Mixed-wet Systems Research Articles

Pore-scale simulation of low-salinity waterflooding in mixed-wet systems: effect of corner flow, surface heterogeneity and kinetics of wettability alteration

The initial wettability state of the candidate oil reservoirs for low-salinity waterflooding (LSWF) is commonly characterized as mixed-wet. In mixed-wet systems, both the two-phase flow dynamics and the salt transport are significantly influenced by the corner flow of the wetting phase. Thus this study aims at comprehensive evaluation of LSWF efficiency by capturing the effect of corner flow and non-uniform wettability distribution. In this regard, direct numerical simulations under capillary-dominated flow regime were performed using the OpenFOAM Computational Fluid Dynamics toolbox. The results indicate that corner flow results in the transport of low-salinity water ahead of the primary fluid front and triggers a transition in the flow regime from a piston-like to multi-directional displacement. This then makes a substantial difference of 22% in the ultimate oil recovery factors between the 2D and quasi-3D models. Furthermore, the interplay of solute transport through corners and wettability alteration kinetics can lead to a new oil trapping mechanism, not reported in the literature, that diminishes LSWF efficiency. While the findings of this study elucidate that LSWF does exhibit improved oil recovery compared to high-salinity waterflooding, the complicating phenomena in mixed-wet systems can significantly affect the efficiency of this method and make it less successful.

Characterization of the effects of wettability and pore pressure on the interfacial behavior of CO2 interacting with oil-water two-phase on pore walls

To date, research studies on film-like residual oil have mainly focused on reservoirs in the late stage of water flooding development. However, there have been relatively few studies on film-like residual oil on pore walls after gas flooding. In this study, a molecular dynamics simulation method was used to investigate the behavior characteristics of fluid-fluid and fluid-solid interfaces and the exploitation potential of film-like remaining oil in water-wet, mixed-wet and oil-wet systems under different pore pressures after CO2 flooding. The results indicated that in the oil-in-water system, the cohesive energy density (CED) of the water films was much greater than that of the CO2 and decane components, and the CED of water films in the water-wet systems was slightly greater than the CED of water films in the mixed-wet systems. Regardless of the water-wet or mixed-wet systems, Einter(CO2−decane) was the strongest between the components. Therefore, CO2 molecules could easily enter the oil films and divide the oil phase into clusters of different sizes. The interfacial tension at the CO2 + decane/H2O and H2O/SiO2 interfaces in both the water-wet and mixed-wet systems decreased with increasing pressure. Under the same pressure, the degree of decrease in interfacial tension at the CO2 + decane/H2O interface in the mixed-wet systems was smaller than that in the water-wet systems. The degree of decrease in interfacial tension at the H2O/SiO2 interfaces in the mixed-wet systems was generally greater than that in the water-wet systems. In the water-in-oil system, because the water films isolated the oil films from the CO2 molecules, the interaction energy between the CO2 molecules and oil phase was weak, so the oil films remained on the quartz surfaces. Due to the existence of the hydrogen bond network inside the water phase, the morphological changes in water films were also small when the CO2 molecules interacted with the water phase. At the CO2/H2O interfaces, under the same pressure, the resistance of CO2 molecules to pass through the water films in the oil-wet systems was greater than that in the mixed-wet systems, and the CO2 molecules in the mixed-wet systems were more likely to enter into the water films. The interfacial tension reduction at the interfaces in the mixed-wet systems was smaller than that in the oil-wet systems. At the H2O/decane interfaces, the power of CO2 molecules breaking through the oil-water interfaces and entering into the oil phase in both the mixed-wet and oil-wet systems was basically equal under the same pressure. The interfacial tension reduction at the interfaces in the mixed-wet systems was almost equal to that of the oil-wet systems. At the decane/SiO2 interfaces, the CED of the oil films in the oil-wet systems was greater than that in the oil-wet systems under the same pressures, and the Einter(CO2−SiO2) in the mixed-wet systems was greater than the Einter(CO2−SiO2) in the oil-wet systems, indicating that CO2 molecules were more easily adsorbed on the quartz surfaces in the mixed-wet systems, and the interfacial tension reduction at the interfaces in the mixed-wet systems was greater than that of the oil-wet systems. The interfacial tension at the CO2/H2O, H2O/decane and decane/SiO2 interfaces in both the mixed-wet and oil-wet systems decreased with increasing pressure. The research results provide a reference for understanding the fluid-fluid and fluid-solid interface behaviors and the exploitation potential of film-like residual oil during CO2 gas flooding.

Pore-scale modeling of two-phase flow: A comparison of the generalized network model to direct numerical simulation.

