Assessing microbial risks is key to feasible hydrogen storage in geological formations. This work quantitatively analyses the impacts of bio-methanation on hydrogen storage performance. Fine-scale flow simulations, coupled with the bio-methanation reaction, are presented to analyse its impact on the storage performance. Based on the reported rates in literature, methanogenesis may slightly degrade the recovery performance of hydrogen but is considered minor compared with the issue of gas mixing. The impacts of methanogenesis on a time scale of months (330 days) becomes observable in the system configured here, when the methanation rate is above 1746 nano molality per hour. The assumed methanation rate is two times greater than the rate reported from the Olla filed. Validated scaling theory generalises findings for gravity-dominated scenarios. But viscous-dominated flows see complications from property variations due to pressure changes at high rates. This study provides definitions of "target properties" (e.g., acceptable methanogenesis rates) for screening hydrogen storage projects.

Summary Geological formations can provide cost-effective storage capacity at scale and therefore are increasingly considered for hydrogen (H2) storage. However, H2 may trigger the bio-methanation process when carbon dioxide (CO2) is used as cushion gas. This process may lead to H2 loss and the contamination of the back produced gas. The impact of the methanation process on the H2 recovery performance is analysed using a series of fine-scale numerical flow simulations. A gravity-dominated operational strategy is designed to mimic seasonal H2 supply-demand patterns. Although gravity can drive the segregation between H2 and CO2, permeability heterogeneities lead to flow dispersions and gas mixing. In turn, they provide the base condition (local mixing of H2 and CO2) for the subsequent methanogenesis to occur. In one scenario, approximately 30% of H2 has been converted to CH4 using a methanation rate from the literature. Compared with the case without methanogenesis, H2 recovery is reduced by 17% and 26% with reference to H2 purity levels of 98% and 90% in the case with methanogenesis considered. Water-breakthrough also occurs when the methanogenesis is activated. This is because of the decrease in the total gas volume and the newly formed water, as a result of the methanation reaction.

The central objective of this study is to improve our current understanding of the hydrodynamic processes arising when hydrogen (H2) is stored in subsurface porous media. In this work, we compare the use of two cushion gases, namely carbon dioxide (CO2) and methane (CH4), for H2storage ina synthetic aquifer. The impacts of viscous instability, gravity segregation, capillary trapping, and CO2 solubility in water on the recovery performance are investigated in detail.In the context of H2 storage, wefocus on both the amount and the purity of the H2that is back produced. A series of very fine-scale numerical simulationswas performed in 2D vertical systems using a fully compositional simulator. A simple three-stage operation strategy (cushion gas injection, H2 injection and H2 production) was designed to trigger the flow behaviour of interest. Based onscaling theory, we analysed the impacts of various mechanisms on the H2 recovery performance, from viscous dominated to gravity dominated flow regimes. Viscous instability and permeability heterogeneity may strongly degrade the purity of the back produced H2. No matter whichgas (CO2 or CH4) is selected as the cushion gas, the less viscous H2 infiltrates the cushion gas, meaning that the displacement does not proceed in a piston-like fashion. In the viscous-dominated scenario, H2 may even bypass the cushion gas of CO2, which subsequently leads to early breakthrough of the cushion gas and thus a dramatic reduction in H2 purity during back production. However, this effect does not arise in the case with CH4 as cushion gas. On the other hand, in the gravity-dominated case, the less dense H2 accumulates above the cushion gas and there is no flow infiltration or bypassing occurring in cases studied here. Therefore, the overall H2recovery performance is much better in the gravity-dominated regime than that in the viscous dominated regime. Finally, we demonstrate that it is important to include the solubility of CO2 when used as cushion gas in aquifer systems. This isbecause CO2 dissolution in water may significantly reduce its gas volume and lead to early water breakthrough during back production.

Renewable energy is becoming an integral part of our energy supply; however, seasonality and weather dependence are some of their major limitations. Therefore, grid integration with reliable storage systems is crucial. One promising energy storage technology is green hydrogen generation and storage. Some research has been ongoing into hydrogen storage in underground porous media, but it mostly lacks comprehensive dynamic modelling of the storage operation and the associated potential losses. In this work. a holistic hydrogen storage operation in a heterogenous depleted gas reservoir and its likely associated underground losses was modelled. Fluid model verification was performed to assess the suitability of a typical equation of state to represent hydrogen behavior at reservoir conditions. The study aimed to assess the feasibility of storing 15% of the renewably generated power in Malaysia for grid-scale equilibration purposes. A total of 12 storage cycles with potential diffusion and biochemical losses were simulated. The storage operation performed effectively in all the key performance indicators. 68.1% of the injected storage volume was recovered by the 12th cycle. It was observed that the purity of the produced hydrogen is influenced by reservoir heterogeneity. Lastly, it was found that storing 15% of Malaysian renewable energy in a depleted gas reservoir was technically feasible.

