Oil-wet Conditions Research Articles

Flow Dynamics of Sulfate-Modified Water/Polymer Flooding in Micromodels with Modified Wettability

This work describes the flow behavior of the oil recovery obtained by the injection of sulfate-modified/low-salinity water in micromodels with different wettabilities. It provides a detailed microscopic visualization of the displacement taking place during modified water flooding at a pore-scale level, while evaluating the effect of wettability on oil recovery. A comprehensive workflow for the evaluation is proposed that includes fluid–fluid and rock–fluid interactions. The methods studied comprise flooding experiments with micromodels. Artificial and real structure water-wet micromodels are used to understand flow behavior and oil recovery. Subsequently, water-wet, complex-wet, and oil-wet micromodels help understand wettability and rock–fluid interaction. The effect of the sulfate content present in the brine is a key variable in this work. The results of micromodel experiments conducted in this work indicate that sulfate-modified water flooding performs better in mixed-wet/oil-wet (artificial structure) than in water-wet systems. This slightly differs from observations of core flood experiments, where oil-wet conditions provided better process efficiency. As an overall result, sulfate-modified water flooding recovered more oil than SSW injection in oil-wet and complex-wet systems compared to water-wet systems.

Influence of the wettability on the residual fluid saturation for homogeneous and heterogeneous porous systems

The influence of wettability on the residual fluid saturation is analyzed for homogeneous and heterogeneous porous systems. Several simulations under different wettability, flow rate, and heterogeneity conditions were carried out using a two-component lattice-Boltzmann method. The fluid flow driving force and initial conditions were imposed using a specific methodology that allows a clear distinction between the results obtained for immiscible displacement when the porous medium is initially saturated with one fluid (called primary) and when two fluids are filling the porous spaces (called secondary). The results show that the primary sweeping process is more effective when the displaced fluid is non-wetting. We observe that the heterogeneity has an important role for the whole process since it disturbs the fluid interfaces inducing the flow in the longitudinal and transversal directions, improving considerably the effectiveness of the primary displacement when compared with ideally homogeneous cases. We noted that for oil contact angles, θo, higher than a critical value, no residual oil is found. In all homogeneous cases, the critical value is 120°. The residual fluid increases proportionally to the capillary number for primary displacements, but it also depends on the system heterogeneity and wetting conditions. For secondary displacements in heterogeneous systems, the highest residual oil saturation is found for completely oil-wet conditions, with values ranging from 29% to 41% and tending to zero for all cases when θo > 120°. The initial water–oil distribution is found to be a determining factor in the amount of trapped oil after the waterflooding process.

Experimental investigation of Alfalfa natural surfactant and synergistic effects of Ca2+, Mg2+, and SO42− ions for EOR applications: Interfacial tension optimization, wettability alteration and imbibition studies

Fractured moderate oil-wet carbonate reservoirs are the main productive formations in the Middle East. The change in wettability state toward water wetness beside interfacial tension (IFT) reduction is one of the potential scenarios for more oil recovery process. Smart water and natural surfactant injection into the porous media will alter the rock wettability and reduce IFT which consequently results in more oil sweep from untouched pores. In this paper, a novel natural surfactant (Alfalfa species) is introduced for EOR applications. IFT and contact angle tests were carried out between the oil phase, rock surface, Alfalfa natural surfactant, and surfactant—ion hybrid aqueous solutions. The results of Alfalfa natural surfactant showed a 29.29 mN/m reduction of IFT (63.39% IFT optimization) at the concentration of 4 wt% as the critical micelle concentration (CMC). Also, after addition of Alfalfa the wettability of rock tends to be more water-wet from the initial oil-wet state by application of Alfalfa because of 86.84° reduction of contact angle (49.91% wettability alteration). Solutions of calcium, magnesium, and sulfate ions were prepared as modified synthetic seawater at CMC of Alfalfa natural surfactant to investigate their synergistic influences on intensifying the optimizations of IFT and wettability alteration as hybrid solutions. IFT measurements of the hybrids demonstrated that among mentioned ions calcium brings the best results as it showed good synergistic effects with mentioned non-ionic natural surfactant in advancing the optimization of IFT reduction from 63.39 (surfactant solution) to 71.0 (surfactant—ion hybrid solution) percent. Also, contact angle measurements of the hybrids demonstrated that calcium ions gain the best results and advance the contact angle optimization from 49.91 (surfactant solution) to 61.8 (surfactant—ion hybrid solution) percent. Therefore, the solution of 3 times Ca concentrated seawater + CMC of surfactant selected to conduct imbibition tests as a displacement experiment based on the hybrid results and the candidate solution caused a 19.2% increase in oil recovery factor regarding seawater flooding and a total oil recovery factor of 62%.