Despite recent advances in pore-scale modeling of two-phase flow through porous media, the relative strengths and limitations of various modeling approaches have been largely unexplored. In this work, two-phase flow simulations from the generalized network model (GNM) [Phys. Rev. E 96, 013312 (2017)2470-004510.1103/PhysRevE.96.013312; Phys. Rev. E 97, 023308 (2018)2470-004510.1103/PhysRevE.97.023308] are compared with a recently developed lattice-Boltzmann model (LBM) [Adv. Water Resour. 116, 56 (2018)0309-170810.1016/j.advwatres.2018.03.014; J. Colloid Interface Sci. 576, 486 (2020)0021-979710.1016/j.jcis.2020.03.074] for drainage and waterflooding in two samples-a synthetic beadpack and a micro-CT imaged Bentheimer sandstone-under water-wet, mixed-wet, and oil-wet conditions. Macroscopic capillary pressure analysis reveals good agreement between the two models, and with experiments, at intermediate saturations but shows large discrepancy at the end-points. At a resolution of 10 grid blocks per average throat, the LBM is unable to capture the effect of layer flow which manifests as abnormally large initial water and residual oil saturations. Critically, pore-by-pore analysis shows that the absence of layer flow limits displacement to invasion-percolation in mixed-wet systems. The GNM is able to capture the effect of layers, and exhibits predictions closer to experimental observations in water and mixed-wet Bentheimer sandstones. Overall, a workflow for the comparison of pore-network models with direct numerical simulation of multiphase flow is presented. The GNM is shown to be an attractive option for cost and time-effective predictions of two-phase flow, and the importance of small-scale flow features in the accurate representation of pore-scale physics is highlighted.

Insights from Boltzmann transformation in solving 1D counter-current spontaneous imbibition at early and late time

Counter-current 1D spontaneous imbibition in scaled form is investigated using Boltzmann transform before and after water meets the closed boundary (early and late time). At early time the system is self-similar and only depends on position divided by square root of time. At late time it also depends on the interaction with the no-flow boundary and hence a second variable, which is set as the square root of time. Diffusion coefficients shifted to high saturations result in early time spatial saturation profiles with shorter front distance, higher average saturation within the imbibition profile and larger imbibed amount. Strongly water-wet systems have zero oil mobility at the inlet, while mixed-wet systems have finite non-zero mobility. The imbibition rate is proportional to inlet diffusion coefficient, inlet saturation gradient (regarding position divided by square root of time) and inverse square root of time. Accordingly, the saturation gradient is infinite and finite for strongly water-wet and mixed-wet systems. At early time, the profile does not change, thus recovery is proportional to square root of time. When the front meets the no-flow boundary (critical time), the saturation profile deviates from the early time profile first at the no-flow boundary, then towards the inlet. When the inlet gradient changes, imbibition rate declines faster than inverse square root of time. The interaction at the inlet and not the closed boundary, thus determines when recovery stops being proportional to square root of time and explains why such proportionality after critical time is reported. The findings were confirmed by matching experimental data. Cited as: Andersen, P. Ø. Insights from Boltzmann transformation in solving 1D counter-current spontaneous imbibition at early and late time. Advances in Geo-Energy Research, 2023, 7(3): 164-175. https://doi.org/10.46690/ager.2023.03.03

Surfactant and surfactant-polymer effects on wettability and crude oil liberation in carbonates

Surfactants and polymers are used in enhanced oil recovery (EOR) to reduce interfacial tension and increase the viscosity of displacing fluid, respectively. For oil-wet to mixed-wet systems, especially carbonates, which tend to be heavily fractured, wettability becomes a key parameter that strongly affects oil recovery. Therefore, studying the impact of surfactant and surfactant-polymer chemicals on carbonate wettability is important to understand the underlying mechanisms responsible for incremental oil recovery in surfactant-polymer flooding. In the present study, liberation kinetics of crude oil from carbonate surfaces were investigated by using a liberation cell at both ambient and elevated temperatures (70 °C). The liberation cell is equipped with an optical microscope for monitoring oil liberation. In addition, a custom-designed integrated thin film drainage apparatus (ITFDA) was used to measure adhesion forces between carbonate substrates and crude oil droplets. The chemical solutions were prepared in a representative high salinity brine. Two types of surfactants: a nonionic and an amphoteric were used and a sulfonated polyacrylamide polymer was selected. The chemical solutions were prepared at dilute concentrations of 1000 mg/L and 500 mg/L for the surfactant and polymer, respectively. Besides the main experimental data, i.e., adhesion forces and liberation kinetics, interfacial tensions and zeta potentials were also measured for different solutions. In the zeta potential tests, carbonate particle suspensions in brine, surfactant, polymer and surfactant-polymer solutions were used. Oil liberation from carbonate surface is the lowest with brine and the polymer increased the degree of oil liberation. The amphoteric surfactant showed better efficiency to liberate more crude oil from carbonate surface over the nonionic surfactant. Polymer and surfactant addition to brine resulted in an oil liberation degree that is much higher than those obtained by each of the chemicals when applied individually. For solutions containing brine, polymer, surfactant, and surfactant-polymer, oil liberation degree increased at elevated temperature. Adhesion forces were very consistent with the observed oil liberation results. Adhesion force was strongest in brine, and both the polymer and surfactants further lowered the adhesion force. Accordingly, the lower adhesion force between carbonate and crude oil in aqueous solutions containing surfactant and polymer contributed to the increased oil liberation. The higher oil liberation degree obtained with the amphoteric surfactant can be explained by its ability to lower oil/water interfacial tension by two to three orders of magnitude. In addition, the surface charges of carbonate particles were found to be increasingly negative in aqueous solutions containing surfactant and polymer, thereby contributing to enhanced wettability alteration in crude oil-brine-carbonate systems. These microscale results indicate that trapped-oil mobilization in carbonates is governed by both wettability and capillarity; in other words, wettability alteration as well as reduction in oil/water interfacial tension would lead to increased oil liberation. This experimental study has characterized, for the first time, surfactant, and surfactant-polymer effects on wettability and crude oil release from carbonate surface at microscale through adhesion force and dynamic oil liberation measurements. Such enhanced understanding obtained on the microscale interactions of surfactant, and surfactant-polymer chemicals at carbonate/brine/oil interfaces can provide some guidance on how to optimize EOR formulations for carbonate reservoirs. • Higher negative surface charge for carbonate particles in surfactant and surfactant-polymer solutions. • Two to three orders of magnitude reduction in interfacial tension with amphoteric surfactant. • Lowest adhesion forces for crude oil on carbonate surface in surfactant, and surfactant-polymer solutions. • Better efficacy of amphoteric surfactant over non-ionic surfactant to liberate crude oil from carbonate surface. • Trapped-oil mobilization in carbonates is governed by both wettability and capillarity.