The central objective of this study is to improve the understanding of flow behaviour during hydrogen (H2) storage in subsurface porous media, with a cushion gas of carbon dioxide (CO2). In this study, we investigate the interactions between various factors driving the flow behaviour, including the underlying permeability heterogeneity, viscous instability, and the balance between the viscous and gravity forces. In particular, we study the impact of CO2 solubility in water on the level of H2 purity. This effect is demonstrated for the first time in the context of H-2 storage. We have performed a range of 2D vertical cross-sectional simulations at the decametre scale with a very fine cell size (0.1 m) to capture the flow behaviour in detail. This is done since it is at this scale that much of the mixing be-tween injected and native fluids occurs in physical porous media. It is found that CO2 solubility may have different (positive and negative) impacts on the H-2 recovery performance (i.e., on the purity of the produced H-2), depending on the flow regimes in the system. In the viscous dominated regime, the less viscous H-2 may infiltrate and bypass the cushion gas of CO2 during the period of H-2 injection. This leads to a quick and dramatic reduction in the H-2 purity when back producing H-2 due to the co-production of the previously bypassed CO2. Interestingly, the impurity levels in the H(2 )are much less severe in the case when CO2 solubility in water is considered. This is because the bypassed CO2 will redissolve into the water surrounding the bypassed zones, which greatly retards the movement of CO2 to-wards the producer. In the gravity dominated scenario, H-2 accumulates at the top of the model and displaces the underlying cushion gas in an almost piston-like fashion. Approximately 58% of H-2 can be recovered at a purity level above 98% (combustion requirements by ISO) in this gravity-dominated case. However, when CO2 solubility is considered, the H(2 )recovery performance is slightly degraded. This is because the dissolved CO2 is also gradually vaporised during H-2 injection, which leads to an expansion of mixing zone of CO(2 )and H-2. This in turn reduces the period of high H(2 )purity level (> 98%) duringback-production. (C) 2022 The Author(s). Published by Elsevier Ltd on behalf of Hydrogen Energy Publications LLC.

Subsurface hydrogen (H2) storage in geological formations is of growing interest for decarbonization. However, there is a knowledge gap in understanding the multiphase flow involved in this process, which can have a significant impact on the recovery performance of H2. Therefore, a full-compositional modeling study was conducted to analyze potential issues and to understand the fundamental hydrodynamic mechanisms of H2 storage. We performed a range of 2D vertical simulations at the decametre scale with a very fine cell size (0.1 m) to observe the detailed flow behaviour of H2 with carbon dioxide (CO2) as cushion gas in various flow regimes. Issues such as viscous instability, capillary bypassing, gas trapping and gravity segregation are analysed here. To generalize our calculations, we have validated and applied the scaling theory in the context of subsurface H2 storage. Since this study is focused on the hydrodynamic behaviour, three dimensionless groups, including aspect factor, capillary/viscous ratio and gravity/viscous ratio were identified to correlate recovery performance between various scales in a fixed heterogeneous system. It was found that H2 could infiltrate the cushion gas in the proximity of the injectors, meaning that CO2 is not displaced away from the injectors in a piston-like fashion. As a result, the purity of the back produced H2 is much degraded, particularly in a viscous-dominated scenario. On the other hand, the injected H2 mostly accumulates at the top forming a highly restricted mixing zone with CO2 in the gravity-dominated case. The recovery performance is therefore much improved in this case. Although the gas distribution can be significantly altered by capillary forces leading to bypassed zones, the recovery performance of H2 is hardly influenced. This is because the back-produced H2 recovery is not dependent on the sweep efficiency of the gas. H2 can be back produced following the same paths which were formed during injection. (c) 2021 Hydrogen Energy Publications LLC. Published by Elsevier Ltd. All rights reserved.