Impacts of pore structure and wettability on distribution of residual fossil hydrogen energy after imbibition

Due to the heterogeneity of the pore structure, there is still much residual fossil hydrogen energy in the pore space. In this study, the distribution of residual fossil hydrogen energy after imbibition with liquid nanofluid (LNF) has been studied through the. Firstly, relevant properties of the LNF were tested, including particle size, wettability alteration, and interfacial tension (IFT). Then, one micromodel under both oil-wet and water-wet conditions was used to elucidate the difference of residual oil after imbibition. Moreover, the difference of imbibition processes with oil-wet and water-wet models was further studied. Finally, the influence of dimensions and coordination numbers of pores was investigated. Besides, the impact of fluid type on imbibition efficiency was also compared through microfluidic experiments. Results show that the residual oil saturation is significantly higher in the oil-wet micromodel than in the water-wet micromodel, even the wettability alteration additive was used. There are four kinds of locations for residual oil after imbibition in water-wet micromodel, while only three kinds of locations for residual oil in oil-wet micromodel. The imbibition rate and residual oil saturation in small pores are higher than the larger ones. Due to the unbalanced force at pore throats, a micromodel with a high coordination number has lower residual oil saturation. Besides, the lower residual oil saturation is obtained by adding the LNF. This paper provides a micro-visual method to understand the imbibition process under different wettability and pore structures in fossil hydrogen reservoirs.

Mechanistic study on silica nanoparticles-assisted guar gum polymer flooding for enhanced oil recovery in sandstone reservoirs

Nanoparticles-assisted polymer flooding has attracted the attention of researchers for its enhanced rheological properties and stability of the chemical slugs. The present work deals with the rheological properties of guar gum with and without silica nanoparticles in the temperature range from 25 °C to 75 °C. It is found that the viscosity of guar gum solution increases significantly with increasing concentration of silica nanoparticles. Imbibition experiments were performed with waxy crude oil-saturated sandstone cores using 2000 ppm brine, 4000 ppm guar gum solution, 0.2 wt% silica nanoparticles in distilled water, and 4000 ppm guar gum containing 0.2 wt% silica nanoparticles as test fluids for understanding the mechanism of wettability alteration in the presence of silica nanoparticles and guar gum. Mixture of 0.2 wt% silica nanoparticles and 4000 ppm guar gum shows higher oil recovery (∼36 % original oil-in-place) compared to other test solutions in imbibition experiments. Contact angles between crude oil and sandstone rock were measured in presence of 2000 ppm brine, 0.025 wt% silica nanoparticles in water, and guar gum (2000 ppm)-silica nanoparticles (0.025 wt%) mixture. Guar gum containing silica nanoparticles are effective in changing the contact angle towards water-wet state (Contact angle ∼115°) from oil-wet state (contact angle ∼72°). No significant phase change is observed during the phase behavior experiment except for light emulsion formation. Finally, core flooding experiments were conducted with guar gum, silica nanoparticles solution, and mixture of silica nanoparticles and guar gum for additional oil recovery to verify the effectiveness of the chemical slugs. Results showed that the addition of silica nanoparticles to guar gum solution improves the effectiveness of guar gum polymer by recovering 44.3 % of original oil-in-place. A comparative study was also conducted to show the performance of silica nanoparticles-assisted guar gum solution for additional oil recovery. Most of the research works have focused on the application of silica nanoparticles-induced polyacrylamide and xanthan gum chemical slugs in enhanced oil recovery. However, laboratory study based on the application of silica nanoparticles-induced guar gum solution in additional oil recovery adds some interesting findings to the literature compared to the existing information.

