55 results found
Kolster C, Agada S, Mac Dowell N, et al., 2018, The impact of time-varying CO<inf>2</inf>injection rate on large scale storage in the UK Bunter Sandstone, International Journal of Greenhouse Gas Control, Vol: 68, Pages: 77-85, ISSN: 1750-5836
© 2017 Elsevier Ltd Carbon capture and storage (CCS) is expected to play a key role in meeting targets set by the Paris Agreement and for meeting legally binding greenhouse gas emissions targets set within the UK (Energy and Climate Change Committee, 2016). Energy systems models have been essential in identifying the importance of CCS but they neglect to impose constraints on the availability and use of geologic CO 2 storage reservoirs. In this work we analyse reservoir performance sensitivities to varying CO 2 storage demand for three sets of injection scenarios designed to encompass the UK's future low carbon energy market. We use the ECLIPSE reservoir simulator and a model of part of the Southern North Sea Bunter Sandstone saline aquifer. From a first set of injection scenarios we find that varying amplitude and frequency of injection on a multi-year basis has little effect on reservoir pressure response and plume migration. Injectivity varies with site location due to variations in depth and regional permeability. In a second set of injection scenarios, we show that with envisioned UK storage demand levels for a large coal fired power plant, it makes no difference to reservoir response whether all injection sites are deployed upfront or gradually as demand increases. Meanwhile, there may be an advantage to deploying infrastructure in deep sites first in order to meet higher demand later. However, deep-site deployment will incur higher upfront cost than shallow-site deployment. In a third set of injection scenarios, we show that starting injection at a high rate with ramping down, a low rate with ramping up or at a constant rate makes little difference to the overall injectivity of the reservoir. Therefore, such variability is not essential to represent CO 2 storage in energy systems models resolving plume and pressure evolution over decadal timescales.
Agada S, Jackson S, Kolster C, et al., 2017, The impact of energy systems demands on pressure limited CO2 storage in the Bunter Sandstone of the UK Southern North Sea, INTERNATIONAL JOURNAL OF GREENHOUSE GAS CONTROL, Vol: 65, Pages: 128-136, ISSN: 1750-5836
Agada S, Kolster C, Williams G, et al., 2017, Sensitivity Analysis of the Dynamic CO<inf>2</inf>Storage Capacity Estimate for the Bunter Sandstone of the UK Southern North Sea, Pages: 4564-4570, ISSN: 1876-6102
© 2017 The Authors. Carbon capture and storage (CCS) in subsurface reservoirs has been identified as a potentially cost-effective way to reduce CO 2 emissions to the atmosphere. Global emissions reductions on the gigatonne scale using CCS will require regional or basin-scale deployment of CO 2 storage in saline aquifers. Thus the evaluation of both the dynamic and ultimate CO 2 storage capacity of formations is important for policy makers to determine the viability of CCS as a pillar of the greenhouse gas mitigation strategy in a particular region. We use a reservoir simulation model representing the large-scale Bunter Sandstone in the UK Southern North Sea to evaluate the dynamics and sensitivities of regional CO 2 plume transport and storage. At the basin-scale, we predict hydrogeological changes in the storage reservoir in response to multiple regional carbon sequestration development scenarios. We test the sensitivity of injection capacity to a range of target CO 2 injection rates and fluctuations in CO 2 supply. Model sensitivities varying the target injection rates indicate that in the absence of pressure management up to 3.7 Gt of CO 2 can be stored in the Bunter region over 50 years given the pressure constraints set to avoid fracturing the formation. Long-term (approx. 1000 years), our results show that up to 16 Gt of CO 2 can be stored in the Bunter region without pressure management. With pressure management, the estimate rises to 32 Gt. However, consideration must be given to the additional operational and economic requirements of pressure management using brine production.
