Oil-water Relative Permeability Research Articles

The research on high efficiency water injection development of carbonate rock reservoir in the middle east

More and more attention has been paid to the waterflood development of carbonate reservoir in the Middle East with continuous expansion of the scale of carbonate reservoir development. Strong non-homogeneity of carbonate reservoirs results in serious conflicts between injection and production, causing low degree of water-driven control in the well network, and low degree of vertical mobilization. This article takes the main reservoir of an oil field in the Middle East region as an example, combining geological evaluation, dynamic analysis, and reservoir development strategies to study the effectiveness of water injection development in carbonate reservoirs. It shows that there is a correlation between pore type, oil-water relative permeability, and development method in the development of carbonate reservoirs. For reservoirs with matrix pores and micropores, water injection should be strengthened in the later stage of development; for reservoirs with dissolved pores and coarse pores, the iso-permeability point is relatively high, and the later development should focus on balanced water injection. Three different waterflooding models for formation development are designed to verify the feasibility of fine waterflooding schemes. The main differences are that one set of well patterns is combined injection and production, and three sets of well patterns are layered system waterflooding. The results show that the development effect in layered system waterflooding is the best. The daily production can be increased by about 16%, the cumulative oil production can be increased by about 8%, and the recovery factor can be increased by about 3%. Eventually, the stable oil and water control of carbonate reservoir can be realized.

Numerical Simulation of Time-Varying Characteristics in a High-Permeability Sandstone Reservoir: A Case of Gaoqian Southern Area

In the process of long-term water flooding in the Gaoqian Southern Area with an average porosity of 30% and an average permeability of 1333.5×10−3 μm2, the fluid-solid interaction among oil, water, and rock has a great influence on the pore structure. It has resulted in changes in reservoir parameters with the extension of time. This paper used electron microscopy scanning, mercury injection, X-ray diffraction, physical properties, and oil-water relative permeability curves to study the variation of clay mineral content, pore throat structure, porosity, permeability, and relative permeability curves of high-permeability sandstone after high-pressure water flooding. The results showed that clay minerals such as montmorillonite and kaolinite were dissolved, hydrated, and migrated after long-term water flooding, which resulted in the decrease of clay mineral content in fine sandstone and medium sandstone, the increase of pore throat radius, and the decrease of displacement pressure, median pressure, and separation coefficient. The saturation of the isotonic point of the oil-water relative permeability curve was obviously shifted to the right, the hydrophilicity was significantly enhanced, and the porosity and permeability were effectively improved, but there was a blockage of the throat less than 2 μm in the fine sandstone. In addition, this paper established the equations of water injection, permeability, irreducible water saturation, residual oil saturation, and oil-water relative permeability curve coefficient and establishes the initial permeability model with the well data before water flooding. The logging interpretation results of development wells in the process of water flooding as verification data were used, and the relative error of permeability far lower than the general requirement of permeability error within an order of magnitude was less than 30%, which verified the rationality of the method.

Waterflood reservoir modelling for Chirag oilfield

This article describes the studies carried out to determine the impact of all available laboratory measured oil-water relative permeability data upon the predicted waterflood performance of the Chirag field of the GCA megastructure. Sector and cross-section models were built of the A-6, A-11 and A-13 area using appraisal well GCA-1 core data. A-6 is the first well in Chirag field to have cut water and is the best candidate well for calibrating the laboratory relative permeability data. Simulations using various wateroil relative permeability curves predicted a wide range of water breakthrough times for A-6 and A-11. It was not possible to obtain a good history match of A-6 water production from core relative permeability curves. Grid size sensitivities were studied using a cross-section model. The results show that optimisation of grid size gives an improved match to the actual field history. Static reservoir parameters and aquifer size were also found to have a major impact on the waterflood performance and by adjusting certain key parameters a good history match to the historic A-6 performance could be achieved with the optimised grid. Keywords: Chirag; relative permeability; simulation sensitivity; cross-section model; reservoir description; grid-size; water breakthrough time; history matching.

