Relative Permeability Curves Research Articles

Determination of relative permeability curve under combined effect of polymer and surfactant

Relative permeability of surfactant-polymer (SP) flooding is determined by an inversion method based on numerical simulation and unsteady-state coreflooding experiment. Compared with the common methods, this method is more time-saving and simpler than steady-state method, and considers more physicochemical properties (adsorption and diffusion) of SP than unsteady-state method based on Buckley-Leverett theory. It is also more applicable to reservoir engineering than pore-scale simulation. After the reliability is confirmed, the superiority of the method is strongly proved by studying the influence of adsorption and diffusion of SP on relative permeability. Comparing relative permeability with and without effect of adsorption and diffusion of SP, the findings show adsorption and diffusion of SP significantly reduce the average inversion error of relative permeability curve from 11.9 to 3.7 for oil and from 10.7 to 1.8 for water. On this basis, the variations of SP-flooding relative permeability under the effect of polymer and surfactant are discussed in turn. In the existing researches, the quantitative characterization of variation of SP-flooding relative permeability curves is limited by curve crossing and endpoint saturation changes. In this work, normalized relative permeability is introduced to eliminate the adverse effect caused by curve crossing and endpoint saturation changes. The findings show that although the rise of aqueous-phase viscosity reduces water relative permeability, it has little effect on normalized water relative permeability. Normalized oil and water relative permeability increase in logistic functions with the decrease of IFT in semi-logarithmic plot. Water relative permeability at residual oil endpoint decreases linearly as aqueous-phase viscosity increases, and increases exponentially as IFT decreases in semi-logarithmic plot. Ultimately, the functional models based on normalized relative permeability and cubic B-spline are built through multiple regression, which can calculate relative permeability of SP flooding in term of IFT and aqueous-phase viscosity.

Influence of capillary pressure boundary conditions and hysteresis on CO2-water relative permeability

This study examines the effect of capillary pressure boundary conditions and hysteresis on CO2-water relative permeability. We perform drainage and imbibition injections into a Berea sandstone core and a sintered glass core. The cores receive three injection stages: water, then water-saturated CO2 representing drainage, and finally CO2-saturated water representing imbibition. Pressure difference and fluid production are recorded. To generate relative permeability using these data, we propose that the conventional Johnson–Bossler–Naumann (JBN) method be modified to incorporate capillary pressure boundary conditions. We then compare the results yielded by the JBN and modified-JBN methods, which generate relative permeability for post-breakthrough water saturation. To generate relative permeability for all states of saturation, history matching is used, in which the relative permeability of a numerical model is tuned until the simulated data match the experimental data.For drainage, history-matched relative permeability curves are found to be significantly closer to modified-JBN estimates than to JBN estimates. This indicates that the proposed modified-JBN method can provide a more accurate initial guess for history matching. In addition, using the initial guess generated by modified-JBN is found to reduce the chance of non-unique history-matched relative permeability curves.For imbibition, the CO2-water relative permeability curve is generated directly from history matching because the experimental data are too sparse to apply the JBN or modified-JBN method. Both CO2 and water imbibition relative permeability are found to differ from the drainage relative permeabilities. This so-called relative permeability hysteresis is attributed to contact angle hysteresis. In addition, imbibition CO2-water relative permeability is found to be sensitive to imbibition capillary pressure boundary conditions.

A numerical study of the effects of temperature and injection velocity on oil-water relative permeability for enhanced oil recovery