Wettability Alteration in Carbonate Reservoirs by Carbon Nanofluids

Wetting phenomena play a significant role in oil recovery from complex carbonate reservoirs under harsh conditions. The potential to being able to alter the rock wettability from oil-wet to water- or neutral-wet is often considered the pre-requisite to a successful Enhanced Oil Recovery (EOR) process. Hence, there arises the importance of understanding the (static) wetting and (dynamic) wettability alteration of the reservoir rock when the rock comes in contact with injected modified brines, oilfield chemicals, and/or nanofluids. In this study, we investigate the effect of three Carbon nanodots in high salinity brines with and without surfactant on static wetting and dynamic wettability alteration of carbonate reservoirs. Outcrop Indiana limestone and reservoir crude oil samples were used in these tests. The contact angle of the rock-oil-brine system is measured as a function of the nanodot concentration, saturating fluid in the rock matrix and aging, surfactant concentration, temperature, pressure, and brine salinity. The upper limits for the values for temperature, pressure, and salinity are set to be representative of the Saudi Arabian harsh reservoir conditions. The use of Carbon nanofluids demonstrated a clear shift in both static and dynamic measurements towards a more favorable water-wet condition for EOR. Statically, the contact angle of an oil-saturated carbonate rock exhibited a change from a strongly oil-wet condition to slightly water wet (with more than 50 % drop in the contact angle value) in 200 ppm (0.02 wt/v%) solution of carbon nanodot (CND) in seawater (SW) over 24 hours. Dynamically, a smaller but still remarkable change (a shift in the order of 20 %) in the contact angle is noted for a sister rock sample over the same period when a solution at the same concentration of CND in SW is introduced to replace the SW base fluid. Nanofluid spreading experiments on oil-coated glass slides supported our dynamic wettability studies. The spreading efficiency of the Carbon nanofluid was analyzed using optical and confocal microscopy with a clear and remarkable oil dislodging effect. Zeta potential measurements of the different systems were made to aid in the interpretations. The combined mechanistic actions of the various factors, including reservoir environment, disjoining pressure, interfacial tension, capillary pressure alterations and nanodots interactions with the oil/water interface, contributed to this change in wettability. Our study supports a strong and favorable EOR impact of CND as an effective and economically viable additive to waterflood operations in carbonate reservoirs.

A positively charged calcite surface model for molecular dynamics studies of wettability alteration

A new model for a positively charged calcite surface was developed to allow realistic molecular dynamics studies of wettability alteration on carbonate rocks. The surface charge was introduced in a manner consistent with the underlying calcite geochemistry and with the conclusions of recent quantum mechanical studies. The simulations using the new surface model demonstrate that the experimentally observed wettability behavior of calcite is represented correctly. In particular, the model surface became oil-wet due to the adsorption of the carboxylate species. Furthermore, the oil-wet conditions were reversed more effectively by a cationic surfactant than by an anionic one, in agreement with the majority of experimental observations. Finally, with simulated smart water, the well-documented wettability alteration abilities of Ca2+ and SO42− could be explained by the formation of ion-pairs and competitive adsorption onto the surface, respectively. The simulation results with the new surface model conceptually agree with the electric double layer expansion being the predominant mechanism for the low salinity effect in oil recovery enhancement. The proposed calcite surface model will benefit future simulation studies on the wettability characteristics of carbonate rocks, and facilitate the design and optimizations of chemical agents and formulations to enhance the oil recovery from carbonate reservoirs.

Impact of pore morphology on two-phase flow dynamics under wettability alteration

Low salinity waterflooding aims to alter rock wettability from oil-wet towards less oil-wet or water-wet conditions. There is a limited understanding of how wettability alteration impacts two-phase flow, which is why it is unclear how wettability change impacts oil recovery. This study is an attempt to evaluate the effect of wettability alteration on two-phase flow for different pore size distributions under tertiary mode of low salinity waterflooding. Pore-scale, two-phase flow simulations with wettability alteration were performed in OpenFOAM’s CFD tool. Two synthetic pore geometries (domains) were constructed with identical pore topology and connectivity, but different variances of pore throat radii. In our simulations, the pore network with a larger variance in pore radii resulted in 12% additional oil recovery. Whereas, the network with smaller variance in pore radii experienced no additional oil recovery despite the same wettability alteration change. This implies that change of wettability in clusters with a larger variation of pore radii can lead to a larger variation in capillary pressure gradient due to wettability alteration, which induces remobilisation of the trapped oil.

