128 results found
Garfi G, John CM, Rucker M, et al., 2022, Determination of the spatial distribution of wetting in the pore networks of rocks, JOURNAL OF COLLOID AND INTERFACE SCIENCE, Vol: 613, Pages: 786-795, ISSN: 0021-9797
Zhang Y, Jackson C, Zahasky C, et al., 2022, European carbon storage resource requirements of climate change mitigation targets, INTERNATIONAL JOURNAL OF GREENHOUSE GAS CONTROL, Vol: 114, ISSN: 1750-5836
Harris C, Jackson SJ, Benham GP, et al., 2021, The impact of heterogeneity on the capillary trapping of CO2 in the Captain Sandstone, International Journal of Greenhouse Gas Control, Vol: 112, Pages: 1-12, ISSN: 1750-5836
A significant uncertainty which remains for CO2 sequestration, is the effect of natural geological heterogeneitiesand hysteresis on capillary trapping over different length scales. This paper uses laboratory data measured incores from the Goldeneye formation of the Captain D Sandstone, North Sea in 1D numerical simulations toevaluate the potential capillary trapping from natural rock heterogeneities across a range of scales, from cm to65m. The impact of different geological realisations, as well as uncertainty in petrophysical properties, on theamount of capillary heterogeneity trapping is estimated. In addition, the validity of upscaling trapping characteristics in terms of the Land trapping parameter is assessed. The numerical models show that the capillaryheterogeneity trapped CO2 saturation may vary between 0 and 14% of the total trapped saturation, dependingupon the geological realisation and petrophysical uncertainty. When upscaling the Land model from core-scaleexperimental data, using the maximum experimental Land trapping parameter could increase the expectedheterogeneity trapping by a factor of 3. Conversely, depending on the form of the imbibition capillary pressurecurve used in the numerical model, including capillary pressure hysteresis may reduce the heterogeneity trapping by up to 70%.
Wenck N, Jackson SJ, Manoorkar S, et al., 2021, Simulating Core Floods in Heterogeneous Sandstone and Carbonate Rocks, WATER RESOURCES RESEARCH, Vol: 57, ISSN: 0043-1397
Manoorkar S, Jackson SJ, Krevor S, 2021, Observations of the Impacts of Millimeter- to Centimeter-Scale Heterogeneities on Relative Permeability and Trapping in Carbonate Rocks, WATER RESOURCES RESEARCH, Vol: 57, ISSN: 0043-1397
Spurin C, Bultreys T, Rücker M, et al., 2021, The development of intermittent multiphase fluid flow pathways through a porous rock, Advances in Water Resources, Vol: 150, Pages: 1-7, ISSN: 0309-1708
storage and natural gas production. However, due to experimental limitations, it has not been possible to identify why intermittency occurs at subsurface conditions and what the implications are for upscaled flow properties such as relative permeability. We address these questions with observations of nitrogen and brine flowing at steady-state through a carbonate rock. We overcome previous imaging limitations with high-speed (1s resolution), synchrotron-based X-ray micro-computed tomography combined with pressure measurements recorded while controlling fluid flux. We observe that intermittent fluid transport allows the non-wetting phase to flow through a more ramified network of pores, which would not be possible with connected pathway flow alone for the same flow rate. The volume of fluid intermittently fluctuating increases with capillary number, with the corresponding expansion of the flow network minimising the role of inertial forces in controlling flow even as the flow rate increases. Intermittent pathway flow sits energetically between laminar and turbulent through connected pathways. While a more ramified flow network favours lowered relative permeability, intermittency is more dissipative than laminar flow through connected pathways, and the relative permeability remains unchanged for low capillary numbers where the pore geometry controls the location of intermittency. However, as the capillary number increases further, the role of pore structure in controlling intermittency decreases which corresponds to an increase in relative permeability. These observations can serve as the basis of a model for the causal links between intermittent fluid flow, fluid distribution throughout the pore space, and the upscaled manifestation in relative permeability.