The paper quantitatively explore the influence of injection rate and temperature on oil-water relative permeability curves during hot water flooding operations in a porous medium flow. ANSYS-CFD was used to construct a numerical model of hot-water injection into an oil saturated sandstone core sample. The modelling technique is based on the Eulerian-Mixture model, using a 3D cylindrical core sample with known inherent permeability and porosity. Injection water at 20 °C was injected into a core sample that was kept at 63 °C and had 14-mD permeability and 26% porosity. For the investigation, three distinct injection rates of 2.9410–6 m/s, 4.41 × 10−6 m/s, and 5.88 × 10−6 m/s were utilised. Furthermore, same injection procedures were repeated under the same conditions, but the core temperature was changed to 90 °C, allowing us to quantify the influence of temperature on the relative permeability curves of oil-water immiscible flow.The results of this study show that the relative permeability of oil is strongly influenced by flow, while the effect of the relative permeability of water is negligible. In addition, the flow rate influences the residual oil and water saturation, as well as the associated effective permeability. From 20 to 90 °C there is little sensitivity to relative permeability or temperature. This study does not provide proof that temperature effects do not exist with genuine reservoir fluids, rocks, and temperature ranges. However, this study has demonstrated the feasibility of utilising CFD approaches to estimate fluid relative permeability, as well as the combined influence of temperature change and flow rate on relative permeability, with the potential for considerable cost-time advantages.

Scale Up of Pore-Network Models into Reservoir Scale: Optimization of Inflow Control Devices Placement

Summary Improvements to more advanced tools, such as inflow control devices (ICDs), create a high drawdown regime close to wellbores. Gas liberation within the formation occurs when the drawdown pressure is reduced below the bubblepoint pressure, which in turn reduces oil mobility by reducing its relative permeability, and potentially reducing oil flow. The key input in any reservoir modeling to compare the competition between gas and liquid flow toward ICDs is the relative permeability of different phases. Pore-network modeling (PNM) has been used to compute the relative permeability curves of oil, gas, and water based on the pore structure of the formation. In this paper, we explain the variability of pore structure on its relative permeability, and for a similar formation and identical permeability, we explain how other factors, such as connectivity and throat radius distribution, can vary the characteristic curves. By using a boundary element method, we also incorporate the expected relative permeability and capillary pressure curves into the modeling. The results show that such variability in the pore network has a less than 10% impact on production gas rates, but its effect on oil production can be significant. Another important finding of such modeling is that providing the PNM-created relative permeabilities may provide totally different direction on setting the operational constraints. For example, in the case studied in this paper, PNM-created relative permeability curves suggest that a reduction of flowing bottomhole pressure (FBHP) increases the oil rate, but for the case modeled with a Corey correlation, changes in FBHP will not create any uplift. The results of such work show the importance of PNM in well completion design and probabilistic analysis of the performance, and can be extended based on different factors of the reservoir in future research. Although PNM has been widely used to study the multiphase flow in porous media in academia, the application of such modeling in reservoir and production engineering is quite narrow. In this study, we develop a framework that shows the general user the importance of PNM simulation and its implementation in day-to-day modeling. With this approach, the PNM can be used not just to provide relative permeability or capillary pressure curves on a core or pore- scale, but to preform simulations at the wellbore or reservoir scale as well to optimize the current completions.

Development of Decline Curve Analysis Parameters for Tight Oil Wells Using a Machine Learning Algorithm

To obtain a reliable production forecast, one has to establish a geological model with well logs and seismic data. The geological model usually has to be upscaled using certain upscaling techniques. Then, a dynamic reservoir model is constructed with another dataset, including completion data, production data, fluid properties, and relative permeability curves. At last, the dynamic model needs to be validated by a history matching process. This approach is data-intensive, time-consuming, and often not rigorously accomplished due to the lack of skillset and time. In this study, 10,000 groups of reservoir/completion input data were generated by Latin hypercube sampling method, and then, 10,000 groups of output (oil rate and cumulative production data) were obtained by numerical simulation. Next, a machine learning technique was applied to establish a model between the input data and determining parameters of a decline curve analysis model by fitting the generated cumulative production rate. Overall coefficients of determination ( R 2 ) of the three Arps decline curve factors were 0.966, 0.990, and 0.945. The validation result shows that the production rate and cumulative production predicted by the proposed machine learning–decline curve analysis (ML-DCA) model agreed well with those simulated by reservoir simulation. As a result of the ML-DCA regression model, a complete understanding can be established of the impact of reservoir properties on the DCA model. The proposed ML-DCA model not only provides a quick and robust method for petroleum engineers to estimate production performance for unconventional reservoirs from reservoir and completion properties without full-field geocellular modeling but also can be used to optimize the completion and operation parameters for wells of interest.

