Microbial Enhanced Oil Recovery in Fractional-Wet Systems: A Pore-Scale Investigation

Microbial enhanced oil recovery (MEOR) is a technology that could potentially increase the tertiary recovery of oil from mature oil formations. However, the efficacy of this technology in fractional-wet systems is unknown, and the mechanisms involved in oil mobilization therefore need further investigation. Our MEOR strategy consists of the injection of ex situ produced metabolic byproducts produced by Bacillus mojavensis JF-2 (which lower interfacial tension (IFT) via biosurfactant production) into fractional-wet cores containing residual oil. Two different MEOR flooding solutions were tested; one solution contained both microbes and metabolic byproducts while the other contained only the metabolic byproducts. The columns were imaged with X-ray computed microtomography (CMT) after water flooding, and after MEOR, which allowed for the evaluation of the pore-scale processes taking place during MEOR. Results indicate that the larger residual oil blobs and residual oil held under relatively low capillary pressures were the main fractions recovered during MEOR. Residual oil saturation, interfacial curvatures, and oil blob sizes were measured from the CMT images and used to develop a conceptual model for MEOR in fractional-wet systems. Overall, results indicate that MEOR was effective at recovering oil from fractional-wet systems with reported additional oil recovered (AOR) values between 44 and 80%; the highest AOR values were observed in the most oil-wet system.     

1D Simulations for Microbial Enhanced Oil Recovery with Metabolite Partitioning

We have developed a mathematical model describing the process of microbial enhanced oil recovery (MEOR). The one-dimensional isothermal model comprises displacement of oil by water containing bacteria and substrate for their feeding. The bacterial products are both bacteria and metabolites. In the context of MEOR modeling, a novel approach is partitioning of metabolites between the oil and the water phases. The partitioning is determined by a distribution coefficient. The transfer part of the metabolite to oil phase is equivalent to its ”disappearance,” so that the total effect from of metabolite in the water phase is reduced. The metabolite produced is surfactant reducing oil–water interfacial tension, which results in oil mobilization. The reduction of interfacial tension is implemented through relative permeability curve modifications primarily by lowering residual oil saturation. The characteristics for the water phase saturation profiles and the oil recovery curves are elucidated. However, the effect from the surfactant is not necessarily restricted to influence only interfacial tension, but it can also be an approach for changing, e.g., wettability. The distribution coefficient determines the time lag, until residual oil mobilization is initialized. It has also been found that the final recovery depends on the distance from the inlet before the surfactant effect takes place. The surfactant effect position is sensitive to changes in maximum growth rate, and injection concentrations of bacteria and substrate, thus determining the final recovery. Different methods for incorporating surfactant-induced reduction of interfacial tension into models are investigated. We have suggested one method, where several parameters can be estimated in order to obtain a better fit with experimental data. For all the methods, the incremental recovery is very similar, only coming from small differences in water phase saturation profiles. Overall, a significant incremental oil recovery can be achieved, when the sensitive parameters in the context of MEOR are carefully dealt with.     

Imbibition of Anionic Surfactant Solution into Oil-Wet Capillary Tubes

The displacement of oil by anionic surfactant solutions in oil-wet horizontal capillary tubes is studied. The position of the oil–water interface is recorded with time. The surfactant solution used is a mixture of several different surfactants and co-solvents tailored to produce ultra-low interfacial tension (IFT) for the specific oil used in the study. The surfactant solution results in ultra-low IFT at optimum salinity and room temperature. Several experimental parameters including the capillary tube radius and surfactant solution viscosity are varied to study their effect on the interface speed. Two different models are used to predict the oil–water interface position with time. In the first model, it is assumed that the IFT is constant and ultra-low throughout the experiments. The second model involves change of wettability and IFT by adsorption of surfactant molecules to the oil–water interface and the solid surface. Comparing the predictions to the experimental results, it is observed that the second model provides a better match, especially for smaller capillary tubes. The model is then used to predict the imbibition rate for very small capillary tubes, which have equivalent permeability close to oil reservoirs. The results show that the oil displacement rate is limited by the rate of diffusion of surfactants to the interface.     