De Simone S, Krevor S, 2021, A tool for first order estimates and optimisation of dynamic storage resource capacity in saline aquifers, International Journal of Greenhouse Gas Control, Vol: 106, Pages: 1-11, ISSN: 1750-5836
The importance of carbon capture and storage in mitigating climate change has emerged from the results of techno-economic or integrated assessment modeling, in which scenarios of future energy systems are developed subject to constraints from economic growth and climate change targets. These models rarely include limits imposed by injectivity, ultimate amounts, or the geographic distribution of storage resources. However, they could if a sufficiently simple model were available. We develop a methodology for the fast assessment of the dynamic storage resource of a reservoir under different scenarios of well numbers and interwell distance. The approach combines the use of a single-well multiphase analytical solution and the superposition of pressure responses to evaluate the pressure buildup in a multiwell scenario. The injectivity is directly estimated by means of a nonlinear relationship between flow-rate and overpressure and by imposing a limiting overpressure, which is evaluated on the basis of the mechanical parameters for failure. The methodology is implemented within a tool, named CO2BLOCK, which can optimise site design for the numbers of wells and spacing between wells. Given its small computational expense, the methodology can be applied to a large number of sites within a region. We apply this to analyse the storage potential in the offshore of the UK. We estimate that 25–250 GtCO2 can be safely stored over an injection time interval of 30 years. We also demonstrate the use of the tool in evaluating tradeoffs between infrastructure costs and maximising injectivity at two specific sites in the offshore UK.
Andrews E, Muggeridge A, Garfi G, et al., 2021, Pore-Scale X-ray Imaging of Wetting Alteration and Oil Redistribution during Low-Salinity Flooding of Berea Sandstone, ENERGY & FUELS, Vol: 35, Pages: 1197-1207, ISSN: 0887-0624
Razak WNA, Kechut NI, Andrews E, et al., 2021, 3D Visualization of Film Flow During Three-Phase Displacement in Water-Wet Rocks via Microtomography Method
Spatial image resolution has limited previous attempts to characterize the thin film flow of oil sandwiched in-between gas and water in a three-phase fluid system This paper describes how a systematically designed displacement experiment can produce imagery to define the film flow process in a 3D pore space of water-wet sandstone rocks. We image multiphase flow at the pore scale through three displacement experiments conducted on water-wet outcrop rock with variable spreading tendencies. The experiment has been formulated to observe the relationship between fluid spreading, phase saturations, and pore-scale displacement mechanisms. We provide exhaustive evidence of the three-phase fluid configurations that serve as a proxy mechanism assisting the fluid displacement process in a three-phase system, which includes the oil sandwiches in-between water and gas, the flow of oil via clay fabrics, and the double-displacement process that generates oil and water film in 3D pore spaces. Further, we show evidence that the stable thin-oil film has enhanced the gas trapping mechanism in the water-wet rocks. We observed that the oil layer had covered the isolated and trapped gas blobs, enhancing their stability. As a result, the trapped gas in the positive and zero spreading systems is slightly higher than in the negative spreading system due to a stable oil film. We analyze the Euler characteristic of the individual fluid phases and the interface pair of the fluids during waterflooding, gas injection, and chase water flooding. The comparison of the Euler characteristic for the connected and disconnected fluid phases between three different spreading systems (i.e., positive, zero, and negative) shows that the oil layer's connectivity is highest in the positive spreading system and lowest in the negative spreading system. The oil layer in the positive spreading system is also thicker than in the negative spreading system.
Andrews E, Muggeridge A, Jones A, et al., 2021, Pore scale observations of wetting alteration during low salinity water flooding using x-ray micro-ct
This paper describes the first pore scale in-situ observations of wetting alteration on clays during tertiary low salinity flooding. Observations in the laboratory over a range of scales show that reducing the salinity of injected water can alter the wetting state of a rock, making it more water-wet. However, there remains a poor understanding of how this alteration impacts the distribution of fluids over the pore and pore network scale and how it leads to additional oil recovery. In this work, X-ray micro-CT scanning is used to image an unsteady state experiment of tertiary low salinity water flooding in a Berea sandstone core with an altered wettability due to exposure to crude oil. Oil was trapped heterogeneously, at a saturation of 0.62, after flooding with high salinity brine. Subsequent flooding with low salinity brine led to an oil production of three percentage points. To understand the mechanisms for this additional recovery, we characterise the wetting state of the sample using imagery of fluid-solid fractional wetting and fluid pore occupancy analysis. Pore occupancy analysis shows that there is a redistribution of oil from large pores to small pores during low salinity flooding. We observe a decrease in the solid surface area covered by the oil after low salinity flooding, consistent with a change to a less oil-wetting state. Pore by pore analysis of the mineral surface area covered by the oil shows that the wetting alteration during low salinity flooding is more significant on clays which likely control the behaviour. Whilst there was only three percentage points of additional recovery during low salinity flooding, the wetting alteration led to the redistribution of 22% of oil within the rock. The success of low salinity water flooding depends on a wetting alteration and oil mobilisation as well as a pore structure which can facilitate the production of the mobilised oil.