Al-Menhali AS, Krevor S, 2017, Pore-scale Analysis of in Situ Contact Angle Measurements in Mixed-wet Rocks: Applications to Carbon Utilization in Oil Fields, Pages: 6919-6927, ISSN: 1876-6102
© 2017 The Authors. Carbon utilization in depleting oil reservoirs is considered as an important component in achieving the widespread commercial deployment of carbon capture and storage (CCS) technology. With absent strong climate policy, CO 2 enhanced oil recovery (EOR) process adds a significant revenue stream and makes the subsequent carbon storage process economically feasible. This is reflected in the great majority of CO 2 storage projects in oil fields utilizing CO 2 for EOR. Therefore, early deployment of subsurface carbon dioxide storage is likely to focus on injection into depleted or producing oil fields. Observations and modelling have shown that capillary trapping of CO 2 through capillary forces within the pore space of the water-wet rocks, typical of subsurface saline aquifers, is one of the most significant mechanisms for storage capacity. This important storage process is also a factor determining the ultimate extent of CO 2 plume migration within the reservoir, enhancing the security of the storage process. In contrast, carbonate oil reservoirs are characterized 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. This study discuss the first observations of supercritical CO 2 in a mixed-wet carbonate rock. Here we show that residual CO 2 trapping of supercritical CO 2 in a limestone altered to a mixed-wet state with crude oil is significantly less than trapping in water-wet systems characteristic of saline aquifers. The initial-residual CO 2 saturations characteristic curve are reported for each system from core scale observations. While pore scale observations provided the first in situ contact angle measurements of supercritical CO 2 in a mixed-wet rock and pore to pore arrangements of CO 2 droplets. The measurements were compared with trapping of N 2 and was similar
Alshawaf MH, Krevor S, Muggeridge A, 2017, Analysis of viscous crossflow in polymer flooding
Polymer flooding improves oil recovery by improving flood front conformance compared with waterflooding as well as, in some cases, extracting more oil from lower permeability zones in the reservoir by viscous cross-flow. However viscous cross-flow of water from the low permeability zone may also adversely affect the polymer flood by causing the polymer slug to be diluted and possibly to lose its integrity. The extent to which viscous cross-flow improves or reduces recovery depends upon the permeability contrast between the low and high permeability zones, the viscosity ratios of the fluids (oil, water and polymer solution) and the geometry of the layers. This paper uses inspectional analysis to derive the minimum set of 6 dimensionless numbers that can be used to characterise a polymer flood in a two layered model. A series of finely gridded numerical simulations are then performed to determine the contribution of viscous crossflow to oil recovery from secondary and tertiary polymer flooding in this system. We show that viscous cross-flow will only make a positive impact on oil recovery from secondary polymer flooding when the viscosity ratio values of oil to polymer solution is less than 1 and permeability ratio between the layers is less than 50. Furthermore, we show that there is an inverse relationship between the permeability ratio between layers and the amount of degradation the polymer slug experiences due to viscous crossflow in the high permeability layer. As the permeability contrast between layers increases, the slug degradation decreases. Also, the results show that the desired positive impact from viscous crossflow is higher in secondary polymer foods when compared to tertiary polymer floods. Finally, the results can be used to make initial estimates of the contribution of both viscous cross-flow and mobility control in polymer flooding applications without the need to perform extensive and time consuming numerical simulations.
Boon M, Bijeljic B, Krevor S, 2017, Observations of the impact of rock heterogeneity on solute spreading and mixing, WATER RESOURCES RESEARCH, Vol: 53, Pages: 4624-4642, ISSN: 0043-1397
Budinis S, Dowell NM, Krevor S, et al., 2017, Can Carbon Capture and Storage Unlock 'Unburnable Carbon'?, Pages: 7504-7515, ISSN: 1876-6102
© 2017 The Authors. 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 CO 2 (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 contribution 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 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.
Kolster C, Mechleri E, Krevor S, et al., 2017, The role of CO<inf>2</inf> purification and transport networks in carbon capture and storage cost reduction, International Journal of Greenhouse Gas Control, Vol: 58, Pages: 127-141, ISSN: 1750-5836
© 2017 Elsevier Ltd A number of Carbon Capture and Storage projects (CCS) are under way around the world, but the technology's high capital and operational costs act as a disincentive to large-scale deployment. In the case of both oxy-combustion and post-combustion CO 2 capture, the CO 2 compression and purification units (CO 2 CPU) are vital, but costly, process elements needed to bring the raw CO 2 product to a quality that is adequate for transport and storage. Four variants of the CO 2 CPU were modelled in Aspen HYSYS each of which provide different CO 2 product purities at different capital and operating costs. For each unit, a price of CO 2 is calculated by assuming that it is an independent entity in which to invest and the internal rate of return (IRR) must be greater or equal to the minimum rate o f return on investment. In this study, we test the hypothesis that, owing to the fact that CO 2 will likely be transported in multi-source networks, not all CO 2 streams will need to be of high purity, and that it may be possible to combine several sources of varying purity to obtain an end-product that is suitable for storage. We find that, when considering study generated costs for an example network in the UK, optimally combining these different sources into one multi-source transport network subject to a minimum CO 2 purity of 96% can reduce the price of captured CO 2 by 17%.