Bubble Dynamics in Stationary Two-phase Flow Through Disordered Porous Media

Two-phase flow through porous media leads to the formation of drops and fingers, which eventually break and merge or may be trapped behind obstacles. This complex dynamical behavior highly influences macroscopic properties such as the effective permeability and it also creates characteristic fluctuations in the velocity fields of the two phases, as well as in their relative permeability curves. In order to better understand how the microscopic behavior of the flow affects macroscopic properties of two phases, we simulate the velocity fields of two immiscible fluids flowing through a two-dimensional porous medium. By analyzing the fluctuations in the velocity fields of the two phases, we find that the system is ergodic for large volume fractions of the less viscous phase and high capillary numbers Ca. We also see that the distribution of drop sizes m follows a power-law scaling, P(m)∝m−ξ. The exponent ξ depends on the capillary number. Below a characteristic capillary number, namely Ca* ≈ 0.046, the drops are large and cohesive with a constant scaling exponent ξ ≈ 1.23 ± 0.03. Above the characteristic capillary number Ca*, the flow is dominated by many small droplets and few finger-like spanning clusters. In this regime the exponent ξ increases approaching 2.05 ± 0.03 in the limit of infinite capillary number. Our analysis also shows that the temporal mean velocity of the entire mixture can be described by a generalization of Darcy’s law of the form v̄(m)∝(∇P)β where the exponent β is sensitive to the surface tension between the two phases. In the limit of infinite capillary numbers the mobility term increases exponentially with the saturation of the less viscous phase. This result agrees with previous observations for effective permeabilities found in dissolved-gas-driven reservoirs.

Impact of salinity and temperature variations on relative permeability and residual oil saturation in neutral-wet sandstone

Low-salinity water flooding has become one of the major emerging enhanced oil recovery techniques where lower salinity water is flooded into a hydrocarbon reservoir in order to increase oil recovery. It’s been widely reported that reservoir wettability alteration from oil-wet to water-wet in a low-salinity water process improves oil recovery. Many factors control system wettability, however, role and intensity of each factor is not completely understood. Therefore, several reported affecting factors on wettability alteration were eliminated in the present work in order to determine the impact of different low-salinity water on oil and water relative permeability curves and residual oil saturation. A series of experiments were performed where three simulated brine solutions were injected into oil saturated thoroughly cleaned neutral-wet sandstone core plugs. The effect of injected brine temperature on oil and water relative permeability curves and residual oil saturation was also determined by injecting 115,000 ppm salinity brine at three different temperatures. Results indicate that decreasing flooded water salinity alters the wettability preference of the rock towards favorable water-wetting conditions. Water-wet conditions decrease water mobility and enhance oil mobilization leading to better oil microscopic displacement efficiency and reduced residual oil saturation. Elevated temperature reduces water relative permeability and residual oil saturation. Cited as: Mahmud, W. M. Impact of salinity and temperature variations on relative permeability and residual oil saturation in neutral-wet sandstone. Capillarity, 2022, 5(2): 23-31. https://doi.org/10.46690/capi.2022.02.01

Study on the two-component gas apparent permeability model in shale nanopores considering Knudsen number correction