Carbon dioxide (CO2) enhanced oil recovery (EOR) has long been practiced in the US as an efficient mean for enhancing oil production. Many of the US CO2-EOR developments have been designed horizontally. This is because of a viscous-dominated CO2 flow regime that is prevalent in these developments driven by thin and low-permeability reservoirs. Reservoirs and fluid properties are different in the North Sea. Pays are usually thicker with better petrophysical properties. Lighter oils can also be found in North Sea reservoirs. This suggests that a dissimilar flow regime might prevail CO2 displacements in the North Sea developments, which could favor a dissimilar CO2-EOR process design. This study thus compares CO2 flow regimes between several North Sea and US reservoirs. We use scaling analysis to characterize and compare CO2 flow regimes between these two classes of reservoirs. Scaling analysis characterizes CO2 displacement in each reservoir system using three dimensionless numbers: gravity, effective aspect ratio, and mobility ratio. Displacement experiments conducted in stochastically generated permeability fields, under exactly matched magnitudes of the derived dimensionless numbers, reveal the prevailing CO2 flow regime in each reservoir system. Results of scaling analysis indicate that CO2 flooding in the North Sea reservoirs can be generally characterized with a larger gravity number, smaller effective aspect ratio, and smaller mobility ratio than the average US CO2 flooded reservoirs. Flow regime analysis indicates that unlike the majority of the US CO2 flooded reservoirs, CO2 flow regimes tend to be more gravity-dominated in the North Sea class of reservoirs. CO2 flow regimes in the North Sea systems are expected to suffer from a higher degree of instability because of thicker North Sea pays, which limit effective crossflow. Understanding the differences and characteristics of CO2 flow regimes in the North Sea prospects can help operators design their CO2 flooding more efficiently, which could increase the recovery factor (RF) as well as address CO2 storage requirements, a necessary consideration for CO2-EOR deployment in the North Sea.

Summary Subsurface hydrogen (H2) storage is a promising way to balance supply fluctuations of intermittent renewable energies (say, solar or wind). Issues including the heterogeneity of geological formations and two-phase flow mechanics may have a significant impact on the flow behaviour of H2 within the porous medium and may potentially degrade the subsequent recovery performance. Therefore, a full- compositional modelling study, using a very fine numerical grid to resolve the details of the flows, was conducted to analyze these risks and to understand the fundamental hydrodynamic mechanisms of H2 storage. We performed a range of 2D vertical simulations at a sector scale (10m×80m) to investigate the detailed flow behaviour of H2 with carbon dioxide (CO2) as cushion gas in heterogeneous systems. We observed that H2 could infiltrate the cushion gas in the proximity of the injectors, meaning that CO2 is not displaced away from the injectors in a piston-like fashion, as driven by the greater heterogeneity. As a result, under certain conditions, the purity of the back produced H2 may be much degraded. On the other hand, the overall storage performance of CO2 is generally good (>95%) and is much less affected by the permeability heterogeneity.

The security of CO2 storage requires all the injected CO2 to be contained entirely within the storage site. CO2 is not allowed to leave the subsurface system during and after cessation of injection. In stacked subsurface systems, the pore volume overlain or underlain by the CO2 storage site might be used by another subsurface user, potentially with a different philosophy. For example, it might be used by a hydrocarbon producer where the philosophy is to deplete the site and reduce its pressure for maximum hydrocarbon exploitation. If the two systems become hydraulically connected, CO2 may migrate from the storage site to the production site where it makes the security of storage more complex. In this study, we use numerical simulation to understand and address the characteristics of this phenomenon. We simulate CO2 injection and hydrocarbon production in two vertically separated stacked systems. The modelling study represents two separate formations, one overlying the other, but separated by an impermeable shale layer. CO2 injection is carried out in the one formation, whereas hydrocarbon is produced from the other formation. The two separated formations become connected via a well which penetrates through both formations and provides hydraulic communication between them. Different configurations of overlying and underlying CO2 storage site relative to the hydrocarbon production site have been investigated in this study. Both pre- and post-storage hydrocarbon production have also been included in the analysis. Results show that in all the investigated scenarios, leakage of CO2 is expected, though with different characteristics. CO2 always migrates to the overlying production site due to combination of gravity and sufficient pressure gradient. Interestingly a reverse migration of CO2 from the overlying storage to the underlying production site was also observed should a sufficient pressure difference between the two formation allows brine to migrate from the overlying CO2 storage site to the underlying production site. Such brine migration dissolves CO2 on its migration path and brings it to the production site. Results of this study illustrate the significance of correctly understanding this leakage phenomenon and including it in the overall long-term assessment of storage security in target storage sites.