Experimental Investigation of Synergy of Components in Surfactant/Polymer Flooding Using Three-Dimensional Core Model

Surfactant/polymer (SP) floods have significant potentials to recover remaining oil after water flooding. Their efficiency can be maximized by fully utilizing synergistic effect of polymer and surfactant. Various components adsorbed on the rock matrix due to chromatographic separation can significantly weaken the synergistic effect. Due to scale and dimensional problems, it is hard to investigate chromatographic separation among various components using one-dimensional natural cores. This study compared the adsorption difference between artificial and natural cores and developed a three-dimensional artificial core model of a 1/4 5-spot configuration to simulate oil recovery in multilayered reservoirs with high, middle and low permeability for each layer. Sampling wells were established to monitor pressures, and effluent fluids were acquired to measure interfacial tension (IFT) and viscosity. Then, distances of synergy of polymer and surfactant in three layers were evaluated. Meanwhile, electrodes were set in the model to measure oil saturation variation with resistance changes at different locations. Through comparison with IFT values, the contribution of improved swept volume and oil displacement efficiency to oil recovery during SP flooding could be known. Results showed that injected 0.65 PV of SP could improve oil recovery by 21.56% when water cut reached 95% after water flooding. The retention ratio of polymer viscosity was kept 55.3% at the outlet, but IFT was only 2 mN/m within the 3/10 injector–producer spacing during SP injection. Although subsequent water flooding could result in surfactant desorption and the IFT became 10^?2?mN/m within the 3/10 injector–producer spacing, the IFT turned to 2?mN/m at the half of the model. The enhanced displacement efficiency by reducing IFT only worked within three-tenth location of the model in the high permeability layer, while the enlarged swept volume contributed much in the other areas.

     

Impact of Rock Heterogeneity on Interactions of Microbial-Enhanced Oil Recovery Processes

Residual oil saturation reduction and microbial plugging are two crucial factors in microbial-enhanced oil recovery (MEOR) processes. In our previous study, the residual saturation was defined as a nonlinear function of the trapping number, and an explicit relation between the residual oil saturation and the trapping number was incorporated into a fully coupled biological (B) and hydrological (H) finite element model. In this study, the BH model is extended to consider the impact of rock heterogeneity on microbial-enhanced oil recovery phenomena. Numerical simulations of core flooding experiments are performed to demonstrate the influences of different parameters controlling the onset of oil mobilization. X-ray CT core scans are used to construct numerical porosity-permeability distributions for input to the simulations. Results show clear fine-scale fingering processing, and that trapping phenomena have significant effects on residual oil saturation and oil recovery in heterogeneous porous media. Water contents and bacterial distributions for heterogeneous porous media are compared with those for homogenous porous media. The evolution of the trapping number distribution is directly simulated and visualized. It is shown that the oil recovery efficiency of EOR/MEOR will be lower in heterogeneous media than in homogeneous media, largely due to the difficulty in supplying surfactant to unswept low-permeability zones. However, MEOR also provides efficient plugging along high-permeability zones which acts to increase sweep efficiency in heterogeneous media. Thus, MEOR may potentially be more suited for highly heterogeneous media than conventional EOR.     

Simulations of Microbial-Enhanced Oil Recovery: Adsorption and Filtration

In the context of microbial-enhanced oil recovery (MEOR) with injection of surfactant-producing bacteria into the reservoir, different types of bacteria attachment and growth scenarios are studied using a 1D simulator. The irreversible bacteria attachment due to filtration similar to the deep bed filtration (DBF) is examined along with the commonly used reversible equilibrium adsorption (REA). The characteristics of the two models are highlighted. The options for bacteria growth are the uniform growth in both phases and growth of attached bacteria only. It is found that uniform growth scenario applied to filtration model provides formation of two oil banks during recovery. This feature is not reproduced by application of REA model or DBF with growth in attached phase. This makes it possible to select a right model based on the qualitative analysis of the experimental data. A criterion is introduced to study the process efficiency: the dimensionless time at which average recovery between pure water injection and maximum surfactant effect is reached. This characteristic recovery period (CRP) was studied as a function of the different MEOR parameters such as bacterial activity, filtration coefficients, and substrate injection concentrations. For both growth scenarios, there is a zone of optimal activity at which the CRP is minimal. Dependence of the CRP on substrate concentration for uniform growth scenario has also an optimal zone. Therefore, growth rate and the substrate concentration should be above a certain threshold value and still not be too high to obtain the minimum CRP. On the other hand, no such zone was found if the bacteria could grow only in the attached phase. Dependencies on both the injected concentration and filtration coefficient are monotonous in this case.     

Adsorption–Desorption of Surfactant for Enhanced Oil Recovery

Surfactant loss due to adsorption on the porous medium of an oil reservoir is a major concern in enhanced oil recovery. Surfactant loss due to adsorption on the reservoir rock weakens the effectiveness of the injected surfactant in reducing oil–water interfacial tension (IFT) and making the process uneconomical. In this study, surfactant concentrations in the effluent of the corefloods and oil–water IFT were determined under different injection strategies. It was found that in an extended waterflood following a surfactant slug injection, surfactant desorbed in the water phase. This desorbed surfactant lasted for a long period of the waterflood. The concentration of the desorbed surfactant in the extended waterflood was very low but still an ultralow IFT was obtained by using a suitable alkali. Coreflood results show an additional recovery of 13.3% of the initial oil in place was obtained by the desorbed surfactant and alkali. Results indicate that by utilizing the desorbed surfactant during the extended waterflood operation the efficiency and economics of the surfactant flood can be improved significantly.     