Investigating sweep efficiency improvement in oil-wet porous media by the application of functionalized nanoparticles

Nanoparticle stabilized emulsions have gained recent attention as mobility control agents in EOR processes. Some recent studies have shown in-situ formation of nanoparticle stabilized emulsions during displacement of a brine phase containing nanoparticles by another non-wetting phase such as n-octane under water-wet conditions. The objective of this research is to evaluate the hypothesis of nanoparticle stabilized emulsion formation by varying the system wettability toward oil-wet condition. Partially hydrophobic silica NPs with proper interface affinity are firstly synthesized and characterized in this study. A series of drainage displacement experiments are then conducted in the oil-wet sandpack embedded in a CT scanner, in the absence or presence of the functionalized NPs and a surfactant. CT-scans during waterflooding in the presence of NPs and surfactant has revealed a piston like displacement as a result of in-situ emulsion formation at the water invading front, which is associated with later water breakthrough, higher pressure drop, considerable pressure fluctuations, and higher oil recovery compared to the control experiment. The effect of nanofluid slug size and nanofluid viscosity is further investigated on sweep efficiency improvement during drainage displacement. The results have revealed that the presence of an oil-based nanofluid is effective in re-distributing the preferential water flow paths into a more stable front as a result of in-situ emulsification and the overall displacement efficiency depends on the nanofluid propagation in porous media. The oil-based nanofluid flooding followed by waterflooding utilized here is found to be a potential conformance control technique for oil recovery in oil-wet porous media.

Toward Reservoir-on-a-Chip: Rapid Performance Evaluation of Enhanced Oil Recovery Surfactants for Carbonate Reservoirs Using a Calcite-Coated Micromodel

Enhanced oil recovery (EOR) plays a significant role in improving oil production. Tertiary EOR, including surfactant flooding, can potentially mobilize residual oil after water flooding. Prior to the field deployment, the surfactant performance must be evaluated using site-specific crude oil at reservoir conditions. Core flood experiments are common practice to evaluate surfactants for oil displacement efficiency using core samples. Core flood experiments, however, are expensive and time-consuming and do not allow for pore scale observations of fluid-fluid interactions. This work introduces the framework to evaluate the performance of EOR surfactants via a Reservoir-on-a-Chip approach, which uses microfluidic devices to mimic the oil reservoir. A unique feature of this study is the use of chemically modified micromodels such that the pore surfaces are representative of carbonate reservoir rock. To represent calcium carbonate reservoir pores, the inner channels of glass microfluidic devices were coated with thin layers of calcium carbonate nanocrystals and the surface was modified to exhibit oil-wet conditions through a crude oil aging process. During surfactant screening, oil and water phases were imaged by fluorescence microscopy to reveal the micro to macro scale mechanisms controlling surfactant-assisted oil recovery. The role of the interfacial tension (IFT) and wettability in the microfluidic device was simulated using a phase-field model and compared to laboratory results. We demonstrated the effect of low IFT at the oil-water interface and wettability alteration on surfactant-enhanced oil displacement efficiency; thus providing a time-efficient and low-cost strategy for quantitative and qualitative assessment. In addition, this framework is an effective method for pre-screening EOR surfactants for use in carbonate reservoirs prior to further core and field scale testing.

Parametric Investigation of Wettability Alteration of Reservoir Rocks by Asphaltene Deposition: Experimental and Modeling Approaches

Rock wettability plays an important role in water flooding process as it controls fluid flow, oil recovery and distribution of residual oil in any oil reservoir. In this context, polar oil components such as asphaltene contents may adsorb onto the pore mineral surfaces and alter wettability of the reservoir rock. Due to this importance, this study aims to investigate the effects of different parameters such as concentration of asphaltene, salinity, temperature and time on the rock wettability alteration process. For this purpose, dynamic contact angle measurement was performed. The results showed that the increment of asphaltene concentration in the oleic phase changes the wettability of water-wet sandstone rock to oil-wet condition; the increase in the concentration of asphaltene fraction from 0.1 to 5.0 g/lit increased the contact angle from 0 to 97 degrees. In addition, the increase in the brine salinity from 500 to 8000 ppm increased the ability of asphaltene to adsorb on the rock surface and consequently, increased oil wetness; the equivalent contact angle changed from 0 to 113 degree for 5 g/lit asphaltene content after 192 hours. Moreover, the results illustrated that a rise in temperature from 40 to 70 o C accelerates adsorption of asphaltene, but it has not significant effect on the final contact angle. Furthermore, the Adaptive Neuro-Fuzzy Inference System (ANFIS) is incorporated into the Particle Swarm Optimization (PSO) algorithm to correlate contact angle with the aforementioned parameters. To this end, the obtained experimental data are used to train and test the algorithm. The outputs of ANFIS-PSO algorithm are compared with the measured contact angles in both graphical and statistical manners. The training and testing determination coefficients (R 2 ) have been obtained as 0.99091 and 0.98761, respectively. The analysis indicates that the predictive model can be used with a high degree of confidence to investigate the effect of different parameters on wettability alteration