Ringrose PS, Furre A-K, Gilfillan SMV, et al., 2021, Storage of Carbon Dioxide in Saline Aquifers: Physicochemical Processes, Key Constraints, and Scale-Up Potential, ANNUAL REVIEW OF CHEMICAL AND BIOMOLECULAR ENGINEERING, VOL 12, 2021, Vol: 12, Pages: 471-494, ISSN: 1947-5438
Spurin C, Bultreys T, Rucker M, et al., 2020, Real-Time Imaging Reveals Distinct Pore-Scale Dynamics During Transient and Equilibrium Subsurface Multiphase Flow, WATER RESOURCES RESEARCH, Vol: 56, ISSN: 0043-1397
Jackson SJ, Krevor S, 2020, Small-Scale Capillary Heterogeneity Linked to Rapid Plume Migration During CO(2)Storage, GEOPHYSICAL RESEARCH LETTERS, Vol: 47, ISSN: 0094-8276
Franchini S, Krevor S, 2020, Cut, overlap and locate: a deep learning approach for the 3D localization of particles in astigmatic optical setups, EXPERIMENTS IN FLUIDS, Vol: 61, ISSN: 0723-4864
Jackson SJ, Lin Q, Krevor S, 2020, Representative Elementary Volumes, Hysteresis, and Heterogeneity in Multiphase Flow From the Pore to Continuum Scale, WATER RESOURCES RESEARCH, Vol: 56, ISSN: 0043-1397
Zahasky C, Krevor S, 2020, Global geologic carbon storage requirements of climate change mitigation scenarios, Energy and Environmental Science, Vol: 13, Pages: 1561-1567, ISSN: 1754-5692
Integrated assessment models have identified carbon capture and storage (CCS) as an important technology for limiting climate change. To achieve 2 °C climate targets, many scenarios require tens of gigatons of CO2 stored per year by mid-century. These scenarios are often unconstrained by growth rates, and uncertainty in global geologic storage assessments limits resource-based constraints. Here we show how logistic growth models, a common tool in resource assessment, provide a mathematical framework for stakeholders to monitor short-term CCS deployment progress and long-term resource requirements in the context of climate change mitigation targets. Growth rate analysis, constrained by historic commercial CO2 storage rates, indicates sufficient growth to achieve several of the 2100 storage targets identified in the assessment reports of the Intergovernmental Panel on Climate Change. A maximum global discovered storage capacity of approximately 2700 Gt is needed to meet the most aggressive targets, with this ceiling growing if CCS deployment is delayed.
Zahasky C, Jackson SJ, Lin Q, et al., 2020, Pore Network Model Predictions of Darcy-Scale Multiphase Flow Heterogeneity Validated by Experiments, WATER RESOURCES RESEARCH, Vol: 56, ISSN: 0043-1397
Kirby ME, Watson JS, Najorka J, et al., 2020, Experimental study of pH effect on uranium (UVI) particle formation and transport through quartz sand in alkaline 0.1 M sodium chloride solutions, Colloids and Surfaces A: Physicochemical and Engineering Aspects, Vol: 592, Pages: 1-11, ISSN: 0927-7757
A thorough understanding of the aqueous uranium VI (UVI) chemistry in alkaline, sodium containing solutions is imperative to address a wide range of critical challenges in environmental engineering, including nuclear waste management. The aim of the present study was to characterise experimentally in more detail the control of pH on the removal of UVI from aqueous alkaline solutions through particle formation and on subsequent transport through porous media. We conducted first static batch experiments in the pH range between 10.5 and 12.5 containing 10 ppm UVI in 0.1 M NaCl solutions and examined the particles formed using filtration, dynamic light scattering, transition electron microscopy and X-ray powder diffraction. We found that at pH 10.5 and 11.5, between 75 and 96 % of UVI was removed from the solutions as clarkeite and studtite over a period of 48 h, forming particles with hydrodynamic diameters of 640 ± 111 nm and 837 ± 142 nm, respectively and representing aggregates of 10′s nm sized crystals randomly orientated. At pH 12.5, the formation of particles >0.2 μm became insignificant and no UVI was removed from solution. The mobility of UVI in these solutions was further studied using column experiments through quartz sand. We found that at pH 10.5 and 11.5, UVI containing particles were immobilised near the column inlet, likely due physical immobilisation of the particles (particle straining). At pH 12.5, however, UVI quantitatively eluted from the columns in the filter fraction <0.2 μm. The findings of our study reinforce a strong control of solution pH on particle size and U removal in alkaline solutions and subsequently on mobility of U through quartz porous media.
