 2016, Modelling basin-scale CO2 storage in the Bunter Sandstone of the UK Southern North Sea
In this paper, a reservoir simulation model of the large-scale Bunter Sandstone in the UK Southern North Sea is used to evaluate the dynamics of regional CO2 plume transport and storage. We have tested the sensitivity of injection capacity to a range of target CO2 injection rates and the number of sites at which injection is deployed. In addition to geology, the model is constrained by local bottom-hole-pressure (BHP) limits and site spacing. Large-scale pressure buildup limitations and the impact of brine production on storage capacity are also evaluated. Furthermore, monitoring of the CO2 plume at multiple injection sites indicates important subsurface controls on plume migration in the context of short-term (approx. 50 years) and long-term CO2 storage (approx. 1000 years).
Oostrom M, White MD, Porse SL, et al., 2015, Comparison of relative permeability-saturation-capillary pressure models for simulation of reservoir CO2 injection, International Journal of Greenhouse Gas Control, Vol: 45, Pages: 70-85, ISSN: 1750-5836
Constitutive relations between relative permeability (kr), fluid saturation (S), and capillary pressure (Pc) determine to a large extent the distribution of brine and supercritical CO2 (scCO2) during subsurface injection operations. Published numerical multiphase simulations for brine-scCO2 systems so far have primarily used four kr-S-Pc models. For the S-Pc relations, either the Brooks-Corey (BC) or Van Genuchten (VG) equations are used. The kr-S relations are based on Mualem, Burdine, or Corey equations without the consideration of experimental data. Recently, two additional models have been proposed where the kr-S relations are obtained by fitting to experimental data using either an endpoint power law or a modified Corey approach. The six models were tested using data from four well-characterized sandstones (Berea, Paaratte, Tuscaloosa, Mt. Simon) for two radial injection test cases. The results show a large variation in plume extent and saturation distribution for each of the sandstones, depending on the used model. The VG-Mualem model predicts plumes that are considerably larger than for the other models due to the overestimation of the gas relative permeability. The predicted plume sizes are the smallest for the VG-Corey model due to the underestimation of the aqueous phase relative permeability. Of the four models that do not use fits to experimental relative permeability data, the hybrid model with Mualem aqueous phase and Corey gas phase relative permeabilities provide the best fits to the experimental data and produce results close to the model with fits to the capillary pressure and relative permeability data. The model with the endpoint power law resulted in very low, uniform gas saturations outside the dry-out zone for the Tuscaloosa sandstone, as the result of a rapidly declining aqueous phase relative permeability. This observed behavior illustrates the need to obtain reliable relative permeability relations for a potential reservoir, beyond permeabi
Reynolds C, Krevor S, 2015, Characterising flow behaviour for gas injection: relative permeability of CO sub 2 /sub -brine and N sub 2 /sub-water in heterogeneous rocks, Water Resources Research, Vol: 51, Pages: 9464-9489, ISSN: 0043-1397
We provide a comprehensive experimental study of steady state, drainage relative permeability curves with CO2-brine and N2-deionized water, on a single Bentheimer sandstone core with a simple two-layer heterogeneity. We demonstrate that, if measured in the viscous limit, relative permeability is invariant with changing reservoir conditions, and is consistent with the continuum-scale multiphase flow theory for water wet systems. Furthermore, we show that under capillary limited conditions, the CO2-brine system is very sensitive to heterogeneity in capillary pressure, and by performing core floods under capillary limited conditions, we produce effective relative permeability curves that are flow rate and fluid parameter dependent. We suggest that the major uncertainty in past observations of CO2-brine relative permeability curves is due to the interaction of CO2 flow with pore space heterogeneity under capillary limited conditions and is not due to the effects of changing reservoir conditions. We show that the appropriate conditions for measuring intrinsic or effective relative permeability curves can be selected simply by scaling the driving force for flow by a quantification of capillary heterogeneity. Measuring one or two effective curves on a core with capillary heterogeneity that is representative of the reservoir will be sufficient for reservoir simulation.