Pore-Scale Characterization and PNM Simulations of Multiphase Flow in Carbonate Rocks

This paper deals with pore-scale two-phase flow simulations in carbonate rock using the pore network method (PNM). This method was used to determine the rock and flow properties of three different rock samples, such as porosity, capillary pressure, absolute permeabilities, and oil–water relative permeabilities. The pore network method was further used to determine the properties of rock matrices, such as pore size distribution, topological structure, aspect ratio, pore throat shape factor, connected porosity, total porosity, and absolute permeability. The predicted simulation for the network-connected porosity, total porosity, and absolute permeability agree well with those measured experimentally when the image resolution is appropriate to resolve the relevant pore and throat sizes. This paper also explores the effect of the wettability and fraction of oil-wet pores on relative permeabilities, both in uniform and mixed wet systems.

Assessment of two-phase relative permeability hysteresis models for oil/water, gas/water and gas/oil systems in mixed-wet porous media

Accurate determination of relative permeability curves and their hysteresis is vital for reliable prediction of the performance of oil and gas reservoirs under enhanced recovery processes. Two out of the three available approaches to simulate three-phase relative permeability hysteresis are based on two-phase hysteresis. A few options (e.g., Carlson, Killough and Jargon models) are available in commercial reservoir simulators to account for hysteresis in relative permeability curves under two-phase flow. These models are based on the assumptions of water-wet state of the rocks, while most of the reservoir rocks are mixed-wet. As a result the aim of the present work is to evaluate the performance of these hysteresis models for mixed-wet systems. In addition to the above models, more recent ones such as Beattie et al., Kjosavik et al., Spiteri et al. are also evaluated by coupling an in-house MATLAB code with the Eclipse simulator. The assessments of models are performed by comparing their predictions with those of previously reported comprehensive set of experimentally measured relative permeabilities for different two-phase systems. All possible two phase fluid/fluid systems i.e. oil/water, gas/water and gas/oil are considered. The interfacial tension in the case of oil/gas system is extra low (i.e. 0.04 mN.m−1) and it represents near-miscible condition. It is concluded that hysteresis models developed by Killough and Carlson are unable to accurately predict hysteresis effect on relative permeability in oil/gas system under extra low IFT and mixed-wettability. However, either of Killough and Carlson models could provide satisfactory results in gas/water and oil/water systems, respectively. Beattie et al. model that is not used in Eclipse gave a better fit to experimental data in oil/gas system, but it couldn't provide a suitable fit with experimental data in the cases of gas/water and oil/water systems. For different fluids systems, Kjosavik et al. model results were approximately close to the Killough model during the imbibition process and Beattie et al. during the drainage process. Even the results of the best models in each category of the two phase systems are not very satisfactorily. This study highlights the lack of a versatile hysteresis model to capture the hysteresis effect in all possible two phase systems for the mixed-wettability. As a result it is vital that modified or even novel hysteresis models in the case of mixed-wet system be developed.

Large-scale Invasion Percolation with Trapping for Upscaling Capillary-Controlled Darcy-scale Flow

We apply steady-state capillary-controlled upscaling in heterogeneous environments. A phase may fail to form a connected path across a given domain at capillary equilibrium. Moreover, even if a continuous saturation path exists, some regions of the domain may produce disconnected clusters that do not contribute to the overall connectivity of the system. In such cases, conventional upscaling processes might not be accurate since identification and removal of these isolated clusters are extremely important to the global connectivity of the system and the stability of the numerical solvers. In this study, we address the impact of percolation during capillary-controlled displacements in heterogeneous porous media and present a comprehensive investigation using random absolute permeability fields, for water-wet, oil-wet and mixed-wet systems, where J-function scaling is used to relate capillary pressure, porosity and absolute permeabilities in each grid cell. Important information is revealed about the average connectivity of the phases and trapping at the Darcy scale due to capillary forces. We show that in oil-wet and mixed-wet media, large-scale trapping of oil controlled by variations in local capillary pressure may be more significant than the local trapping, controlled by pore-scale displacement.