Investigation of oil/water two-phase flow behavior in laminated shale porous media considering heterogeneous structure and fluid-solid interaction

The laminated structure of continental shale oil reservoirs introduces significant macro and micro heterogeneity, posing challenges for efficient shale oil extraction. Existing microscopic experimental and simulation methods are insufficient to accurately simulate the fluid flow behavior in mud–lime interactive laminated shale reservoirs. This study delves into the complexities of laminated shale reservoirs with a focus on their heterogeneous structure and wettability. Using scanning electron microscopy, we extracted the structural features of laminated shale reservoirs and established a Multicomponent and multiphase -multi relaxation time-Lattice Boltzmann model(MCMP-MRT-LBM) that considers nanoscale effects such as wall adsorption, liquid–solid slippage, and liquid–liquid slippage. We investigated the occurrence state, the flow behavior, and the phase seepage characteristics of crude oil in laminated shale at different water saturation stages and explored the reasons behind interlayer channeling and the conditions under which crude oil is mobile within limestone and mudstone layers. Then, we examined the impact of varying factors, including heterogeneous wettability, displacement pressure gradients, and pore size, on relative permeability, water injection capacity, sweep efficiency, and crude oil recovery in laminated reservoirs. The results indicate that wettability and pore size distribution, driven by capillary and viscous forces, dictate the occurrence state of remaining oil. Wettability primarily influences fluid distribution, whereas pore size distribution substantially impacts fluid morphology. It also highlights the pivotal role of flow velocity differences between layers in causing interlayer channeling. Increasing the capillary number promotes crude oil mobility within mudstone layers, with the initiation pressure gradient in mudstone layers being 2.5 times that of the limestone layer. The examination of the oil–water relative permeability reveals the dominance of pressure gradients in affecting oil flow capabilities, while pore size significantly influences water flow capacity. By optimizing various factors, it is possible to enhance water injection capacity and sweep efficiency, resulting in a substantial 5%–10% increase in crude oil recovery from laminated shale reservoirs.

Effect of Displacement Pressure Gradient on Oil–Water Relative Permeability: Experiment, Correction Method, and Numerical Simulation

Relative permeability is a fundamental parameter affecting reservoir development performance analysis. During the development of oil and gas fields, the displacement pressure gradient changes with time and space. This paper studies the effect of displacement pressure gradient on relative permeability. The oil–water relative permeability curves of a Bohai Oilfield under different displacement pressure gradients are obtained through experimental analysis. Based on the experimental data, a correction model of the permeability curve is established by regression of the Willhite model parameters. The correction model is introduced into the black oil numerical simulation, and the production performance and remaining oil are compared and analyzed. The results show that the displacement pressure gradient can have an obvious impact on the relative permeability curve. As the displacement pressure gradient increases, the two-phase span of the relative permeability curve increases, the oil displacement efficiency increases, and the water relative permeability increases. The relative permeability curves under different displacement pressure gradients can be accurately characterized by the Willhite model. The consideration of the displacement pressure gradient has an obvious impact on numerical simulation results. The conventional method of using a fixed relative permeability curve cannot truly reflect the production performance and the remaining oil distribution. This paper proposes a set of realization methods including obtaining laws from experiments, utilizing the empirical model to correct, and simulating to characterize reservoir changes.

Numerical simulation of enhanced throughput of surfactant in Lamadian oilfield

Based on the actual data of Lamadian oilfield in terms of geological structure, reservoir fluid physical properties and production dynamics, a numerical simulation geological model of CMG STARS chemical flooding module is established, which is consistent with the static and dynamic characteristics of the oil reservoir. In order to study the effect of enhanced throughput of surfactants, based on the mechanism of enhanced throughput of surfactants, the numerical model was established by defining parameters such as oil-water interfacial tension at different concentrations, residual oil saturation, oil-water relative permeability curve, capillary pressure, isotonic point change and surfactant diffusion coefficient in the formation, etc. The numerical simulation of surfactant enhanced throughput was carried out to optimize the surfactant enhanced throughput parameters in Lamadian oilfield, and the sensitivity sequence of each injection and production parameter to the surfactant enhanced throughput and oil was determined. The final recommended injection and production parameters are surfactant injection amount (10000m3), injection concentration (0.5%) and brazing time (2d). It is predicted that the cumulative oil increase can reach 1310m3, the initial daily fluid production is controlled at 80m3/d, the daily oil production can be increased by 10m3/d, and the water cut can be reduced by 10%.