Matrix–Fracture Transfer through Countercurrent Imbibition in Presence of Fracture Fluid Flow

Although a lot of research has been done in modeling the oil recovery from fractured reservoirs by countercurrent imbibition, less attention has been paid to the effect of the fracture fluid velocity upon the rate of oil recovery. Experiments are conducted to determine the effect of fracture flow rate upon countercurrent imbibition. A droplet detachment model is proposed to derive the effective water saturation in a thin boundary layer at the matrix–fracture interface. This effective boundary water saturation is a function of fluid properties, fluid velocity in the fracture and fracture width. For a highly water–wet porous medium, this model predicts an increase in the boundary water saturation with increase in fracture fluid velocity. The increase in boundary water saturation, in turn, increases the oil recovery rate from the matrix, which is consistent with the experimental results. The model also predicts that the oil recovery rate does not vary linearly with the boundary water saturation.     

Direct numerical simulation of water droplet coalescence in the oil

Coalescence of two water droplets in the oil was simulated using Computational Fluid Dynamics (CFD) techniques. The finite volume numerical method was applied to solve the Navier–Stokes equations in conjunction with the Volume of Fluid (VOF) approach for interface tracking. The effects of some parameters consisting of the collision velocity, off-center collision parameter, oil viscosity and water–oil interfacial tension on the coalescence time were investigated. The simulation results were validated against the experimental data available in the literature. The results revealed that quicker coalescence could be achieved if the head-on collisions occur or the droplets approach each other with a high velocity. In addition, low oil viscosities or large water–oil interfacial tensions cause less coalescence time. Moreover, a correlation was developed to predict coalescence efficiency as a function of the mentioned parameters.     

An Experimental Study of the Influence of Interfacial Tension on Water–Oil Two-Phase Relative Permeability

Adding surfactant into the displacing aqueous phase during surfactant-enhanced aquifer remediation of NAPL contamination and in chemical flooding oil recovery significantly changes interfacial tension (IFT) (σ) on water–oil interfaces within porous media. The change in IFT may have a large impact on relative permeability for the two-phase flow system. In most subsurface flow investigations, however, the influence of IFT on relative permeability has been ignored. In this article, we present an experimental study of two-phase relative- permeability behavior in the low and more realistic ranges of IFT for water–oil systems. The experimental work overcomes the limitations of the existing laboratory measurements of relative permeability (which are applicable only for high ranges of IFT (e.g., σ > 10⁻² mN/m). In particular, we have (1) developed an improved steady-state method of measuring complete water–oil relative permeability curves; (2) proven that a certain critical range of IFT exists such that IFT has little impact on relative permeability for σ greater than this range, while within the range, relative permeabilities to both water and oil phases will increase with decreasing IFT; and (3) shown that a functional correlation exists between water–oil two-phase relative permeability and IFT. In addition, this work presents such correlation formula between water–oil two-phase relative permeability and IFT. The experimental results and proposed conceptual models will be useful for quantitative studies of surfactant-enhanced aquifer remediation and chemical flooding operations in reservoirs.     

Visualisation of Residual Oil Recovery by Near-miscible Gas and SWAG Injection Using High-pressure Micromodels

We present results of high-pressure micromodel visualizations of pore-scale fluid distribution and displacement mechanisms during the recovery of residual oil by near-miscible hydrocarbon gas and SWAG (simultaneous water and gas) injection under conditions of very low gas–oil IFT (interfacial tension), negligible gravity forces and water-wet porous medium. We demonstrate that a significant amount of residual oil left behind after waterflooding can be recovered by both near-miscible gas and SWAG injection. In particular, we show that in both processes, the recovery of the contacted residual oil continues behind the main gas front and ultimately all of the oil that can be contacted by the gas will be recovered. This oil is recovered by a microscopic mechanism, which is strongly linked to the low IFT between the oil and gas and to the perfect spreading of the oil over water, both of which occur as the critical point of the gas–oil system is approached. Ultimate oil recovery by near-miscible SWAG injection was as high as near-miscible gas injection with SWAG injection using much less gas compared to gas injection. Comparison of the results of SWAG experiments with two different gas fractional flow values (SWAG ratio) of 0.5 and 0.2 shows that fractional flow of the near-miscible gas injected simultaneously with water is not a crucial factor for ultimate oil recovery. This makes SWAG injection an attractive IOR (improved oil recovery) process especially for reservoirs, where continuous and high-rate gas injection is not possible (e.g. due to supply constraint).     