Hydrogen stored on a large scale in porous rocks helps alleviate the main drawbacks of intermittent renewable energy generation and will play a significant role as a fuel substitute to limit global warming. This study discusses the injection, storage and production of hydrogen in an open saline aquifer anticline using industry standard reservoir engineering software, and investigates the role of cushion gas, one of the main cost uncertainties of hydrogen storage in porous media. The results show that one well can inject and reproduce enough hydrogen in a saline aquifer anticline to cover 25% of the annual hydrogen energy required to decarbonise the domestic heating of East Anglia (UK). Cushion gas plays an important role and its injection in saline aquifers is dominated by brine displacement and accompanied by high pressures. The required ratio of cushion gas to working gas depends strongly on geological parameters including reservoir depth, the shape of the trap, and reservoir permeability, which are investigated in this study. Generally, deeper reservoirs with high permeability are favoured. The study shows that the volume of cushion gas directly determines the working gas injection and production performance. It is concluded that a thorough investigation into the cushion gas requirement, taking into account cushion gas costs as well as the cost-benefit of cushion gas in place, should be an integral part of a hydrogen storage development plan in saline aquifers. (C) 2021 Hydrogen Energy Publications LLC. Published by Elsevier Ltd. All rights reserved.

This study seeks to improve numerical simulations of the key physics occurring in CO 2 enhanced oil recovery (CO 2 -EOR) processes, with a particular focus on the transition from immiscible to miscible displacements. In the previous work, we have investigated interactions between compositional effects and the underlying heterogeneities of the flow field in near-miscible floods (Wang et al. in Transp Porous Media 129(3):743–759, 2019a). In this current study, we have further analysed the effects of reduction in interfacial tension (IFT) on the flow behaviour, as motivated by the study on the film-flow mechanism previously presented by Sorbie and van Dijke (SPE improved oil recovery symposium, Society of Petroleum Engineers, 2010). We identify two clear mechanisms of oil recovery that may occur in near-miscible CO 2 (or other gas) injection processes, which we denote, M CE , as oil stripping or conventional compositional effects, and M IFT as lower IFT oil film-flow effects. The latter M IFT effects are described by an enhanced hydrocarbon relative permeability in the near-miscible three-phase relative permeabilities (3PRP). Various combinations between the M CE and M IFT mechanisms were tested by numerical simulations to evaluate the impact of each mechanism on the flow behaviour, i.e. their separate and joint effects on quantities such as the local oil displacement efficiency, phase flow vectors and the ultimate oil recovery. When acting in combination, the oil stripping and IFT effects can greatly improve the local displacement performance even when viscous fingering flow occurs. Viscous fingering is well known to lead to bypassed oil in the “non-preferential” flow paths between the main fingers. We show that the remaining oil in these non-preferential flow paths (i.e. bypassed oil) can be efficiently recovered by the combined M CE and M IFT mechanisms, but only with the application of water alternating gas (WAG). In contrast to oil stripping effects, the IFT effect is not dependent on continuous contact between oil and CO 2 . Instead, the remaining oil is mobilized by gas as the IFT is reduced and can be efficiently produced by subsequent water injection. This M IFT mechanism has much less impact in cases with continuous CO 2 injection compared to its efficiency in WAG. This is because during continuous injection, gas fingers are dominant in the preferential flow paths, and therefore the local displacement efficiency is very good, but only in these preferential routes. On the other hand, WAG is able to make full use of the IFT effects because of its relatively stable displacing front, which allows the M IFT mechanism to contribute. In this study, the effects of using different three-phase relative permeability methods were investigated and, as expected, different methods yielded different results. However, an important observation is that when IFT effects ( M IFT ) were included, there was much less difference in the final oil recovery using the different 3PRP models; our analysis shows why this is the case.