Impact of Acid and Base Numbers and Their Ratios on Wettability Alteration of the Calcite Surface

Alteration of rock wetting preference toward a more favorable wetting state has been identified as the primary mechanism of oil recovery from intermediate and oil-wet carbonate rocks. In order to produce a favorable wetting state, it is critical to have a clear picture of the initial wetting properties of the rock surface. This study aimed to improve the understanding of carbonate wettability by examining the impact of acid, base, and their mixture on wettability of calcite surfaces using different analytical tools (contact angle measurements, zeta potential test, Fourier transform infrared spectroscopy, interfacial tension measurements, and fluorescence ultraviolet spectroscopy). The acid number (AN) and the ratio of the basic component (quinoline) to the acidic component (stearic acid) were systematically varied in model oil solutions to elucidate the effect of simultaneous presence of the acid and base on the wettability alteration process. The results showed that as the acid concentration increases, the wettability alteration toward the oil-wet state is enhanced. However, the impact of the base was significant at high concentrations, where the wettability was changed toward the neutral state. Addition of the basic compound to the acidic model oil hindered the impact of stearic acid on wettability alteration. Although the impact of the basic component on wettability alteration of calcite seems to be weaker than that of the acidic component, presence of the base can alter the wetting characteristics of the surface. Acid and base concentrations and their ratio dictate the extent of calcite wettability alteration. Slight impact of the base on the wettability alteration process was observed for a system with an AN of 0.25. However, at higher ANs, an increase in the base number (BN) to AN ratio from 0 to 1 resulted in a remarkable reduction in the contact angle; while the contact angle increased again when the BN to AN ratio was 4. Further investigations (for systems with AN = 1) revealed that at the BN to AN ratio of 0.25 and 1, adsorption of the basic component on the surface was unlikely to happen. Formation of an acid–base complex could hinder the access of stearate ions to the calcite surface. At the BN to AN ratio of 1, the quinoline concentration was equal to that for stearic acid, which may enhance the acid–base interactions; hence, more stearic acid would be involved in acid–base complexes. However, once the base concentration became higher than the acid concentration (BN to AN = 4), an excess amount of the base, which was not involved in the complex mixtures with acid molecules, might adsorb on the surface.

Simultaneous Interpretation of Three-Phase Relative Permeability and Capillary Pressure for a Tight Carbonate Reservoir From Wireline Formation Testing

AbstractIn this paper, techniques have been developed to interpret three-phase relative permeability and water–oil capillary pressure simultaneously in a tight carbonate reservoir from numerically simulating wireline formation tester (WFT) measurements. A high-resolution cylindrical near-wellbore model is built based on a set of pressures and flow rates collected by dual packer WFT in a tight carbonate reservoir. The grid quality is validated, the effective thickness of the WFT measurements is examined, and the effectiveness of the techniques is confirmed prior to performing history matching for both the measured pressure drawdown and buildup profiles. Water–oil relative permeability, oil–gas relative permeability, and water–oil capillary pressure are interpreted based on power-law functions and under the assumption of a water-wet reservoir and an oil-wet reservoir, respectively. Subsequently, three-phase relative permeability for the oil phase is determined using the modified Stone II model. Both the relative permeability and the capillary pressure of a water–oil system interpreted under an oil-wet condition match well with the measured relative permeability and capillary pressure of a similar reservoir rock type collected from the literature, while the relative permeability of an oil–gas system and the three-phase relative permeability bear a relatively high uncertainty. Not only is the reservoir determined as oil-wet but also the initial oil saturation is found to impose an impact on the interpreted water relative permeability under an oil-wet condition. Changes in water and oil viscosities and mud filtrate invasion depth affect the range of the movable fluid saturation of the interpreted water–oil relative permeabilities.