Al-Menhali A, Niu B, Krevor S, 2015, Capillarity and wetting of carbon dioxide and brine during drainage in Berea sandstone at reservoir conditions, Water Resources Research, Vol: 51, Pages: 7895-7914, ISSN: 0043-1397
The wettability of CO2-brine-rock systems will have a major impact on the management of carbon sequestration in subsurface geological formations. Recent contact angle measurement studies have reported sensitivity in wetting behaviour of this system to pressure, temperature and brine salinity. We report observations of the impact of reservoir conditions on the capillary pressure characteristic curve and and relative permeability of a single Berea sandstone during drainage - CO2 displacing brine - through effects on the wetting state. Eight reservoir condition drainage capillary pressure characteristic curves were measured using CO2 and brine in a single fired Berea sandstone at pressures (5 to 20 MPa), temperatures (25 to 50°C) and ionic strengths (0 to 5 mol kg−1 NaCl). A ninth measurement using a N2-water system provided a benchmark for capillarity with a strongly water wet system. The capillary pressure curves from each of the tests were found to be similar to the N2-water curve when scaled by the interfacial tension. Reservoir conditions were not found to have a significant impact on the capillary strength of the CO2-brine system during drainage through a variation in the wetting state. Two steady-state relative permeability measurements with CO2 and brine and one with N2 and brine similarly show little variation between conditions, consistent with the observation that the CO2-brine-sandstone system is water wetting and multiphase flow properties invariant across a wide range of reservoir conditions.
Lai P, Moulton K, Krevor S, 2015, Pore-scale heterogeneity in the mineral distribution and reactive surface area of porous rocks, Chemical Geology, Vol: 411, Pages: 260-273, ISSN: 0009-2541
The reactive surface area is an important control on interfacial processes between minerals and aqueous fluids in porous rocks. Spatial heterogeneity in the surface area can lead to complications in modelling reactive transport processes, but quantitative characterisation of this property has been limited. In this paper 3D images obtained using x-ray micro-tomography were used to characterise heterogeneity in surface area in one sandstone and five carbonate rocks. Measurements of average surface area from x-ray imagery were 1-2 orders of magnitude lower than measurements from nitrogen BET. A roughness factor, defined as the ratio of BET surface area to x-ray based surface area, was correlated to the presence of clay or microporosity. Co-registered images of Berea sandstone from x-ray and energy dispersive spectroscopy imagery were used to guide the identification of quartz, K-feldspar, dolomite, calcite and clays in x-ray images. In Berea sandstone, clay and K-feldspar had higheraverage surface area fractions than their volumetric fractions in the rock. In the Edwards carbonate, however, modal mineral composition correlated with surface area. By sub-sampling digital images, statistical distributions of the surface area were generated at various length scales of subsampling. Comparing these to distributions used in published modelling studies showed that the common practice of leaving surface area and pore volume uncorrelated in a pore has lead to unrealistic combinations of surface area and pore volume in the models. We suggest these models adopt a moderate correlation based on observations. In Berea sandstone, constraining ratios of surface area to pore volume to a range of values between that of quartz-lined and five times that of clay-lined spheres appeared sufficient.
Krevor SC, Blunt MJ, Benson SM, et al., 2015, Capillary trapping for geologic carbon dioxide storage - From pore scale physics to field scale implications, International Journal of Greenhouse Gas Control, Vol: 40, Pages: 221-237, ISSN: 1750-5836
A significant amount of theoretical, numerical and observational work has been published focused on various aspects of capillary trapping in CO2 storage since the IPCC Special Report on Carbon Dioxide Capture and Storage (2005). This research has placed capillary trapping in a central role in nearly every aspect of the geologic storage of CO2. Capillary, or residual, trapping – where CO2 is rendered immobile in the pore space as disconnected ganglia, surrounded by brine in a storage aquifer – is controlled by fluid and interfacial physics at the size scale of rock pores. These processes have been observed at the pore scale in situ using X-ray microtomography at reservoir conditions. A large database of conventional centimetre core scale observations for flow modelling are now available for a range of rock types and reservoir conditions. These along with the pore scale observations confirm that trapped saturations will be at least 10% and more typically 30% of the pore volume of the rock, stable against subsequent displacement by brine and characteristic of water-wet systems. Capillary trapping is pervasive over the extent of a migrating CO2 plume and both theoretical and numerical investigations have demonstrated the first order impacts of capillary trapping on plume migration, immobilisation and CO2 storage security. Engineering strategies to maximise capillary trapping have been proposed that make use of injection schemes that maximise sweep or enhance imbibition. National assessments of CO2 storage capacity now incorporate modelling of residual trapping where it can account for up to 95% of the storage resource. Field scale observations of capillary trapping have confirmed the formation and stability of residually trapped CO2 at masses up to 10,000 tons and over time scales of years. Significant outstanding uncertainties include the impact of heterogeneity on capillary immobilisation and capillary trapping in mixed-wet systems. Overall capillary trapp