Relative permeabilities hysteresis for oil/water, gas/water and gas/oil systems in mixed-wet rocks

Accurate determination of relative permeability (kr) curves and their hysteresis is needed for reliable prediction of the performance of oil and gas reservoirs. A few options (e.g., Carlson, Killough and Jargon models) are available in commercial reservoir simulators to account for hysteresis in kr curves under two-phase flow. Two-phase kr curves are also needed for estimating kr hysteresis under three-phase flow during water-alternating-gas (WAG) injection. Although, most oil reservoirs are mixed-wet, the existing hysteresis predictive approaches have been developed based on water-wet conditions. Experimentally measured data are needed to assess the performance of these methodologies under more realistic reservoir conditions e.g. low gas-oil IFT and mixed-wet systems.This paper includes two parts. In the first part we review the most valuable works in the literature regarding the effect of hysteresis on two-phase relative permeabilities in different wettability conditions. As will be highlighted most of these data are generated on water-wet or slightly water-wet condition which are most likely not representative of the oil reservoirs. Even the generated two-phase relative permeabilities on mixed-wet and oil-wet conditions are not fully developed for the full hysteresis cycle and/or not for the all three possible systems (oil/water, gas/oil and gas/water) in one place. It is recently recommended by some of the valuable theoretical works in the literature that to enhance the predictions of three-phase hysteresis models, hysteresis for all possible two-phase systems shall be considered in the provided equations. As a result in the second part of this paper, we summarize comprehensive set of experimentally measured relative permeabilities for the two-phase systems of oil/water, gas/water and gas/oil. This set of data can be used with new three-phase hysteresis models such as that presented by Hustad and Browning (2010) to enhance the prediction of the WAG processes in non-water-wet systems.Experiments were performed in 65mD sandstone with mixed-wettability.For the gas/water system, the first set of fluid displacements began by water injection (imbibition: I) in the core saturated with gas and immobile water. This was followed by a period of gas injection (Drainage: D) which was followed by alternating periods of water and gas injections (IDIDI). In the second series, the core was initially 100% saturated with water and the experiment started with gas injection (D) followed by successive imbibition and drainage periods (DIDIDI). Similar sets of displacement experiments were performed for oil/water and gas/oil systems. The gas/oil system in our experiments represents extra low-IFT (near-miscible) system with an IFT value of 0.04 mN.m−1. The measured pressure drop and fluid production data obtained during the experiments were then history matched to estimate kr values for each imbibition and drainage period for each pair of fluids.In the oil/water system (DIDID injection sequence), krw shows cycle hysteresis which is in contrast to the common observations made in water-wet systems in which krw does not show hysteresis. In addition to krw, kro also shows significant hysteresis for the 1st imbibition period compared to the 1st drainage period but after the 1st imbibition period the kro hysteresis was not significant. In the gas/water system (IDIDI), both krg and krw decreased as the alternation between imbibition and drainage continued. The results show significant differences in the kr hysteretic behaviour in gas/water and oil/water systems. We demonstrate that the approach used in some of the three-phase simulations reported in literature, where the oil/water kr curves are used instead of gas/water kr curves (which are not normally measured) is not valid for mixed-wet systems and can lead to significant errors in prediction by reservoir simulators. Irreversible hysteresis loops were observed in our experiments even for the gas/oil system (in spite of the ultra-low gas/oil IFT) whereby krg values during each drainage period lied above the krg of the preceding imbibition. Drainage kro curves were significantly lower than their preceding imbibition kro. The observed kro cycle hysteresis diminished after the 2nd or 3rd injection cycle.The results suggest that in mixed-wet systems it is necessary to consider irreversible hysteresis loops for all phases, and hysteresis behaviour of different systems (oil/gas, water/gas and water/oil) can be different. This behaviour is not predictable by the formulations such as Land, Carlson and Killough models which are currently exist in commercial reservoir simulators.