At present, the technology of carbon dioxide flooding shale gas is a hot topic for scholars. The numerical simulation of shale gas driven by carbon dioxide is inseparable from the accurate understanding of gas percolation mechanism and the construction of two-component gas motion equation. During the flooding process, the gas apparent permeability and the Knudsen number both change with time and space. However, this has not been fully discussed in previous studies. In this paper, the percolation mechanisms of two-component gas are discussed. On this basis, the calculation formula of Knudsen number in porous media is modified, and the transport equation of two-component gas is established. According to the derivation of apparent permeability, the two-component gas apparent permeability model is deduced. Then, the correction effect of Knudsen number and the related properties of two-component apparent permeability are analyzed. The results show that: (1) the effect of Knudsen number correction is significant at low pressure. Under high pressure, that is, when the pressure is greater than 10 MPa, the effect can be ignored; (2) the effect of Knudsen number correction is mainly significant in the range of medium pores, which is generally 10 nm–60 nm. And the peak value range decreases with the increase of pressure; (3) for the relative component apparent permeability curve, it has the properties of both relative permeability and apparent permeability. Based on the data in this paper, for the pressure change, it can be concluded that the maximum change rate of methane is 47.79% and that of carbon dioxide is 51.36%. For the change of pore size, it can be concluded that the maximum change rate of methane is 223.45% and that of carbon dioxide is 106.19%. It can be shown that the relative permeability of carbon dioxide is sensitive to pressure and the relative permeability of methane is sensitive to pore size.

Characterization of Two-Phase Flow from Pore-Scale Imaging Using Fractal Geometry under Water-Wet and Mixed-Wet Conditions

High resolution micro-computed tomography images for multiphase flow provide us an effective tool to understand the mechanism of fluid flow in porous media, which is not only fundamental to the understanding of macroscopic measurements but also for providing benchmark datasets to validate pore-scale modeling. In this study, we start from two datasets of pore scale imaging of two-phase flow obtained experimentally under in situ imaging conditions at different water fractional flows under water-wet and mixed-wet conditions. Then, fractal dimension, lacunarity and succolarity are used to quantify the complexity, clustering and flow capacity of water and oil phases. The results show that with the wettability of rock surface altered from water-wet to mixed-wet, the fractal dimension for the water phase increases while for the oil phase, it decreases obviously at low water saturation. Lacunarity largely depends on the degree of wettability alteration. The more uniform wetting surfaces are distributed, the more homogeneous the fluid configuration is, which indicates smaller values for lacunarity. Moreover, succolarity is shown to well characterize the wettability effect on flow capacity. The succolarity of the oil phase in the water-wet case is larger than that in the mixed-wet case while for the water phase, the succolarity value in the water-wet is small compared with that in the mixed-wet, which show a similar trend with relative permeability curves for water-wet and mixed-wet. Our study provides a perspective into the influence that phase geometry has on relative permeability under controlled wettability and the resulting phase fractal changes under different saturations that occur during multiphase flow, which allows a means to understand phase geometric changes that occur during fluid flow.

Experimental investigation and simulation for hybrid of nanocomposite and surfactant as EOR process in carbonate oil reservoirs

Numerous studies have been presented in the literature on the effect of the combination of nanoparticles and surfactants on enhanced oil recovery (EOR). In this study, we investigated the synergistic effect of synthesized Nanocomposite (ZnO@PAM) and surfactant on enhanced oil recovery by performing zeta potential (evaluation of chemicals stability in the aqueous phase), adsorption, wettability alteration (evaluation of the quantitative and qualitative wetness), and interfacial tension testes. In addition, to better understand how the fluid moves after chemicals flood in the porous medium, the Cartesian model was developed in CMG-STARS. Besides, this model is valid because of the history match of the oil recovery data, water cut data, and relative permeability curves. The Nanocomposite was physically synthesized from polyacrylamide polymers and zinc oxide nanoparticles under reflux conditions. The CMC surfactant point was obtained by examining various parameters (pH, density, electrical conductivity, and IFT). In the next step, we prepared nano-surfactant solutions (Nanocomposites with different concentrations of 100 ppm, 200 ppm, 500 ppm, and 1000 ppm + Surfactant (CMC)). By investigating the results of the adsorption and zeta potential tests, it was observed that the combinations of Surfactant and NCs have a positive effect on each other (increased nanoparticle stability and decreased surfactant adsorption on the carbonate rock surface). The Surfactant and Nano-Surfactant reduced the IFT from 29.16 to 0.176 (mN/m) and 1.354 (mN/m), respectively. In addition, the Surfactant at CMC and Nano-Surfactant (Surfactant (CMC) + NCs (500 ppm)) improve the contact angle in carbonate rock from 145.86 to 64° and 12.79°, respectively. After the core flooding by Surfactant and hybrid of NCs and Surfactant, we saw an increase of 17.94% and 30% in oil recovery compared to seawater floods, respectively. Furthermore, we observed the effect of mobility control and reduction of the fingering phenomenon after the flooding of chemicals by analyzing the simulated fluid distribution. By constructing the model in the core dimensions, we were able to get a good history matching from the laboratory data. Moreover, the mobility ratio after simultaneous flooding of NCs and surfactant compared to seawater decreased from 13.354 to 1.86, respectively. In addition, according to the fluid distribution pattern (one of the simulator outputs) the fingering phenomenon, was delayed after flooding the hybrid of NCs and surfactant. The positive effect of this type of chemical compound on mobility control and the fingering phenomenon has caused increased oil recovery. This study's findings can help to understand better how hybrid chemicals perform on improved oil recovery.