Kolster C, Mechleri E, Krevor S, et al., 2017, The role of CO2 purification and transport networks in carbon capture and storage cost reduction, INTERNATIONAL JOURNAL OF GREENHOUSE GAS CONTROL, Vol: 58, Pages: 127-141, ISSN: 1750-5836
Liyanage R, Crawshaw J, Krevor S, et al., 2017, Multidimensional Imaging of Density Driven Convection in a Porous Medium, Pages: 4981-4985, ISSN: 1876-6102
© 2017 The Authors. Carbon dioxide (CO 2 ) sequestration is a climate change mitigation technique which relies on residual and solubility trapping in injection locations with saline aquifers. The dissolution of CO 2 into resident brines results in density-driven convection which further enhances the geological trapping potential. We report on the use of an analogue fluid pair to investigate density-driven convection in 3D in an unconsolidated bead pack. X-ray computed tomography (CT) is used to image density-driven convection in the opaque porous medium non-invasively. Two studies have been conducted that differ by the Rayleigh number (Ra) of the system, which in this study is changed by altering the maximum density difference of the fluid pair. We observe the same general mixing pattern in both studies. Initially, many high density fingers move downward through the bead pack and as time progresses these coalesce and form larger dominate flow paths. However, we also observe that a higher Rayleigh number leads to the denser plume moving faster towards the bottom of the system. Due to the finite size of the system, this in turn leads to early convective shut-down.
Reynolds C, Krevor S, 2017, Capillary Limited Flow Behavior of CO<inf>2</inf>in Target Reservoirs in the UK, Pages: 4518-4523, ISSN: 1876-6102
© 2017 The Authors. The flow of supercritical CO 2 and brine in the subsurface is predicted to be strongly dependent on both the fluid properties and the heterogeneity of the pore space. However there are few laboratory studies that characterise the interaction between fluid properties and heterogeneity in real reservoir rocks. We explore the sensitivity of CO 2 flow paths and relative permeability to pore space capillary heterogeneity in target CO 2 storage reservoirs in the UK and Australia. Samples from potential North Sea and East Irish Sea reservoirs and a current CO 2 storage site in Australia are compared. The rock samples are all of high permeability ( > 500mD) and porosity ( > 12%), and are clean and homogeneous sandstones. Relative permeability is found to be highly sensitive to minor heterogeneities in pore structure at reservoir conditions that give rise to a low CO 2 viscosity and in particular when the flow is capillary limited, as will be the case for most of the reservoir. We use a simple capillary number in guiding the measurement of relative permeability and residual trapping under viscous and capillary limited conditions. Observations suggest that to fully characterise the behaviour in a reservoir a range of relative permeability curves must be measured which can be applied as the flow of CO 2 slows with distance from the near wellbore and flow behaviour changes from viscous-dominated to capillary-dominated. Experiments are performed at 8-20 MPa, 40-90 °C and brine molalities of 0 - 5 mol/kg NaCl. Saturation is measured in situ, using a medical x-ray CT scanner, which allows the fluid arrangement to be observed at a resolution of 0.25x0.25x1 mm.
Reynolds CA, Menke H, Andrew M, et al., 2017, Dynamic fluid connectivity during steady-state multiphase flow in a sandstone, PROCEEDINGS OF THE NATIONAL ACADEMY OF SCIENCES OF THE UNITED STATES OF AMERICA, Vol: 114, Pages: 8187-8192, ISSN: 0027-8424
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
Copyright 2016, Society of Petroleum Engineers. 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 CO 2 emissions reduction on industrial scales. Observations and modeling have shown that residual trapping of CO 2 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 CO 2 migration within the reservoir. In contrast, most of the major CO 2 storage projects in operation and under construction are in depleting oil reservoirs utilizing CO 2 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 CO 2 in mixed-wet carbonate systems, a characteristic of most conventional oil reservoirs in the world. In this work, residual trapping of supercritical CO 2 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, CO 2 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 CO 2 and brine at reservoir conditions. The measurements w
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 CO 2 emissions reduction on industrial scales. Observations and modeling have shown that residual trapping of CO 2 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 CO 2 migration within the reservoir. In contrast, most of the major CO 2 storage projects in operation and under construction are in depleting oil reservoirs utilizing CO 2 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 CO 2 in mixed-wet carbonate systems, a characteristic of most conventional oil reservoirs in the world. In this work, residual trapping of supercritical CO 2 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, CO 2 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 CO 2 and brine at reservoir conditions. The measurements were made while maintaining chemical equilibrium
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: 0013-936X
Al-Menhali AS, Menke HP, 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
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
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.
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
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.
Oostrom M, White MD, Porse SL, et al., 2016, 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
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
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.
Krevor S, 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
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.
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
Reynolds CA, Krevor S, 2015, Characterizing flow behavior for gas injection: Relative permeability of CO2-brine and N-2-water in heterogeneous rocks, WATER RESOURCES RESEARCH, Vol: 51, Pages: 9464-9489, ISSN: 0043-1397
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
Copyright 2015, Society of Petroleum Engineers. We used conventional numerical simulation of immiscible multiphase flow to reproduce laboratory observations of the CO 2 /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 CO 2 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 CO 2 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, Krevor S, 2014, Effective wettability measurements of CO2-brine-sandstone system at different reservoir conditions, 12th International Conference on Greenhouse Gas Control Technologies (GHGT), Publisher: ELSEVIER SCIENCE BV, Pages: 5420-5426, ISSN: 1876-6102
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