In any flooding process, the flow pattern determines the quality of the macroscopic sweep and expected recovery efficiency. The flow pattern also controls the choice of the flooding strategy. This study compares CO2 flow patterns between two major classes of reservoirs; first, the United States CO2 flooded reservoirs, considered as benchmark for CO2 application elsewhere, and second, the North Sea class of reservoirs considered as future target for CO2 flooding offshore. An inventory of reservoir data was first prepared by inspecting the literature. North Sea reservoirs are characterised with higher temperatures, higher pressures, thicker pays and higher permeabilities. Well spacing is also larger in the North Sea and these reservoirs are depleted faster. Using appropriate correlations, the in-situ CO2 and oil properties were inferred for each individual reservoir knowing its ambient reservoir conditions. Scaling analysis was used to characterise the CO2 displacing oil process in each reservoir by calculating a few key dimensionless numbers. Numerical simulation of CO2 displacing oil in stochastic permeability fields revealed the CO2 flow pattern in each individual reservoir. Although CO2 and oil densities are comparable in North Sea and United States classes of reservoirs, scaling analysis shows that "gravity numbers" for a CO2 displacing oil process are an order of magnitude larger offshore North Sea. This indicates a more gravity dominated CO2 flooding in the North Sea compared to United States reservoirs principally due to thicker pays and significantly higher permeabilities in this province but not due to larger CO2 and oil density contrast. The "mobility number" for a CO2-oil displacement process is also considerably lower (or better) in the North Sea due to lower North Sea oil viscosities. This indicates, in the absence of gravity, the viscous CO2 flooding is expected to be more stable in the North Sea. "Effective aspect ratios", illustrating the degree of cross flow are also lower in the North Sea mainly due to considerably thicker pay reservoirs in these systems. Visual comparison of displacement profiles in different stochastic permeability fields shows that, unlike the majority of United States CO2 flooded reservoirs where the displacement may be characterised with an unstable viscous dominated process, in the North Sea CO2 flow patterns vary mostly between gravity dominated and stable viscous displacements. Better understanding of the CO2 flow pattern can help in the selection of the appropriate CO2 flooding process e.g. selection between horizontal and gravity stable CO2 flooding or the decision to implement WAG instead of continuous CO2 injection for future provinces targeted for CO2-EOR like the North Sea. North Sea reservoirs thus may benefit from a different CO2 flood design than that observed historically in the United States since their CO2 flow patterns is fundamentally different.

CO2 Water-Alternating-Gas injection (CO2-WAG) is still a challenging task to simulate and predict accurately, due to the complex interaction of CO2/oil phase behaviour, 3-phase flow and the heterogeneity of the porous medium. In this paper, we focus specifically on the regime of viscous fingering flow in CO2-WAG in heterogeneous systems because of its importance in elucidating this complex interaction. This work presents a detailed simulation study of both immiscible and near-miscible CO2-WAG and continuous CO2 displacements with unfavourable mobility ratios for 1D and 2D systems. 2D heterogeneous permeability fields were generated as Correlated Random Fields (CRF) with specified degrees of heterogeneity (permeability range, described by the Dykstra-Parsons coefficients, V-DP) and structures (defined through the dimensionless correlation range, R-L = lambda/L). Our central aim is to improve the modelling of CO2 displacement in the transition from immiscible to miscible flows in CO2-WAG processes. To do so, two key physical mechanisms that occur during near-Miscible WAG (nMWAG) processes have been studied in detail, namely compositional effects (denoted as Mechanism 1, MCE) and low-interfacial-tension (IFT) film flow effects (denoted as Mechanism 2, M-IFT). The low IFT effects in M-IFT manifest themselves in an increased mobility of oil phase due to enhanced film formation and flow processes. This latter mechanism (M-IFT) is modelled as an increased oil relative permeability using different well-known models (Bette and Coats) parameterized by the gas/oil IFT (sigma(go)), calculated in the simulation from the compositional PVT model via a built-in correlation (the McLeod-Sugden equation, in this case). A range of various combinations of oil-stripping effects (MCE) and IFT effects (M-IFT) has been tested to evaluate the potential impact of each mechanism on the flow behaviour such as the local displacement efficiency and the ultimate oil recovery. Oil bypassed by viscous fingering/local heterogeneity, can be efficiently recovered by WAG in the cases where both M-CE and M-IFT are taken into account (as opposed to either mechanism being considered alone). We also show that the way these two distinct but related mechanisms (M-CE and M-IFT) operate in near miscible conditions cannot be observed in (i) a simple 1D system such as a slim tube experiment, or (ii) in a heterogeneous system under continuous CO2 injection. Using tracer analysis in our simulations, we demonstrate that a major recovery mechanism in near-miscible WAG displacement is viscous crossflow between non-preferential (bypassed) flowpaths and preferential flow-paths (i.e. between the viscous fingers). Due to the significance of IFT effects (the M-IFT mechanism), we also present comparative results from two of the IFT-dependent relative permeability models (Bette and Coats) showing the impact of each model on the simulation of the near-miscible WAG flow behaviour.