Experimental investigation of the coupling impacts of new gaseous phase formation and wettability alteration on improved oil recovery by CWI

It has been shown that carbonated (CO2-enriched) water injection (CWI) has the potential to improve oil recovery in oil reservoirs. Introduced oil recovery mechanisms were oil swelling and oil viscosity reduction. However, most early studies have neglected to consider two important factors: (i) using ‘’live’’ reservoir oil (oil with dissolved gases) rather than refined oil or dead oil, (ii) establishing the native wettability state of the oil reservoirs which is generally mixed-wet to oil-wet. Previously, we reported the fluid-fluid and rock-fluid interactions that took place during CWI under realistic reservoir conditions using ‘’live’’ oil and aged rock. The results indicated CO2 partitioning at the interface of carbonated water (CW) and live oil leads to nucleation of a new gaseous phase inside the oil that boosts the performance of CWI significantly which represents being a game-changer for this EOR technique. Furthermore, based on our reported wettability studies, low pH of CW can change the wettability state of the brine-oil-rock system and thereby improve the oil recovery. In this study, through a series of carefully designed coreflood and micromodel experiments, the aim has been to comprehensively investigate (i) the complex fluid-fluid interactions which happen at pore scale during CWI in both ‘’live’’ and dead oil systems and (ii) the effects of formation of the new phase and wettability alteration on oil recovery by CWI at core scale. For the coreflood experiments two systems were considered, a mixed-wet system and a water-wet system, and for each system a secondary waterflood and a secondary CWI were conducted at pressure and temperature of 2500psia and 100°F. Synthetic live reservoir crude oil was used.The results of pore scale observations revealed the rapid formation and growth of the new phase as CW comes in contact with ‘’live’’ oil. However, this phenomenon was not observed for the dead oil system. Furthermore, the results of coreflood tests for both water-wet and mixed-wet systems revealed the good potential of CWI compared to waterflood. However, secondary CWI in the mixed-wet system resulted in higher and earlier additional oil recovery than shown in the water-wet system. For the water-wet system, secondary CWI led to 6.2% ultimate additional oil recovery. This incremental oil recovery took place after the breakthrough with the main recovery mechanism being nucleation and growth of the new phase. However, for the mixed-wet system, secondary CWI led to 4.6% additional oil recovery at time of breakthrough and 11% ultimate additional oil recovery. The main recovery mechanisms were wettability alteration and formation and growth of the new phase. Based on the results, the formation and growth of the new phase play a more dominant role on additional oil recovery by CWI.

Incorporation of viscosity scaling group into analysis of MPMS index for laboratory characterization of wettability of reservoir rocks

Wettability is a key parameter affecting petrophysical properties of reservoir rocks. Mirzaei-Paiaman et al. (Energy Fuels 27:7360–7368, 2013) presented an index (referred to as MPMS) for laboratory characterization of wettability of native- or restored-state reservoir rock samples. To use this index two counter-current spontaneous imbibition (COUCSI) experiments are needed, one on the native- or restored-state core sample and another on the strongly water-wet (SWW) reference system. Slope analysis of recovery data in these two systems gives inputs for determination of MPMS index. The two systems must have the same pore structure, initial water saturation, and viscosity ratio. The case of high viscosity reservoir crude needs the reference COUCSI test to be performed using a high viscosity polar compounds-free oil. Such test could be very slow and time consuming. The purpose of this study is to remove the need for limiting condition of the same viscosity ratio between the two systems, so that the reference experiment could be performed using any viscosity ratio independent of viscosity ratio of the native- or restored-state system. Thus, in the case of high viscosity reservoir crude, the reference test can be conducted using a low viscosity oil. Such test is relatively very fast and time efficient. We do this by benefiting the viscosity scaling group (VSG) proposed by Mason et al. (J Pet Sci Eng 72:195–205, 2010). Using experimental data from three sets of mixed-wet systems, we show that applicability of this VSG is not limited to SWW systems only. This VSG is used to relax the need for the limiting condition of the same viscosity ratio between the native- or restored-state and reference systems in the MPMS method. Using two sets of experimental data, we show that acceptable results are observed when comparing the MPMS indices estimated by the proposed technique and the original MPMS method.

Automated contact angle estimation for three-dimensional X-ray microtomography data

Multiphase flow in capillary regimes is a fundamental process in a number of geoscience applications. The ability to accurately define wetting characteristics of porous media can have a large impact on numerical models. In this paper, a newly developed automated three-dimensional contact angle algorithm is described and applied to high-resolution X-ray microtomography data from multiphase bead pack experiments with varying wettability characteristics. The algorithm calculates the contact angle by finding the angle between planes fit to each solid/fluid and fluid/fluid interface in the region surrounding each solid/fluid/fluid contact point. Results show that the algorithm is able to reliably compute contact angles using the experimental data. The in situ contact angles are typically larger than flat surface laboratory measurements using the same material. Wetting characteristics in mixed-wet systems also change significantly after displacement cycles.