Mechanisms Involved in Microbially Enhanced Oil Recovery

Microbial enhanced oil recovery (MEOR) represents a possible cost-effective tertiary oil recovery method. Although the idea of MEOR has been around for more than 75 years, even now little is known of the mechanisms involved. In this study, Draugen and Ekofisk enrichment cultures, along with Pseudomonas spp. were utilized to study the selected MEOR mechanisms. Substrates which could potentially stimulate the microorganisms were examined, and l-fructose, d-galacturonic acid, turnose, pyruvic acid and pyruvic acid methyl ester were found to be the best utilized by the Ekofisk fermentative enrichment culture. Modelling results indicated that a mechanism likely to be important for enhanced oil recovery is biofilm formation, as it required a lower in situ cell concentration compared with some of the other MEOR mechanisms. The bacterial cells themselves were found to play an important role in the formation of emulsions. Bulk coreflood and flow cell experiments were performed to examine MEOR mechanisms, and microbial growth was found to lead to possible alterations in wettability. This was observed as a change in wettability from oil wet (contact angle 154°) to water wet (0°) due to the formation of biofilms on the polycarbonate coupons.     

Theoretical Development of a Novel Equation for Dynamic Spontaneous Imbibition with Variable Inlet Saturation and Interfacial Coupling Effects

In oil recovery from fractured reservoirs, dynamic spontaneous imbibition (DSI) plays an important role. Conventional equations used for characterizing dynamic spontaneous imbibition neglect the effects of the driving forces acting across the wetting and non-wetting phases which are flowing in opposite directions. Such effects, defined as interfacial coupling effects (ICE), are known to cause a decrease in the calculated flow rate in drainage processes. Moreover, none of the numerical models have considered a variable inlet saturation (S*) for DSI. A new theoretical model has been developed using generalized transport equations to describe dynamic spontaneous imbibition for immiscible two-phase flow processes. The inclusion of interfacial coupling effects provides a more accurate way to describe dynamic spontaneous imbibition. Furthermore, the addition of variable inlet saturation allows one to establish whether the inlet-face saturation (S*) increases from the initial saturation to 1−Sro, or whether it can remain constant and equal to one minus the residual saturation to the non-wetting phase (1−Sro).     

Modeling Kinetic Interphase Mass Transfer for Two-Phase Flow in Porous Media Including Fluid–Fluid Interfacial Area

Interphase mass transfer in porous media takes place across fluid–fluid interfaces. At the field scale, this is almost always a kinetic process and its rate is highly dependent on the amount of fluid–fluid interfacial area. Having no means to determine the interfacial area, modelers usually either neglect kinetics of mass transfer and assume local equilibrium between phases or they estimate interfacial area using lumped parameter approaches (in DNAPL pool dissolution) or a dual domain approach (for air sparging). However, none of these approaches include a physical determination of interfacial area or accounts for its role for interphase mass transfer. In this work, we propose a new formulation of two-phase flow with interphase mass transfer, which is based on thermodynamic principles. This approach comprises a mass balance for each component in each phase and a mass balance for specific interfacial area. The system is closed by a relationship among capillary pressure, interfacial area, and saturation. We compare our approach to an equilibrium model by showing simulation results for an air–water system. We show that the new approach is capable of modeling kinetic interphase mass exchange for a two-phase system and that mass transfer correlates with the specific interfacial area. By non-dimensionalization of the equations and variation of Peclet and Damköhler number, we make statements about when kinetic interphase mass transfer has to be taken into account by using the new physically based kinetic approach and when the equilibrium model is a reasonable simplification.     

Kinetics of thermally induced swelling of hydrogels

We present a continuum model for thermally induced volume transitions in stimulus–responsive hydrogels (SRHs). The framework views the transition as proceeding via the motion of a sharp interface separating swollen and collapsed phases of the underlying polymer network. In addition to bulk and interfacial force and energy balances, our model imposes an interfacial normal configurational force balance. To account for the large volume changes exhibited by SRHs during actuation, the governing equations are developed in the setting of finite-strain kinematics. The numerical approximations to the coupled thermomechanical equations are obtained with an extended finite element/level-set method. The solution strategy involves a non-standard operator split and a simplified version of the level-set update. A number of representative problems are considered to investigate the model and compare its predictions to experimental observations. In particular, we consider the thermally induced swelling of spherical and cylindrical specimens. The stability of the interface evolution is also examined.     