Modeling of multiphase flow in low permeability porous media: Effect of wettability and pore structure properties

Multiphase flow in low permeability porous media is involved in numerous energy and environmental applications. However, a complete description of this process is challenging due to the limited modeling scale and the effects of complex pore structures and wettability. To address this issue, based on the digital rock of low permeability sandstone, a direct numerical simulation is performed considering the interphase drag and boundary slip to clarify the microscopic water-oil displacement process. In addition, a dual-porosity pore network model (PNM) is constructed to obtain the water-oil relative permeability of the sample. The displacement efficiency as a recovery process is assessed under different wetting and pore structure properties. Results show that microscopic displacement mechanisms explain the corresponding macroscopic relative permeability. The injected water breaks through the outlet earlier with a large mass flow, while thick oil films exist in rough hydrophobic surfaces and poorly connected pores. The variation of water-oil relative permeability is significant, and residual oil saturation is high in the oil-wet system. The flooding is extensive, and the residual oil is trapped in complex pore networks for hydrophilic pore surfaces; thus, water relative permeability is lower in the water-wet system. While the displacement efficiency is the worst in mixed-wetting systems for poor water connectivity. Microporosity negatively correlates with invading oil volume fraction due to strong capillary resistance, and a large microporosity corresponds to low residual oil saturation. This work provides insights into the water-oil flow from different modeling perspectives and helps to optimize the development plan for enhanced recovery.

Micropore Throat Structure and Movable Fluid Characteristics of Chang 63 Tight Sandstone in Baibao Area of Ordos Basin

Tight sand is an important unconventional reservoir. Aiming at the problem of large unused reserves and the poor development effect of Chang 63 reservoir, this paper researches reunderstanding reservoir and evaluating unused reserves. Employing rock slice and scanning electron microscope (SEM), the experiment of low-field nuclear magnetic resonance (NMR), water-oil relative permeability experiment, reservoir space, movable fluid, and oil-water seepage characteristics was studied. The factors affecting NMR T 2 cutoff, controlling factors of movable fluids, and controlling factors of displacing efficiency in tight sandstone reservoirs are discussed. The study demonstrates that (1) the mean pore volume and permeability are 4.4% and 0.068 mD, respectively. The reservoir pertains to tight sandstone, mainly intergranular pore and dissolution pore, and the intercalated materials are mainly chlorite and illite. (2) The characteristic of the NMR T 2 spectrum has bimodal characteristics and can be subdivided into two classes: left peak dominant and right peak dominant. The mean value of mobile fluid saturation was 17.9%. (3) According to the relative permeability curve pattern, it is divided into four categories, and the mean bound water saturation is 29.9%. The average irreducible oil saturation was 40.6%. The mean oil flooding efficiency was 40.2%. (4) The better the pore-throat relationship, the lower the T 2 cutoff, the stronger ability of the fluid migration ability, and the higher of a percentage of active fluid. The percentage of active fluid in a low-permeability reservoir is affected by the reservoir’s physical property and pore structure.