Numerical Investigation on Low-Salinity Augmented Microbial Flooding within a Sandstone Core for Enhanced Oil Recovery under Nonisothermal and pH Gradient Conditions

Summary In an era of increasing energy demand, declining oil fields, and fluctuating crude oil prices globally, most oil companies are looking forward to implementing cost-effective and environmentally sustainable enhanced oil recovery (EOR) techniques such as low salinity waterflooding (LSWF) and microbial EOR (MEOR). The present study numerically investigates the combined influence of simultaneous LSWF and microbial flooding for in-situ MEOR in tertiary mode within a sandstone core under spatiotemporally varying pH and temperature conditions. The developed black oil model consists of five major coupled submodels: nonlinear heat transport model; ion transport coupled with multiple ion exchange (MIE) involving uncomplexed cations and anions; pH variation with salinity and temperature; coupled reactive transport of injected substrates, Pseudomonas putida and produced biosurfactants with microbial maximum specific growth rate varying with temperature, salinity, and pH; relative permeability and fractional flow curve variations owing to interfacial tension (IFT) reduction and wettability alteration (WA) by LSWF and biofilm deposition. The governing equations are solved using finite difference technique. Operator splitting and bisection methods are adopted to solve the MIE-transport model. The present model is found to be numerically stable and agree well with previously published experimental and analytical results. In the proposed MIE-transport mechanism, decreasing injection water (IW) salinity from 2.52 to 0.32 M causes enhanced Ca2+ desorption rendering rock surface toward more water-wet. Consequently, oil relative permeability (kro) increases with >55% reduction in water fractional flow (fw) at water saturation of 0.5 from the initial oil-wet condition. Further reducing IW salinity to 0.03 M causes Ca2+ adsorption shifting the surface wettability toward more oil-wet, thus increasing fw by 52%. Formation water (FW) salinity showed minor impact on WA with <5% decrease in fw when FW salinity is reduced from 3.15 to 1.05 M. During low-salinity augmented microbial flooding (LSAMF), biosurfactant production is enhanced by >63% on reducing IW salinity from 2.52 to 0.32 M with negligible increase on further reducing IW and FW salinities. This might be owing to limiting nonisothermal condition (40 to 55°C), dispersion, sorption, and microbial decay. During LSAMF, maximum biosurfactant production occurs at microbial maximum specific growth rate of 0.53 h-1, mean fluid velocity of 2.63×10-3 m h-1 and initial oil saturation of 0.6, thus resulting in significant WA, increase in kro by >20%, and corresponding fw reduction by >84%. Moreover, the EOR efficiency of LSAMF is marginally impacted even on increasing the minimum attainable IFT by two orders of magnitude from 10-3 to 10-1 mN m-1. Though pH increased from 8.0 to 8.9, it showed minor impact on microbial metabolism. Formation damage owing to bioplugging observed near injection point causing increase in fw by ~26% can be mitigated by adopting suitable well-stimulation strategies during the LSAMF run time. The present study is a novel attempt to show synergistic effect of LSAMF over LSWF in enhancing oil mobility and recovery at core scale by simultaneously addressing complex crude oil-brine-rock (COBR) chemistry and critical thermodynamic parameters that govern MEOR efficiency within a typical sandstone formation. The present model with relatively lower computational cost and running time improves the predictive capability to preselect potential field candidates for successful LSAMF implementation.