Compositional simulation of three-phase flow in mixed-wet shale oil reservoir

Three-phase flow is often involved during the production of shale oil reservoir. Relative permeability, which is often used to characterize multiphase flow, is found a strong function of wettability. Meanwhile, the mixed wettability in shale reservoir has been well characterized and may have impacts on fluid flow. In this work, to describe the mix-wet condition in shale, matrix is divided into organic and inorganic matrix which are hydrophobic and hydrophilic respectively. Relative permeabilities under different condition of wettability are applied in each kind of matrix. To construct permeability for three-phase flow, water-oil and oil-gas systems are evaluated separately with the assumption that water/gas permeabilities are only functions of their own saturations. Specifically, water-oil relative permeability is obtained by simulating multiphase flow directly on a digital rock sample using the lattice Boltzmann method. Oil-gas relative permeability is calculated from capillary pressure obtained from confined vapor liquid equilibria (VLE) coupled with Young-Laplace equation. Compositional simulation shows that the rich hydrocarbon in organic matrix is difficult to be produced due to the relatively lower permeability and poorer oil mobility under oil-wet condition. Since organic matter is a dispersed phase inside inorganic matter, fluids in organic matrix must flow through inorganic matrix before reaching the fractures. The dispersed nature of organic matter makes the relative permeability in inorganic matrix a dominant factor that controls the overall production in shale oil reservoir. The effect of relative permeability in organic matrix however has limited effect.

Effect of brine type and ionic strength on the wettability alteration of naphthenic-acid-adsorbed calcite surfaces

Low-salinity/smart waterflooding is a technique, used in oil reservoirs, where the salinity and/or ionic composition of the injection water is tuned to improve oil recovery. It has been observed by many researchers that low-salinity waterflooding can enhance oil recovery by altering the wettability of carbonate rock surfaces from oil-wet to water-wet. Though wettability alteration is generally agreed to be the main mechanism for the improved oil recovery, the contributing parameters and necessary conditions for wettability alteration are not clearly understood. Hence, it is essential to decouple the effects of salinity, ionic composition, and oil composition on wettability alteration of the solid surface. In this work, we systematically investigated smart-water induced wettability alteration of naphthenic-acid-adsorbed oil-wet calcite surfaces. Well-characterized model systems were used to understand the effects of individual monovalent and divalent ions (Na+, Cl−, Mg2+ and SO42−), and salinity on the calcite surface wettability. Contact angle measurements were performed on smooth Iceland Spar calcite surfaces that were aged at 120 °C in 5M NaCl brine, acid number 1.5 model oil, and single-electrolyte-based brine solutions of different salinity and ionic composition. The extent of wettability alteration was assessed based on ACA values, which are more relevant during waterflooding, using a goniometer customized for obtaining multiple advancing and receding contact angles along the surface by the tilting plate method. The results indicate that, for 0.164 M ionic strength (equivalent to 4-times diluted seawater concentration) brine solutions, the wettability of calcite surfaces was changed from oil-wet state to water-wet state irrespective of the salt type. The lowest advancing contact angle (ACA) values (20°–30° range) were obtained for 0.164 M ionic strength NaCl and Na2SO4 solutions, indicating the presence of SO42− ions or reduction in NaCl concentration act in favor of wettability alteration towards water-wet. At this ionic strength, the relative merit of divalent SO42− ions over monovalent Cl− ions was not observed. Upon comparison of ACA values for 0.164 M ionic strength Na2SO4 and MgSO4 (SO42− ion is common) solutions, we concluded that the extent of wettability alteration is lower in the presence of Mg2+ ions. A similar conclusion was made by comparing ACA values for 0.164 M ionic strength NaCl and MgCl2 solutions (Cl− ion is common). The calcite surfaces aged in 0.656 M (equivalent to seawater concentration) NaCl solution demonstrated intermediate-wet state indicating the extent of wettability alteration towards water-wet state increases with a decrease in salinity.