This study shows the application of scaling analysis in the context of CO2 storage. Scaling analysis has been used in many flooding processes to characterize the displacement in such systems. The study aims to derive the key dimensionless numbers pertinent to CO2 storage in saline aquifers. This set of dimensionless numbers may be used to characterize important storage characteristics such as injectivity, plume migration and mobility, the pressure response and the ultimate storage capacity in potential saline aquifers. CO2 storage in a two-dimensional cross-sectional model representing part of a saline aquifer was considered. The model is assumed to be full of brine when CO2 is injected into it. The fundamental equations for the material conservation of each phase, and the transport equations were formulated and derived. All fluids and the formation were considered compressible. These fundamental equations were then converted into the dimensionless domain by applying inspectional analysis to allow the identification of the key dimensionless numbers characterizing the storage process. The storage process in such a system can be described by twelve dimensionless numbers, each of which characterize a different aspect of the storage process. Some numbers are similar to those already observed in the context of petroleum processes while a few of them are solely relevant to the storage process. Importantly, the pressure response and the injectivity consideration of the storage process can be described by the injectivity number and the ratio of compressibilities. A numerical model was constructed to test the sensitivity of the storage process with respect to these dimensionless numbers. Results show the same set of dimensionless numbers can describe storage performance in different systems as long as the processes in all of them are described by identical dimensionless numbers. The lateral migration of the plume and its onset arrival at the storage boundary can be described by the combination of the magnitudes of gravity numbers, effective aspect ratio number, mobility ratio between CO2 and brine and finally the ratio of CO2 and formation compressibilities relative to brine compressibility. For a confined storage system, the storage efficiency was correlated with the magnitudes of the influencing dimensionless numbers. The derived dimensionless numbers may be used as a set of characterization parameters for describing the storage process in potential storage candidates. They can also be used effectively as a preliminary screening criteria for the purpose of site selection amongst potential storage candidates.

CO2 Water-Alternating-Gas injection (CO2-WAG) under near-miscible conditions entails interactions between multi-physical processes at different length scales, which is not fully understood mechanistically. This research contributes to our fundamental understanding of the fluid behaviour driven by major physical mechanisms including compositional effects (denoted as MCE), interfacial tension effects (denoted as MIFT), capillary forces and gas trapping. The total system size was of order 1 large-scale “grid block” (~50m), which allowed us to capture the multi-scale behaviour from the cm to the 50m scale. Using fine-scale 2D areal simulations, this study identifies the separate and combined contributions of mechanisms to the recovery of bypassed oil induced by viscous fingering. Mechanisms MCE and MIFT work in tandem to improve the oil recovery through stripping oil components and enhancing viscous crossflow. However, the magnitude of such benefits is highly dependent on the ancillary effects of gas trapping and the capillary forces (system wettability). In a water-wet system, gas trapping modestly constricts actions of MIFT whereas capillary forces significantly degrade the sweep efficiency and lead to multiple isolated oil zones. We also found that the negative impacts of capillary pressure on the oil recovery can be much reduced if CO2 is injected prior to any water injection. On the other hand, oil-wet capillary forces hardly decrease the ultimate oil recovery in our cases. For the first time, flow trajectories, phase occupancies, oil compositions and interfacial tension as a function of permeability are explicitly depicted for each WAG cycle, which effectively unpicks the complexity of near-miscible CO2-WAG process.