Modified Johnson–Bossler–Naumann method to incorporate capillary pressure boundary conditions in drainage relative permeability estimation

A proposed modification of the Johnson–Bossler–Naumann (JBN) method incorporates capillary pressure at the inlet and outlet of a rock sample. The experimental runs are performed on Berea and Obernkriechner sandstone rock samples. Fluid is injected into Berea rock at capillary to viscous ratios 0.05, 0.1, 0.5, and 1 and into Obernkriechner rock at capillary to viscous ratios 0.05 and 0.25. Rock samples are initially saturated with 20 g/l NaCl water. The experimental observations are analyzed using classical JBN and our modified JBN. The latter's relative permeability curves are found to closely match those derived by applying history matching to a numerical model. This indicates that modified JBN can be used to provide an initial guess for history matching. We also show that accurate estimates of threshold capillary pressure are crucial to obtaining accurate oil relative permeability estimates. In contrast to those derived from the JBN method, modified JBN relative permeabilities are independent of capillary to viscous ratio or injection rate. • The proposed model incorporates capillary pressure at the inlet and outlet boundary. • Experiments are performed to validate the model. • Derived relative permeability curves are less sensitive to capillary number compared to classical methods.

Numerical study of the mud loss in naturally fractured oil layers with two-phase flow model

Drilling in the naturally fractured formations always encounters severe mud loss, which endangers the drilling safety. In oil & gas layers, a larger quantity of mud loss has great adverse effects on later oil and gas production. Therefore, it makes the knowledge of mud loss very important, and after that, it is instructive to control the mud loss in the oil layer. In this paper, we first consider the mud loss process using a two-phase flow model. A discrete fracture network model is employed to describe the fluid transfer between fractures and matrix pores. And different relative permeability curves and capillary pressure functions are used in matrix pores and natural fractures. The finite element method and “upwind” scheme are employed to deduce the numerical discretized formulas. The correctness of our model is verified with the published literature. Then a sensitivity analysis is performed to study the laws of mud loss in naturally fractured oil-wet formation. Compared with single-phase flow models, the mud loss rate of two-phase flow model is lower. The two-phase flow model is used to identify the most influential factors on mud loss and predict the distribution of water saturation in oil formation during the drilling process. We find that: since the pressure increase zone is much larger than the water saturation increase zone, the size of the water invasion zone is unknown in the single-phase flow model. The most important influential factors of mud loss in the oil layer are fracture connection, drilling fluid density and matrix permeability. Once the natural fractures are connected to the wellbore, the mud loss rate is much higher than that when the natural fractures are not connected to the wellbore. The capillary pressure has little effect on the mud loss. The larger the capillary pressure, and the lower the mud loss rate. The model in this paper is instructive to learn the law of mud loss and contamination range of drilling fluids in oil layers.