Simulation Interpretation of Capillary Pressure and Relative Permeability From Laboratory Waterflooding Experiments in Preferentially Oil-Wet Porous Media

SummaryIn preferentially oil-wet porous media, laboratory waterflooding experiments are prone to capillary end effects. The wetting phase (oil) will tend to accumulate at the outlet where the capillary pressure is zero and leave a highly remaining-oil saturation at steady state (defined by a stable pressure drop and a zero oil-production rate) compared to the residual-oil saturation. Andersen et al. (2017c) derived analytical solutions describing how the capillary pressure and relative permeability of water (the injected phase) could be determined on the basis of pressure drop and average saturation at steady states obtained at different water-injection rates. Plotting these values against inverse rate reveals linear trends at high rates, with slopes and intercepts that directly quantify the saturation functions in the range of negative capillary pressures. The method is similar to the Gupta and Maloney (2016) intercept theory but quantifies entire functions rather than a single point and provides the trends also at low rates, thus using all the information.Our aim is to demonstrate how pressure drop and oil production at steady state for different water-injection rates can be used to derive relative permeability and capillary pressure from waterflooding. This is done in three ways. First, synthetic transient waterflooding tests are generated (using a core-scale simulator), applying the same saturation-function correlations as assumed in the analytical solution. Then, more-general correlations are assumed when generating the synthetic data. This is to test the robustness of the analytical solution in producing functions similar to the “true” ones. Finally, we perform a waterflooding experiment in the laboratory on a high-permeability (3 darcies) Bentheimer sandstone core, altered to an oil-wet state. Forced imbibition was started at a rate of 0.4 pore volumes (PV) per day, which was increased stepwise after approaching a steady state. Twelve rates were applied, differing overall by a factor of ≈1,000 to yield states governed by capillary forces and advective forces. The results were interpreted using both full history matching of the transient data and matching of the steady-state data with the analytical solution.The experimental procedure and model demonstrate that only water relative permeability and capillary pressure determine the steady state during waterflooding, and hence can be estimated accurately. The analytical solution could simultaneously match the trends and magnitude of a steady-state pressure drop and production with injection rate to give an estimation of the saturation functions. The estimated saturation functions from the analytical solution agreed well with the estimates from full history matching.

Micro-scale experimental investigations of multiphase flow in oil-wet carbonates. II. Tertiary gas injection and WAG

Carbonate reservoirs are typically oil-wet, which can lead to low oil production during the oil recovery processes such as base waterflooding. The residual oil in these reservoirs is the target of many EOR techniques such as tertiary gas injection and Water-Alternating-Gas (WAG) flooding. Currently, there is scarce research investigating the pore-scale displacement physics governing the afore-mentioned EOR techniques in oil-wet carbonates. In this study, three sets of miniature core-flooding experiments were performed in carbonate samples at elevated pressure and temperature conditions using a three-phase core-flooding system integrated with a high-resolution X-ray micro-CT scanner. Pore-scale displacement events governing tertiary gas injection and WAG under weakly oil-wet conditions were examined. The prevailing oil mobilization mechanisms during the tertiary gas injection were further investigated under varying wettability conditions. The results revealed that gas-to-oil-to-brine double displacement is the main displacement chain for oil production by tertiary gas injection. During this process, the greater was the degree of oil-wetness of the rock, the larger became the additional oil recovery that could be achieved. This was due to the increase in the frequency of gas-to-oil-to-brine double displacements and the superior connectivity of the oil phase under stronger oil-wet conditions. Furthermore, WAG flooding significantly increased the displacement efficiency of both gas and brine phases because of the shielding effect of the trapped gas ganglia. In the first WAG cycle, oil was produced through a series of direct and double displacements. Multiple displacements started taking place and further contributed to oil recovery as more WAG cycles were implemented.

Micro-scale experimental investigations of multiphase flow in oil-wet carbonates. I. In situ wettability and low-salinity waterflooding

In this study, the impacts of temperature, initial water saturation, and aging time on wettability alteration during dynamic aging process were investigated at the pore scale, using a state-of-the-art high-temperature, high-pressure miniature core-flooding system integrated with a high-resolution micro-CT scanner. Furthermore, pore-scale displacement mechanisms impacting the waterflooding oil recovery under varying oil-wet conditions were probed. Subsequently, we investigated the wettability alteration and its corresponding impact on pore-scale displacement mechanisms during low-salinity waterflooding (LSWF). The results showed that the aging-induced wettability alteration reached an equilibrium condition after approximately seventeen days. With higher temperature, lower initial water saturation, and longer aging time, we observed greater in situ contact angles indicative of more oil-wet rock surfaces. Once brine was injected to displace oil, since the majority of pore elements were oil-wet after the aging process, pore-scale piston-like displacements (brine-to-oil drainage) had the largest contribution to the oil recovery. Based on our observations, the waterflooding-based oil recovery decreases as the porous medium becomes more oil-wet. This phenomenon is due to the higher threshold brine pressures of the displacements in more oil-wet conditions, which restricts brine invasion into medium and small size pores. Furthermore, wettability alteration towards neutral-wetness and the consequent reduction in threshold brine pressure required for the fluid to invade the midsize oil-filled pores, result in higher oil recovery by LSWF compared to high-salinity waterflooding (HSWF). The in situ analyses indicate that reservoirs with wide pore size distributions (a large number of midsize pores) could be better candidates for applications of LSWF EOR technique.