Capillary trapping for geologic carbon dioxide storage – From pore scale physics to field scale implications

A significant amount of theoretical, numerical and observational work has been published focused on various aspects of capillary trapping in CO2 storage since the IPCC Special Report on Carbon Dioxide Capture and Storage (2005). This research has placed capillary trapping in a central role in nearly every aspect of the geologic storage of CO2. Capillary, or residual, trapping – where CO2 is rendered immobile in the pore space as disconnected ganglia, surrounded by brine in a storage aquifer – is controlled by fluid and interfacial physics at the size scale of rock pores. These processes have been observed at the pore scale in situ using X-ray microtomography at reservoir conditions. A large database of conventional centimetre core scale observations for flow modelling are now available for a range of rock types and reservoir conditions. These along with the pore scale observations confirm that trapped saturations will be at least 10% and more typically 30% of the pore volume of the rock, stable against subsequent displacement by brine and characteristic of water-wet systems. Capillary trapping is pervasive over the extent of a migrating CO2 plume and both theoretical and numerical investigations have demonstrated the first order impacts of capillary trapping on plume migration, immobilisation and CO2 storage security. Engineering strategies to maximise capillary trapping have been proposed that make use of injection schemes that maximise sweep or enhance imbibition. National assessments of CO2 storage capacity now incorporate modelling of residual trapping where it can account for up to 95% of the storage resource. Field scale observations of capillary trapping have confirmed the formation and stability of residually trapped CO2 at masses up to 10,000tons and over time scales of years. Significant outstanding uncertainties include the impact of heterogeneity on capillary immobilisation and capillary trapping in mixed-wet systems. Overall capillary trapping is well constrained by laboratory and field scale observations, effectively modelled in theoretical and numerical models and significantly enhances storage integrity, both increasing storage capacity and limiting the rate and extent of plume migration.

Technology Focus: EOR Performance and Modeling (January 2015)

Technology Focus We can easily state that incorporating enhanced-recovery focus into field- management practices as early as possible is finally becoming the norm. No longer is enhanced oil recovery (EOR) something operators procrastinate about and not act on until the end of the life of a field. Growing recovery challenges of maturing fields definitely are one of the reasons for this historical change in focus. We should also acknowledge the effect of growing unconventional oil operations and, more importantly, their severe recovery challenges. Increasing recovery factors in tight, light reservoirs is one of the more prominent research topics in the oil industry in recent years. Last but not least, EOR is being implemented in offshore operations. This new paradigm—caring for production and recovery, optimizing production rates and recovery factors simultaneously—is being realized with significant help from new technologies. Significant enhancements in reservoir characterization, EOR chemicals, modeling capabilities (EOR software and computational power), conformance capabilities, and monitoring and control systems, along with improved understanding of flow physics, are making EOR easier for our industry. Ongoing EOR research is bringing complex EOR schemes to the industry; some of the examples are low-salinity CO2 water-alternating-gas (WAG) injection, CO2/steam injection, steam/ solvent injection, and microbial EOR. Integration for successful EOR projects is also maturing. Historically, with steam-assisted gravity drainage, we all recognized the effect of well trajectory on recovery. More recently, we have identified the relationship between massive fracture architecture and EOR in tight, light reservoirs. It is worth mentioning that unconventionals have been pushing reservoir characterization, drilling, and completions to yet another level. All that effort not only improves the performance of those special reservoirs but also makes EOR easier for conventionals. As a result of the focus on enhancing recovery for all types of reservoirs, many great technical papers were available for this feature this year. The following pages will provide some insights into how EOR is being tested for tight, light reservoirs; into low-salinity CO2 WAG experimentation; and into giant-field EOR applications. More papers can be found in the OnePetro online library, including those listed for recommended additional reading. JPT Recommended additional reading at OnePetro: www.onepetro.org. SPE 169076 Modeling of Viscous Displacement in Dual-Porosity Naturally Fractured Reservoirs: Application to Surfactant Enhanced Oil Recovery by Mojtaba Kiani, Tiorco, et al. SPE 169170 Assessment of Three-Phase Relative Permeability and Hysteresis Models for Simulation of Water- Alternating-Gas Injection in Water- Wet and Mixed-Wet Systems by Omid Shahrokhi, Heriot-Watt University, et al. SPE 169102 Low-Salinity Waterflooding at West Salym: Laboratory Experiments and Field Forecasts by B.M.J.M. Suijkerbuijk, Shell, et al. OTC 24483 Relative Permeability Effects on the Miscible CO2 WAG Injection Schemes Through Compositional Simulations of Brazilian Small-Scale Water-Wet Synthetic Presalt Reservoir by S.F. Mello, Universidade Estadual de Campinas, et al.

Structure of residual oil as a function of wettability using pore-network modelling

In the water flooding of mixed-wet porous media, oil may drain down to relatively low residual oil saturations (Sor). Various studies have indicated that such low saturations can only be reached when oil layers in pore corners are included in the pore-scale modelling. These processes within a macroscopic porous medium can be modelled at the pore-scale by incorporating the fundamental physics of capillary dominated displacement within idealised pore network models. Recently, the authors have developed thermodynamic criteria for oil layer existence in pores with non-uniform wettability which takes as input geometrically and topologically representative networks, to calculate realistic Sor values for mixed-wet and oil-wet sandstones [16, 21]. This previous work is developed in this paper to include (i) the visualisation of the 3D structure of this residual oil, and (ii) a statistical analysis of this “residual/remaining” oil. Both the visualisation and the statistical analysis are done under a wide range of wettability conditions, which is reported for the first time in this paper.The structure of residual oil for strongly water wet systems is well known (where residual=remaining oil) and our model agrees with this but this structure changes radically for mixed wet systems (where residual≠remaining) and this has not yet been visualised experimentally. We find that for more water-wet systems high final residual oil saturations are reached at relatively small amounts of water injected and this oil is present in the pores as bulk oil. On the other hand, for more oil-wet systems we find a slow decrease of the amount of remaining oil with increasing amounts of injected water. During the process, the remaining connectivity of the oil phase is increasingly provided by oil layers only, hence the slow drainage. The final residual oil saturation, only reached in the theoretical limit of an infinite amount of injected water, is almost entirely contained in large number of (relatively low volume) oil layers, which are present in pores of most radius sizes.