Liyanage R, Russell A, Crawshaw JP, et al., 2020, Direct experimental observations of the impact of viscosity contrast on convective mixing in a three-dimensional porous medium, Physics of Fluids, Vol: 32, Pages: 1-10, ISSN: 1070-6631
Analog fluids have been widely used to mimic the convective mixing of carbon dioxide into brine in the study of geological carbon storage. Although these fluid systems had many characteristics of the real system, the viscosity contrast between the resident fluid and the invading front was significantly different and largely overlooked. We used x-ray computed tomography to image convective mixing in a three-dimensional porous medium formed of glass beads and compared two invading fluids that had a viscosity 3.5× and 16× that of the resident fluid. The macroscopic behavior such as the dissolution rate and onset time scaled well with the viscosity contrast. However, with a more viscous invading fluid, fundamentally different plume structures and final mixing state were observed due in large part to greater dispersion.
Garfi G, John CM, Lin Q, et al., 2020, Fluid Surface Coverage Showing the Controls of Rock Mineralogy on the Wetting State, GEOPHYSICAL RESEARCH LETTERS, Vol: 47, ISSN: 0094-8276
Rücker M, Bartels W-B, Bultreys T, et al., 2020, Workflow for upscaling wettability from the nano- to core-scales, International Symposium of the Society of Core Analysts
Rucker M, Bartels W-B, Garfi G, et al., 2020, Relationship between wetting and capillary pressure in a crude oil/brine/rock system: From nano-scale to core-scale, Journal of Colloid and Interface Science, Vol: 562, Pages: 159-169, ISSN: 0021-9797
HypothesisThe wetting behaviour is a key property of a porous medium that controls hydraulic conductivity in multiphase flow. While many porous materials, such as hydrocarbon reservoir rocks, are initially wetted by the aqueous phase, surface active components within the non-wetting phase can alter the wetting state of the solid. Close to the saturation endpoints wetting phase fluid films of nanometre thickness impact the wetting alteration process. The properties of these films depend on the chemical characteristics of the system. Here we demonstrate that surface texture can be equally important and introduce a novel workflow to characterize the wetting state of a porous medium.ExperimentsWe investigated the formation of fluid films along a rock surface imaged with atomic force microscopy using ζ-potential measurements and a computational model for drainage. The results were compared to spontaneous imbibition test to link sub-pore-scale and core-scale wetting characteristics of the rock.FindingsThe results show a dependency between surface coverage by oil, which controls the wetting alteration, and the macroscopic wetting response. The surface-area coverage is dependent on the capillary pressure applied during primary drainage. Close to the saturation endpoint, where the change in saturation was minor, the oil-solid contact changed more than 80%.
Krevor S, Blunt MJ, Trusler JPM, et al., 2020, Chapter 8: An introduction to subsurface CO<inf>2</inf> storage, RSC Energy and Environment Series, Pages: 238-295, ISBN: 9781788014700
The costs of carbon capture and storage are driven by the capture of CO2 from exhaust streams or the atmosphere. However, its role in climate change mitigation is underpinned by the potential of the vast capacity for storage in subsurface geologic formations. This storage potential is confined to sedimentary rocks, which have substantial porosity and high permeability in comparison to crystalline igneous and metamorphic rocks. These in turn occur in the sedimentary basins of the Earth's continents and near shore. However, the specific capacity for storage is not correlated simply to the existence of a basin. Consideration must also be made of reservoir permeability, caprock integrity, injectivity, fluid dynamics, and geomechanical properties of pressurisation and faulting. These are the topics addressed in this chapter. These processes and properties will combine in complex ways in a wide range of settings to govern the practicality of storing large volumes of CO2. There is clear potential for storage at the scale required to mitigate the worst impacts of global climate change, estimated to be in the order of 10 Gt CO2 per year by 2050. However, until at least dozens of commercial projects have been built in a range of geologic environments, the upper reaches of what can be achieved, and how quickly, will remain uncertain.