In-situ hydrogen wettability characterisation for underground hydrogen storage

Hydrogen storage in subsurface aquifers or depleted gas reservoirs represents a viable long-term energy storage solution. There is currently a scarcity of subsurface petrophysical data for the hydrogen system. In this work, we determine the wettability and Interfacial Tension (IFT) of the hydrogen-brine-quartz system using captive bubble, pendant drop and in-situ 3D micro-Computed Tomography (CT) methods. Effective contact angles ranged between 29° and 39° for pressures 6.89–20.68 MPa and salinities from distilled water to 5000 ppm NaCl brine. In-situ methods, novel to hydrogen investigations, confirmed the water-wet system with the mean of the macroscopic and apparent contact angle distributions being 39.77° and 59.75° respectively. IFT decreased with increasing pressure in distilled water from 72.45 mN/m at 6.89 MPa to 69.43 mN/m at 20.68 MPa. No correlation was found between IFT and salinity for the 1000 ppm and 5000 ppm brines. Novel insights into hydrogen wetting in multiphase environments allow accurate predictions of relative permeability and capillary pressure curves for large scale simulations. • Comprehensive characterisation of hydrogen-brine-quartz wettability. • Novel investigation of in-situ contact angle for underground hydrogen storage. • Contact angle on smooth rock surface 27–39° and at in situ conditions 39.77–59.75°. • Deficit curvature analysis confirms a water-wet system. • IFT from 72.45 mN/m at 6.89 MPa to 69.43 mN/m at 20.68 MPa.

A two-dimensional study on the impact of pore space connectivity on the immiscible two-phase flow in a water-wet, water–oil system under steady state conditions

Immiscible displacements in porous media are unquestionably of great significance in numerous natural and industrial processes. It has been well established and accepted that in addition to the immiscible fluid properties, the morphology of the porous medium also plays a significant role in the final volumetric throughput of a particular fluid. Topological features of the porous medium have been found to exert a strong influence on the hydrodynamic behaviour of single and two-phase flows as they express a measure of pore space and consequently flow path connectivity and availability. The current study investigates the effect of the pore space connectivity, expressed through the Euler characteristic, on the hydrodynamic behaviour of a water-wet, oil–water two-phase system at steady state. Two-dimensional simulations are conducted in artificially generated porous media with constant diameter circular solid grains using a multi-relaxation time lattice-Boltzmann model. It is shown that topological features of the porous medium can significantly affect the macro-scale capillary pressure and relative permeability curves for drainage and imbibition but in different ways. It is also demonstrated that pore space connectivity has a strong influence on the fluid phase distribution and fragmentation patterns in the porous structure depending on the displacement process.

An insight into core flooding experiment via NMR imaging and numerical simulation

Traditional core flooding experiments can only be used post breakthrough while what happens in the core prior to this time is vital to understand multiphase flow phenomenon for more successful EOR operations. We can overcome this obstacle through a visualized fluid displacement scheme. This can ultimately provide us with a reliable relative permeability curve that can lead to a more accurate reservoir simulation outcome in the field scale. In this study, NMR imaging is employed in a water flood experiment in conjunction with two separate numerical two-phase flow simulation methods (FDM and FEM), to reproduce experimental data. Using the Brooks-Corey equation, random pore size distribution indices (λ) are selected to generate relative permeability curves. Moreover, simulations are performed with FDM, and oil displacement efficiency, saturation maps, and saturation profiles are generated and compared to the experimental results. Next, FEM was employed in COMSOL for further validation and FDM results were found in agreement with the experiments. This way, an appropriate relative permeability curve was generated and assigned to the sample. Results suggest that λ of 0.2 generated the best numerical results with an MSE value of 0.009 in oil displacement efficiency curves, comparable to the experiments. Collectively, integration of imaging techniques with routine experimental fluid displacement procedures presented a detailed insight into complicated nature of multiphase flow phenomena in geomaterials.

Part 1: Oil displacement by foam injection in Hele-Shaw cell with a pattern of impermeable regions

Gas flooding is one of the most effective enhanced oil recovery (EOR) techniques. However, mobility control of the injected gas has always been an issue, especially for heterogeneous and fractured reservoirs. There is still a need to understand the phase interference (relative Permeability) and oil production from such heterogeneous and fractured systems. This study investigates the displacement of oil in a fractured system, conducted in a Hele-Shaw set up with a pattern of obstructions or impermeable regions. This 2D pattern is printed from an actual rock cross-section, obtained from high-resolution micro-computed tomography. Different displacement fluids were utilized, including water, gas, and foam in secondary and tertiary injection modes. Relative permeability curves were generated, which depict the interference between the phases flowing through the Hele-Shaw cell with tortuosity. The results showed that secondary foam injection is the most efficient technique as opposed to the other methods. Also, N2-foam achieves better recovery than air-foam, which is due to the solubility of N2 gas in the aqueous phase. This study provides more insight into foam flooding when high surfactant concentration is used. Under this condition, the effectiveness of foam injection compared to conventional water and gas injections is due to both emulsification and foam displacement effects.