Summary CO2 Water-Alternating-Gas injection (CO2-WAG) under near-miscible conditions is a multifaceted process due to the complex interaction of thermodynamic phase behaviour, multi-phase flow behaviour and the heterogeneity of the porous medium. The central objective of this study is to improve the fundamental understanding of fluid behaviour in the process of near-miscible CO2-WAG. This work presents a detailed simulation study of CO2-WAG displacements with unfavourable mobility ratios in a 2D areal heterogeneous system to trigger the fingering flow regime. In our previous work ( Wang et al., 2019 a; 2019b ; 2020 ), we have successfully developed a new mechanistic synthesis of near-miscible WAG, incorporating compositional effects (the MCE mechanism) and interfacial tension effects (the MIFT mechanism). Here, we extend our study to include additional key multiphase flow mechanisms, such as gas trapping and capillarity, to reflect better the flow physics in a 3-phase system. We identify that the effect of gas trapping reduces the oil recovery due to the degraded displacement performance in the “non-preferential” flow routes (areas between gas fingers). This is because the trapping mechanism greatly hampers the MIFT mechanism acting during the secondary water injection cycle. The viscous crossflow between the non-preferential routes and preferential routes (gas fingers) is restricted, which leads to a lowered sweep efficiency. On the other hand, the effect of the capillary force is more complex. In a water-wet system, the oil production increases at the early stage of displacement but approaches the plateau more quickly. In this case, capillary pressure creates entry barriers for gas flowing into low-permeability zones, which gives rise to more severe gas fingers and a larger amount of bypassed oil. The oil recovery drops by over 7% compared to the zero capillary pressure case. For the oil-wet system with capillarity, the production life is much extended by the capillary forces compared to the water-wet case. Although the production rate is reduced at the early stage of the displacement, the oil-wet capillary pressure function enables gas to imbibe into low-permeability zones (under near-miscible conditions), which mitigates the effect of the dominant gas fingers. The improved sweep efficiency maximizes the benefits of the combined MCE and MIFT mechanisms, particularly at the late stage of the displacement. The oil recovery in the oil-wet case can be almost as good as in the base case provided the final water cycle is long enough.

This study investigates the interaction of compositional effects with the flow behaviour during near-miscible (and immiscible) CO 2 –oil displacements in heterogeneous systems. A series of numerical simulations modelling 1D slim-tube and 2D areal systems were simulated using a fully compositional simulator. A number of grid resolutions for a slim-tube model were simulated to choose the proper level of numerical dispersion to mimic the actual physical dispersion. The corresponding 2D cases are based on a small heterogeneous sector model of dimensions 50 m × 10 m, in order that the fine-scale displacement physics can be modelled accurately. We investigated various flow regimes ranging from viscous fingering to channelling displacements within heterogeneous random correlated fields. We found that the reduced recovery is the result of a combination of differences in sweep efficiency associated with the viscous fingering and possible differences in local mixing that affect composition path. At the same time, the unstable phase flow determined by the underlying heterogeneity slows the flow in the unswept area and leads to unequal displacement performance between preferential and non-preferential routes. Specifically, lighter components have moved preferentially in high gas saturation zones, and leaving the heavier components behind in slower flow zones. In the case of channelling flow, compositional effects were less important since the permeability channel dominated the displacement. Both the ultimate oil recovery and component recovery are significantly and about equally reduced, when the underlying heterogeneity is of dominant influence. To summarise, compositional effects can have a very significant impact on the prediction of near-miscible CO 2 EOR projects. Issues such as front stability, local displacement efficiency and formation of fingering/channelling during CO 2 near-miscible displacement can lead to behaviour that is significantly different from immiscible flooding in these systems. The process of mass transfer between CO 2 and oil can be hampered to a certain degree by unstable flow depending on the level of heterogeneity. This leads to a further reduction in component recovery, particularly of the heavier components. The complete dataset and results of this study are available online as a model case example for compositional flows in heterogeneous systems (Wang et al. in "The analysis of compositional effects on global flow regimes in CO 2 near-miscible displacements in heterogeneous systems” dataset for paper SPE-190273, 2018 . https://doi.org/10.17861/fc1c90bb-9d3f-4a6c-9170-7b7fe10ec7b9 ).

Summary Carbonate reservoir rocks exhibit property alterations due to depositional texture, diagenesis and fracturing. Superposition of these processes results in a heterogeneous rock and a complex pore system. The workflow proposed addresses the independent ternary interrelationships between porosity, permeability and irreducible water saturation in carbonate rocks. A novel Ternary Rock Typing (TRT) application focuses on these parameters in the shape of a 3D ellipsoid. The change of rock fabric, diagenesis and fracturing changes the ellipsoid characteristics. The complex interaction of rock, pore and fluid affect the location, shape, orientation and relative position of the three-parameter ellipsoid. The three measurements are extracted from wireline-logs, routine and special core analysis. The TRT can be used as a solely data driven or as a guided “sedimentologically” data driven approach. Saturation-height modelling becomes an integral part of the quality control of the TRT application. This paper tests TRT and eight other standard rock-typing methods by quantifying the hydrodynamic observations with respect to cumulative oil produced, water cut and oil production rate. The test data is derived from a Miocene age of restricted lagoonal environment applying two strategies: the first is an active bottom water drive and the second is using one injector and one producer.