Imanovs E, Krevor S, Zadeh AM, 2020, CO2-EOR and Storage Potentials in Depleted Reservoirs in the NorwegianContinental Shelf (NCS)
Two global challenges are an increase in carbon dioxide (CO2) concentration in the atmosphere, causingglobal warming and an increase in energy demand (UNFCCC, 2015; EIA, 2018). Carbon Capture andStorage (CCS) is believed to be a major technology to considerably reduce CO2 emissions (Budinis et al.,2018). Applying this technology, the anthropogenic CO2 could be injected into depleted reservoirs andpermanently stored in the subsurface. However, standalone CCS projects may not be economically feasibledue to CO2 separation, transportation and storage costs (Pires et al., 2011). On the other hand, one of themost efficient Enhanced Oil Recovery (EOR) methods is carbon dioxide injection (Holm, 1959). Therefore,a combination of CO2-EOR and storage schemes could offer an opportunity to produce additional oil fromdepleted reservoirs and permanently store CO2 in the subsurface in an economically efficient manner. In this study, a depleted sandstone reservoir located in the Norwegian Continental Shelf (NCS) is used. Aninnovative development scenario is considered, involving two phases: CO2 storage phase at the beginningof the project followed by a CO2-EOR phase. The objective of this paper is to evaluate the effect of differentinjection methods, including continuous gas injection (CGI), continuous water injection (CWI), WaterAlternating Gas (WAG), Tapered WAG (TWAG), Simultaneous Water Above Gas Co-injection (SWGCO),Simultaneous Water and Gas Injection (SWGI) and cyclic SWGI on oil recovery and CO2 storage potentialin the depleted reservoir. A conceptual 2D high-resolution heterogeneous model with one pair injector-producer is used toinvestigate the mechanisms taking place in the reservoir during different injection methods. This knowledgeis applied in a field scale, realistic 3D compositional reservoir model of a depleted sandstone reservoir inthe NCS including ten oil producers and twenty water/gas injectors. The simulation results demonstrate that innovative development scen
Imanovs E, Krevor S, Zadeh AM, 2020, CO<inf>2</inf>-EOR and storage potentials in depleted reservoirs in the norwegian continental shelf NCS
Two global challenges are an increase in carbon dioxide (CO2) concentration in the atmosphere, causing global warming and an increase in energy demand (UNFCCC, 2015; EIA, 2018). Carbon Capture and Storage (CCS) is believed to be a major technology to considerably reduce CO2 emissions (Budinis et al., 2018). Applying this technology, the anthropogenic CO2 could be injected into depleted reservoirs and permanently stored in the subsurface. However, standalone CCS projects may not be economically feasible due to CO2 separation, transportation and storage costs (Pires et al., 2011). On the other hand, one of the most efficient Enhanced Oil Recovery (EOR) methods is carbon dioxide injection (Holm, 1959). Therefore, a combination of CO2-EOR and storage schemes could offer an opportunity to produce additional oil from depleted reservoirs and permanently store CO2 in the subsurface in an economically efficient manner. In this study, a depleted sandstone reservoir located in the Norwegian Continental Shelf (NCS) is used. An innovative development scenario is considered, involving two phases: CO2 storage phase at the beginning of the project followed by a CO2-EOR phase. The objective of this paper is to evaluate the effect of different injection methods, including continuous gas injection (CGI), continuous water injection (CWI), Water Alternating Gas (WAG), Tapered WAG (TWAG), Simultaneous Water Above Gas Co-injection (SWGCO), Simultaneous Water and Gas Injection (SWGI) and cyclic SWGI on oil recovery and CO2 storage potential in the depleted reservoir. A conceptual 2D high-resolution heterogeneous model with one pair injector-producer is used to investigate the mechanisms taking place in the reservoir during different injection methods. This knowledge is applied in a field scale, realistic 3D compositional reservoir model of a depleted sandstone reservoir in the NCS including ten oil producers and twenty water/gas injectors. The simulation results demonstrate that innovative
Garfi G, John CM, Berg S, et al., 2019, The sensitivity of estimates of multiphase fluid and solid properties of porous rocks to image processing, Transport in Porous Media, Vol: 131, Pages: 985-1005, ISSN: 0169-3913
X-ray microcomputed tomography (X-ray μ-CT) is a rapidly advancing technology that has been successfully employed to study flow phenomena in porous media. It offers an alternative approach to core scale experiments for the estimation of traditional petrophysical properties such as porosity and single-phase flow permeability. It can also be used to investigate properties that control multiphase flow such as rock wettability or mineral topology. In most applications, analyses are performed on segmented images obtained employing a specific processing pipeline on the greyscale images. The workflow leading to a segmented image is not straightforward or unique and, for most of the properties of interest, a ground truth is not available. For this reason, it is crucial to understand how image processing choices control properties estimation. In this work, we assess the sensitivity of porosity, permeability, specific surface area, in situ contact angle measurements, fluid–fluid interfacial curvature measurements and mineral composition to processing choices. We compare the results obtained upon the employment of two processing pipelines: non-local means filtering followed by watershed segmentation; segmentation by a manually trained random forest classifier. Single-phase flow permeability, in situ contact angle measurements and mineral-to-pore total surface area are the most sensitive properties, as a result of the sensitivity to processing of the phase boundary identification task. Porosity, interfacial fluid–fluid curvature and specific mineral descriptors are robust to processing. The sensitivity of the property estimates increases with the complexity of its definition and its relationship to boundary shape.