Near miscible relative permeability curves in layered porous media- investigations via diffuse interface Lattice Boltzmann method

The relative permeability of immiscible multi-phase flow in Layered 2D porous media is investigated employing the diffuse interface Lattice Boltzmann model. The interfacial tension is set to small value to mimic the near miscible condition of the fluids. The model is validated with static and dynamic analytical solutions. Three classes of porous media are examined: A high permeable porous media, a low permeable porous media, and layered dual permeable porous media. For the later case, parallel and serie conditions were considered. For each condition, three proportion of layers were studied; I– 25% of the high permeable layer, II– 50% of the high permeable layer, and III– 75% of high permeable layer. For each condition, the viscous coupling effects due to viscosity ratio, the capillary number and the effect of the fluid patterns on the relative permeability curves were investigated. The simulation results showed very small errors compare with the analytical permeability solutions of layered porous media. The findings showed that despite the dual permeable serie system, the relative permeability curve of dual permeable parallel geometry is closely matched with the analytical solution.

Pore network modeling of oil and water transport in nanoporous shale with mixed wettability

Hydraulic fracturing is an effective means for the economic development of shale oil reservoirs. A large volume of water is introduced into the shale matrix during hydraulic fracturing, which leads to the subsequent oil-water two-phase flow in the shale reservoir. The fluid flow behaviors in shale are still ambiguous due to the nonnegligible nanoconfinement effect caused by the omnipresent nanoscale pores and the heterogeneities of mineral types, pore size and wettability of shale. In this study, both the single-phase and oil-water two-phase flow behaviors at pore-scale considering nanoconfinement effects, dual-wettability and pore space characteristic of shale reservoir were investigated using the pore network modeling (PNM) method. We constructed the three-dimension shale digital rock based on scanning electron microscope (SEM) images and extracted the pore network model. The modified single nanotube flow equations considering the adsorption and slip effects were incorporated with the shale pore network model to investigate the single-phase flow at different volumetric total organic content (TOC). Oil-water two-phase flow and relative permeability at different TOC in volume were computed by quasi-static method with consideration of nanoconfinement effect. Results indicated that the TOC and wettability are the primary factors affecting the single-phase flow in shale. Slip effect enhanced the flow capacities of both single-phase water and oil. The wettability effect on two-phase relative permeability curve was not as notable as that on single-phase flow. Oil-water two-phase relative permeability curves were significantly affected by TOC. The two-phase flow region narrows down with the increase of volume TOC, indicating more oil is trapped and thus cannot be displaced. This work provided important insights on pore-scale fluid transport behaviors in shale.

Productivity model with mechanisms of multiple seepage in tight gas reservoir

The productivity model with unilateral threshold pressure gradient, real gas effect or non-Darcy effect has been documented in the research of tight gas reservoir. However, the multiple seepage mechanisms are poorly addressed in a productivity model, especially the application of gas-water relative permeability curve changing with the displacement pressure. A novel productivity model of multi-stage fractured horizontal wells with mechanisms of multiple seepage was proposed the present study. Results show that the stress effect has a negative effect on the effective permeability, while the Knudsen diffusion effect of gas has a positive effect. The water flow can inhibit the gas flow in the tight gas reservoir, whose effect is more significant with larger displacement pressure differences. The higher initial water saturation and reservoir temperature, whereas the lower gas well productivity, contribute to a high gas well productivity in the reservoir of high pressure.