Niu B, Al-Menhali A, Krevor SC, 2015, The impact of reservoir conditions on the residual trapping of carbon dioxide in Berea sandstone, WATER RESOURCES RESEARCH, Vol: 51, Pages: 2009-2029, ISSN: 0043-1397
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- Citations: 68
Zhou Z, Krevor S, Reynolds C, 2015, A simulation investigation into the influence of thermophysical fluid properties on CO<inf>2</inf> brine core flooding experiments, Pages: 1141-1157
We used conventional numerical simulation of immiscible multiphase flow to reproduce laboratory observations of the CO2/Brine system. A model of homogeneous rock properties was QC'ed on Buckley-Leverett, gravity effect and capillary end effect. The natural rock heterogeneity in the core was modelled by capillary heterogeneity, and calibrated by fluid distribution observed during the experiment. The calibrated model was then used to produce synthetic relative permeability observables by changing thermophysical fluid properties, knowing what the intrinsic relative permeabilities are. It was discovered that a change in reservoir conditions and particularly CO2 viscosity can lead to changing the impact that a natural rock heterogeneity in the core has on the fluid distribution. We showed that viscous-pressuredrive determines the extent to which rock heterogeneity matters in a core flooding experiment and demonstrated that heterogeneity can lead to a deviation in observed relative permeability from its intrinsic value. Given CO2 viscosity changes much more dramatically with reservoir conditions than other fluids, the impact of reservoir conditions on relative permeability tests is apparently observed because the changing conditions increases or decreases the role of heterogeneity in the core. We therefore concluded that appropriate relative permeability observations require a homogeneous fluid distribution and thus flow rates should be used where possible to minimize the impact of heterogeneity.
Al-Menhali A, Reynolds C, Lai P, et al., 2014, Advanced reservoir characterization for CO<inf>2</inf> storage, Pages: 503-512
Injection of CO2 into the subsurface is of interest for CO 2 storage and enhanced oil recovery (EOR). There are, however, major unresolved questions around the multiphase flow physics and reactive processes that will take place after CO2 is injected, particularly in carbonate rock reservoirs. For example, the wetting properties of CO2-brine- rock systems will impact the efficiency of EOR operations and CO2 storage but reported contact angles range widely from strongly water-wet to intermediate wet. Similar uncertainties exist for properties including the relative permeability and the impact of chemical reaction on flow. In this presentation we present initial results from laboratory studies investigating the physics of multiphase flow and reactive transport for CO2-brine systems. We use traditional and novel core flooding techniques and x-ray imaging to resolve uncertainties around the CO2-brine contact angle, relative permeability, residual trapping, and feedbacks between chemical reaction and flow in carbonate rocks. Copyright 2014, International Petroleum Technology Conference.
Niu B, Krevor S, 2014, The impact of reservoir conditions on the measurement of multiphase flow properties for CO2-brine systems, Pages: 77-81
Successful industrial scale carbon dioxide injection into deep saline aquifers will be dependent on the ability to model the flow of the fluid and to quantify the impact of various trapping mechanisms. The effectiveness of the models is in turn dependent on high quality laboratory measurements ofbasic multiphase flow properties such as relative permeability and residual trapping at reservoir conditions. At the same time there exists general uncertainty around the few existing published data on these properties for CO2-brine systems. In this study we present results from a newly constructed reservoir condition coreflooding and imaging laboratory designed to measure multiphase flow properties, capillary pressure, relative permeability and residual trapping at a range of reservoir conditions. The proper approach to measuring relative permeability for CO2-brine system is proposed and demonstrated. The changes in residual trapping correlated to pressure, temperature, brine salinity, interfacial tension, and contact angle are also reported. We also show with a combination of simulations of corefloods and experiments performed at various conditions that high precision results can be obtained for this system when the appropriate conditions are used. Copyright © (2014) by the European Association of Geoscientists & Engineers. All rights reserved.
Niu B, Al-Menhali A, Krevor S, 2014, A study of residual carbon dioxide trapping in sandstone, 12th International Conference on Greenhouse Gas Control Technologies (GHGT), Publisher: ELSEVIER SCIENCE BV, Pages: 5522-5529, ISSN: 1876-6102
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- Citations: 18
Lai P, Krevor S, 2014, Pore scale heterogeneity in the mineral distribution and surface area of Berea sandstone, 12th International Conference on Greenhouse Gas Control Technologies (GHGT), Publisher: ELSEVIER SCIENCE BV, Pages: 3582-3588, ISSN: 1876-6102
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- Citations: 16
Reynolds C, Blunt M, Krevor S, 2014, Impact of reservoir conditions on CO<sub>2</sub>-brine relative permeability in sandstones, 12th International Conference on Greenhouse Gas Control Technologies (GHGT), Publisher: ELSEVIER SCIENCE BV, Pages: 5577-5585, ISSN: 1876-6102
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- Citations: 15
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