Niu B, Krevor S, 2019, The Impact of Mineral Dissolution on Drainage Relative Permeability and Residual Trapping in Two Carbonate Rocks, TRANSPORT IN POROUS MEDIA, Vol: 131, Pages: 363-380, ISSN: 0169-3913
Spurin C, Bultreys T, Bijeljic B, et al., 2019, Mechanisms controlling fluid breakup and reconnection during two-phase flow in porous media, Physical Review E, Vol: 100, ISSN: 2470-0045
The use of Darcy's law to describe steady-state multiphase flow in porous media has been justified by the assumption that the fluids flow in continuously connected pathways. However, a range of complex interface dynamics have been observed during macroscopically steady-state flow, including intermittent pathway flow where flow pathways periodically disconnect and reconnect. The physical mechanisms controlling this behavior have remained unclear, leading to uncertainty concerning the occurrence of the different flow regimes. We observe that the fraction of intermittent flow pathways is dependent on the capillary number and viscosity ratio. We propose a phase diagram within this parameter space to quantify the degree of intermittent flow.
Spurin C, Bultreys T, Bijeljic B, et al., 2019, Intermittent fluid connectivity during two-phase flow in a heterogeneous carbonate rock, Physical Review E, Vol: 100, ISSN: 2470-0045
Subsurface fluid flow is ubiquitous in nature, and understanding the interaction of multiple fluids as they flow within a porous medium is central to many geological, environmental, and industrial processes. It is assumed that the flow pathways of each phase are invariant when modeling subsurface flow using Darcy's law extended to multiphase flow, a condition that is assumed to be valid during steady-state flow. However, it has been observed that intermittent flow pathways exist at steady state even at the low capillary numbers typically encountered in the subsurface. Little is known about the pore structure controls or the impact of intermittency on continuum scale flow properties. Here we investigate the impact of intermittent pathways on the connectivity of the fluids for a carbonate rock. Using laboratory-based micro computed tomography imaging we observe that intermittent pathway flow occurs in intermediate-sized pores due to the competition between both flowing fluids. This competition moves to smaller pores when the flow rate of the nonwetting phase increases. Intermittency occurs in poorly connected pores or in regions where the nonwetting phase itself is poorly connected. Intermittent pathways lead to the interrupted transport of the fluids; this means they are important in determining continuum scale flow properties, such as relative permeability. The impact of intermittency on flow properties is significant because it occurs at key locations, whereby the nonwetting phase is otherwise disconnected.
De Simone S, Jackson SJ, Krevor S, 2019, The error in using superposition to estimate pressure during multi‐site subsurface CO 2 storage, Geophysical Research Letters, Vol: 46, Pages: 6525-6533, ISSN: 0094-8276
Analytic pressure estimates for multisite CO2 injection are typically performed through the superposition of single‐site injection models. This is theoretically invalid for multiphase flow because of its nonlinearity. We quantify the error associated with the application of superposition in scenarios with sites located in a rectangular grid geometry. We show that the use of superposition results in overestimates of the pressure buildup, because it neglects the presence of multiple CO2 plumes, which increase the reservoir fluid mobility. The adoption of a dimensionless time scaled to the geometric average between the advective and diffusive characteristic times allows us to define a general model for the maximum error, which may be used to evaluate the validity of using superposition, or to correct the pressure estimates when errors are significant. This procedure can be applied to any analytical solution and advances the extension of single‐well models to scenarios of multiple injection sites.
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