Sensitivity Analysis for Dynamic Spontaneous Imbibition with Variable Inlet Saturation and Interfacial Coupling Effects

Dynamic spontaneous imbibition (DSI) plays an important role in oil reservoir characterization. Conventional equations used to characterize DSI consider neither interfacial coupling effects (ICE) nor variable inlet saturation (S*) for DSI. Yazzan et?al. (Transp Porous Media 87(1):309?C333, 2011a; 86(3):705?C717, 2011b) developed a set of equations, and a numerical solution scheme, to take into account ICE and variable S* for DSI. Based on these, a graphical user interface (GUI) simulator was built. A sensitivity analysis has been conducted to study the effect of the fluid and rock properties on DSI. The results reveal that including a variable S* has no significant impact; however, neglecting ICE results in an overestimation of the imbibition flow rate. Moreover, it is shown that the capillary and relative permeability curves determine the type of frontal advance, and that the imbibition recovery is proportional to the square root of time.     

Multiphase flow with a simplified model for oil entrapment

A computationally simple procedure is described to model effects of oil entrapment on three-phase permeability-saturation-capillary pressure relations. The model requires knowledge of airwater saturation-capillary pressure relations, which are assumed to be nonhysteretic and are characterized by Van Genuchten's parametric model; scaling factors equal to the ratio of water surface tension to oil surface tension and to oil-water interfacial tension; and the maximum oil (also referred to as nonwetting liquid in a three-phase medium) saturation which would occur following water flooding of oil saturated soil. Trapped nonwetting liquid saturation is predicted as a function of present oil-water and air-oil capillary pressures and minimum historical water saturation since the occurrence of oil at a given location using an empirically-based algorithm. Oil relative permeability is predicted as a simple function of apparent water saturation (sum of actual water saturation and trapped oil saturation) and free oil saturation (difference between total oil and trapped oil saturation), and water relative permeability is treated as a unique function of actual water saturation. The proposed method was implemented in a two-dimensional finite-element simulator for three-phase flow and component transport, MOFAT. The fluid entrapment model requires minimal additional computational effort and computer storage and is numerically robust. The applicability of the model is illustrated by a number of hypothetical one- and two-dimensional simulations involving infiltration and redistribution with changes in water-table elevations. Results of the simulations indicate that the fraction of a hydrocarbon spill that becomes trapped under given boundary conditions increases as a nonlinear function of the maximum trapped nonwetting liquid saturation. Dense organic liquid plumes may exhibit more pronounced effects of entrapment due to the more dynamic nature of flow, even under static water table conditions. Disregarding nonwetting fluid entrapment may lead to significant errors in predictions of immiscible plume migration.     

Chemically induced swelling of hydrogels

We consider a continuum model for chemically induced volume transitions in hydrogels. Consistent with experimental observations, the model allows for a sharp interface separating swelled and collapsed phases of the underlying polymer network. The polymer chains are treated as a solute with an associated diffusion potential and their concentration is assumed to be discontinuous across the interface. In addition to the standard bulk and interfacial equations imposing force balance and solute balance, the model involves a supplemental interfacial equation imposing configurational force balance. We present a hybrid eXtended-Finite-Element/Level-Set Method for obtaining approximate solutions to the governing equations of the model. As an application, we consider the swelling of a spherical specimen whose boundary is traction-free and is in contact with a reservoir of uniform chemical potential. Our numerical results exhibit good qualitative comparison with experimental observations and predict characteristic swelling times that are proportional to the square of the specimen radius. Our results also suggest several possible synthetic pathways that might be pursued to engineer hydrogels with optimal response times.     

EM Heating-Stimulated Water Flooding for Medium–Heavy Oil Recovery

We report a study of heavy oil recovery by combined water flooding and electromagnetic (EM) heating at a frequency of 2.45 GHz used in domestic microwave ovens. A mathematical model describing this process was developed. Model equations were solved, and the solution is presented in an integral form for the one-dimensional case. Experiments consisting of water injection into Bentheimer sandstone cores, either fully water saturated or containing a model heavy oil, were also conducted, with and without EM heating. Model prediction was found to be in rather good agreement with experiments. EM energy was efficiently absorbed by water and, under dynamic conditions, was transported deep into the porous medium. The amount of EM energy absorbed increases with water saturation. Oil recovery by water flooding combined with EM heating was up to \(37.0\%\) larger than for cold water flooding. These observations indicate that EM heating induces an overall improvement in the mobility ratio between the displacing water and the displaced heavy oil.