Enhancing the spontaneous imbibition rate of water in oil-wet dolomite rocks through boosting a wettability alteration process using carbonated smart brines

Most fractured carbonate oil reservoirs have oil-wet rocks. Therefore, the process of imbibing water from the fractures into the matrix is usually poor or basically does not exist due to negative capillary pressure. To achieve appropriate ultimate oil recovery in these reservoirs, a water-based enhanced oil recovery method must be capable of altering the wettability of matrix blocks. Previous studies showed that carbonated water can alter wettability of carbonate oil-wet rocks toward less oil-wet or neutral wettability conditions, but the degree of modification is not high enough to allow water to imbibe spontaneously into the matrix blocks at an effective rate. In this study, we manipulated carbonated brine chemistry to enhance its wettability alteration features and hence to improve water imbibition rate and ultimate oil recovery upon spontaneous imbibition in dolomite rocks. First, the contact angle and interfacial tension (IFT) of brine/crude oil systems were measured for several synthetic brine samples with different compositions. Thereafter, two solutions with a significant difference in WAI (wettability alteration index) but approximately equal brine/oil IFT were chosen for spontaneous imbibition experiments. In the next step, spontaneous imbibition experiments at ambient and high pressures were conducted to evaluate the ability of carbonated smart water in enhancing the spontaneous imbibition rate and ultimate oil recovery in dolomite rocks. Experimental results showed that an appropriate adjustment of the imbibition brine (i.e., carbonated smart water) chemistry improves imbibition rate of carbonated water in oil-wet dolomite rocks as well as the ultimate oil recovery.

An Integrated Carbon-Dioxide-Foam Enhanced-Oil-Recovery Pilot Program With Combined Carbon Capture, Utilization, and Storage in an Onshore Texas Heterogeneous Carbonate Field

SummaryA carbon–dioxide (CO2) –foam enhanced–oil–recovery (EOR) field pilot research program has been started to advance the technology of CO2 foam for mobility control in a heterogeneous carbonate reservoir. Increased oil recovery with associated anthropogenic–CO2 storage is a promising technology for mitigating global warming as part of carbon capture, utilization, and storage (CCUS). Previous field tests with CO2 foam report various results because of injectivity problems and the difficulty of attributing fluid displacement specifically to CO2 foam. Thus, a comprehensive integrated multiscale methodology is required for project design to better link laboratory– and field–scale displacement mechanisms. This study presents an integrated upscaling approach for designing a miscible CO2–foam field trial, including pilot–well–selection criteria and laboratory corefloods combined with reservoir–scale simulation to offer recommendations for the injection of alternating slugs of surfactant solution and CO2, or surfactant–alternating–gas (SAG) injection, while assessing CO2–storage potential.Laboratory investigations include dynamic aging, foam–stability scans, CO2–foam EOR corefloods with associated CO2 storage, and unsteady–state CO2/water endpoint relative permeability measurements. Tertiary CO2–foam EOR corefloods at oil–wet conditions result in a total recovery factor of 80% of original oil in place (OOIP), with an incremental recovery of 30% of OOIP by CO2 foam after waterflooding. Stable CO2 foam, using aqueous surfactants with a gas fraction of 0.70, provided mobility–reduction factors (MRFs) up to 340 compared with pure–CO2 injection at reservoir conditions. Oil recovery, gas–mobility reduction, producing–gas/oil ratio (GOR), and CO2 utilization at field pilot scale were investigated with a validated numerical model. Simulation studies show the effectiveness of foam to reduce gas mobility, improve CO2 utilization, and decrease GOR.