Relative Permeability Hysteresis: Water-Alternating-Gas Injection and Gas Storage

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 161827, ’Experimental and Theoretical Investigation of Water/Gas Relative Permeability Hysteresis: Applicable to Water-Alternating-Gas (WAG) Injection and Gas-Storage Processes,’ by S. Mobeen Fatemi, SPE, and Mehran Sohrabi, SPE, Heriot-Watt University, prepared for the 2012 Abu Dhabi International Petroleum Exhibition & Conference, Abu Dhabi, 11-14 November. The paper has not been peer reviewed. Accurate determination of relative permeability hysteresis is needed to predict water-alternating-gas (WAG) injection reliably. Two series of gas/water relative permeability hysteresis curves were obtained from corefloods under mixed-wet conditions. The results revealed that none of the widely used hysteresis models (e.g., Carlson and Killough models) is able to predict the observed cyclic relative permeability hysteresis for alternating injection of gas and water. The results suggest that, for mixed-wet systems, it is necessary to consider irreversible hysteresis loops for modeling both the wetting and the nonwetting phase. Introduction Because of nonwetting-phase trapping, wetting-phase relative permeability for imbibition increased compared with the drainage case and nonwetting-phase imbibition relative permeability was less than that of the drainage case. Therefore, relative permeability to a fluid at a given saturation depends on whether that saturation was obtained by approaching it from a higher or lower value. This behavior in relative permeability is the hysteresis effect. Much of the hysteresis data in the literature was obtained with saturations starting at endpoint values (i.e., irreducible-water saturation or residual-oil saturations for a water/oil system). These data usually deal with the differences between bounding relative permeabilities. Such data are more applicable to modeling reservoir processes in which phase saturations increase or decrease to an intermediate value, then change in the opposite direction. Examples include enhanced-oil-recovery methods such as WAG injection or cyclic-steam stimulation. Most of the existing relative permeability hysteresis functions were developed for strongly water-wet porous media. However, it generally is accepted that many oil reservoirs are mixed-wet. In a mixed-wet system, the oil-wet pores correspond to the largest pores in the rock, while the small pores are water-wet. There are only a few relative permeability models developed for mixed-wet porous media, of which none are included in commercial simulators. The purpose of this study was to further investigate the effect of cyclic hysteresis for water/gas systems under mixed-wet conditions. These two-phase relative permeability data are of interest for reliable simulation of processes involving cyclic changes between imbibition and drainage displacement, including WAG injection. The results of this study can be applied to underground hydrocarbon-gas storage, which usually involves cyclic pressurization (drainage) and depressurization (imbibition) on an annual basis. This is especially true if the underground formation has an active aquifer.

Experimental Investigation of Near-Miscible Water-Alternating-Gas Injection Performance in Water-Wet and Mixed-Wet Systems

Summary Laboratory data on water-alternating-gas (WAG) injection for non-water-wet systems are very limited, especially for near-miscible (very low IFT) gas/oil systems, which represent injection scenarios involving high-pressure hydrocarbon gas or CO2 injection. Simulation of these processes requires three-phase relative permeability (kr) data. Most of the existing three-phase relative permeability correlations have been developed for water-wet conditions. However, a majority of oil reservoirs are believed to be mixed-wet and, hence, prediction of the performance of WAG injection in these reservoirs is associated with significant uncertainties. Reliable simulation of WAG injection, therefore, requires improved relative permeability and hysteresis models validated by reliable measured data. In this paper, we report the results of a comprehensive series of coreflood experiments carried out in a core under natural water-wet conditions. These included water injection, gas injection, and also WAG injection. Then, to investigate the impact of wettability on the performance of these injection strategies, the wettability of the same core was changed to mixed-wet (by aging the core in an appropriate crude oil) and a similar set of experiments were performed in the mixed-wet core. WAG experiments under both wettability conditions started with water injection (I) followed by gas injection (D), and this cyclic injection of water and gas was repeated (IDIDID). The results show that in both the water-wet and mixed-wet cores, WAG injection performs better than water injection or gas injection alone. Changing the rock wettability from water-wet to mixed-wet significantly improves the performance of water injection. Under both wettability conditions (water-wet and mixed-wet), the breakthrough (BT) of the gas during gas injection happens sooner than the BT of water in water injection. Ultimate oil recovery by gas injection is considerably higher than that obtained by water injection in the water-wet system, while in the mixed-wet system, gas injection recovers considerably less oil.

Experimental and Theoretical Investigation of Gas/Oil Relative Permeability Hysteresis under Low Oil/Gas Interfacial Tension and Mixed-Wet Conditions

Accurate determination of relative permeability values and their hysteresis is crucial for obtaining a reliable prediction of the performance of water-alternating-gas (WAG) injection in oil reservoirs. In this paper, we report two series of gas/oil relative permeability curves obtained from coreflood experiments carried out in a mixed-wet core under a very low oil/gas interfacial tension (IFT) of 0.04 mN·m–1. The first set of the corefloods began by gas injection (drainage) in the core saturated with oil and immobile water (Swi). This was followed by a period of oil injection (imbibition), and this sequential injection of gas and oil continued, and in total, three drainage and two imbibition periods were carried out. In the second series of experiments, the core was initially saturated with gas and immobile water, and the experiment started with oil injection and followed by cycles of drainage and imbibitions. The measured pressure drop and production data were history matched through simulation analysis to obtain krg and kro values for each of the imbibition and drainage cycles. The results show that both the oil and the gas relative permeability curves show cycle-dependent hysteresis despite the very low gas/oil IFT. Therefore, the current assumption in existing models (such as Land, Carlson, and Killough) that the drainage scanning kr curves follow the preceding imbibition curve is not supported by our coreflood experiments. When compared to our measured data, the Carlson model predictions for krg in imbibition direction are poor. The Killough model predictions underestimate krg and overestimate kro, especially near trapped gas saturation regions. Beattie et al. hysteresis model is able to capture the krg and kro behavior that we observed in our experiments qualitatively, but it is still unable to predict the value of the observed hysteresis. The results suggest that, for mixed-wet systems, it is necessary to consider irreversible hysteresis loops for both the wetting and nonwetting phases. Such capability currently does not exist in reservoir simulators because of a lack of appropriate predictive tools.

Pore-scale modeling: Effects of wettability on waterflood oil recovery

We study the effects of wettability on waterflood oil recovery using a capillary-controlled pore-scale network model. We validate the model against experimental data in the literature on mixed-wet Berea sandstone and then apply it to study multiphase flow through four networks extracted from different types of rock: a sand pack, a poorly consolidated sandstone from the Middle East, a granular carbonate and Berea sandstone. We study the effects of initial water saturation, contact angle distribution and oil-wet fraction on recovery. For a uniformly-wet system, where the contact angle everywhere falls within a relatively narrow range, recovery increases as the system becomes less water-wet and reaches a maximum for oil-wet conditions where recovery is approximately constant for average intrinsic contact angles above 100°. As the initial water saturation increases, recovery decreases in water-wet systems whereas in oil-wet systems it initially increases and then decreases. For mixed-wet systems that contain water-wet and oil-wet regions of the pore space, the oil-wet fraction plays a more important role in determining recovery than the contact angle in the oil-wet regions. Optimal recovery occurs when a small fraction of the system is water-wet. Pore structure plays a relatively minor role in the generic behavior, although it does influence the initial saturation for maximum recovery and the magnitude of the recovery. These results are explained in terms of pore-scale displacement mechanisms and fluid configurations.

Three-Phase Capillary Pressure and Relative Permeability Relationships in Mixed-Wet Systems

A simple process-based model of three-phase displacement cycles for both spreading and non-spreading oils in a mixed-wet capillary bundle model is presented. All possible pore filling sequences are determined analytically and it is found that the number of pore occupancies that are permitted on physical grounds is actually quite restricted. For typical non-spreading gas/oil/water systems, only two important cases need to be considered to see all types of allowed qualitative behaviour for non-spreading oils. These two cases correspond to whether water or gas is the ‘intermediate-wetting’ phase in oil-wet pores as determined by the corresponding contact angles, that is, cos θogw > 0 or cos θogw < 0, respectively. Analysis of the derived pore occupancies leads to the establishment of a number of relationships showing the phase dependencies of three-phase capillary pressures and relative permeabilities in mixed-wet systems. It is shown that different relationships hold in different regions of the ternary diagram and the morphology of these regions is discussed in terms of various rock/fluid properties. Up to three distinct phase-dependency regions may appear for a non-spreading oil and this reduces to two for a spreading oil. In each region, we find that only one phase may be specified as being the ‘intermediate-wetting’ phase and it is only the relative permeability of this phase and the capillary pressure between the two remaining phases that depend upon more than one saturation. Given the simplicity of the model, a remarkable variety of behaviour is predicted. Moreover, the emergent three-phase saturation-dependency regions developed in this paper should prove useful in: (a) guiding improved empirical approaches of how two-phase data should be combined to obtain the corresponding three-phase capillary pressures and relative permeabilities; and (b) determining particular displacement sequences that require additional investigation using a more complete process-based 3D pore-scale network model.