A Novel Method for the Calculation of Oil–Water Relative Permeability for Tight Oil Reservoirs by Considering Nonlinear Seepage Characteristics

In view of the lack of clear physical significance of the parameters of the traditional nonlinear seepage models and the difficulty of obtaining accurate experimental measurements of the two-phase relative permeability curve, a nonlinear seepage model of a tight reservoir is established on the basis of fractal theory and boundary layer theory. The results show that the proposed model can comprehensively reflect the effects of reservoir matrix physical properties, reservoir fluid physical properties, wettability, and displacement-pressure gradient on the single-phase and two-phase nonlinear seepage characteristics of tight reservoirs. Furthermore, the introduction of the permeability loss factor makes the two-phase relative permeability model more representative of the morphological characteristics of the actual relative permeability curve and avoids the disadvantage that the relative permeability at the end point of the wetting phase has in the traditional model. Finally, by taking the tight core of Changqing Oilfield as an example, a sensitivity analysis of the proposed model is conducted, which proves the practical application of this model. The proposed model provides a convenient theoretical method for the accurate characterization of nonlinear seepage characteristics of tight reservoirs and is of great significance to the numerical simulation, productivity evaluation, and optimization of tight reservoirs.

An improved method for fitting relative permeability curve using nuclear magnetic resonance imaging

Nuclear magnetic resonance (NMR) technology can be used for online monitoring of the fluid flow in cores. Especially, NMR imaging can visualize the injected fluid distribution and the residual oil location, as well as show the displacement effects of different injected fluid. This provides a new perspective for understanding displacement mechanisms. This paper proposes an improved method for fitting relative permeability curve based on NMR imaging. We established formulas to quantitatively calculate the water saturation profiles at different displacement times. Using the water saturation profiles, the water front position, residual oil saturation, and capillary end effect were analyzed to visualize the fluid flow inside the core. Base on the water saturation distribution, we analyzed the waterflooding characteristics more accurately. Using the oil-water relative permeability equation proposed by Honaropur, the relationship between the water cut and water saturation at the outlet section of the core was fitted to obtain the oil-water relative permeability. Compared with the commonly used Johnson-Bossler-Naumann method for calculating relative permeability, the method proposed in this paper has fewer fitting parameters, is highly precise, and is easy to operate. Additionally, it also broadens the application of NMR technology in the field of oil exploration and development.

Research Progress on Factors Affecting Oil-Absorption Performance of Cement-Based Materials.

With the wide application of petroleum resources, oil substances have polluted the environment in every link from crude oil extraction to utilization. Cement-based materials are the main materials in civil engineering, and the study of their adsorption capacity for oil pollutants can expand the scope of functional engineering applications of cement-based materials. Based on the research status of the oil-wet mechanism of different kinds of oil-absorbing materials, this paper lists the types of conventional oil-absorbing materials and introduces their application in cement-based materials while outlining the influence of different oil-absorbing materials on the oil-absorbing properties of cement-based composites. The analysis found that 10% Acronal S400F emulsion can reduce the water absorption rate of cement stone by 75% and enhance the oil-absorption rate by 62%. Adding 5% polyethylene glycol can increase the oil-water relative permeability of cement stone to 1.2. The oil-adsorption process is described by kinetic and thermodynamic equations. Two isotherm adsorption models and three adsorption kinetic models are explained, and oil-absorbing materials and adsorption models are matched. The effects of specific surface area, porosity, pore interface, material outer surface, oil-absorption strain, and pore network on the oil-absorption performance of materials are reviewed. It was found that the porosity has the greatest influence on the oil-absorbing performance. When the porosity of the oil-absorbing material increases from 72% to 91%, the oil absorption can increase to 236%. In this paper, by analyzing the research progress of factors affecting oil-absorption performance, ideas for multi-angle design of functional cement-based oil-absorbing materials can be obtained.

Experimental Study on the Enhanced Oil Recovery Mechanism of an Ordinary Heavy Oil Field by Polymer Flooding.

It is widely known that in the water flooding development process of ordinary heavy oil, the fingering phenomenon is obvious, there are a lot of unswept areas, and absolutely, the recovery is really very low. In addition, for some shallow and thin ordinary heavy oil reservoirs limited by the geological conditions of the reservoir, the thermal recovery technology also has serious heat loss and high development cost. Therefore, there is an urgent need to transform the development and further improve the enhanced oil recovery (EOR). In this paper, the mechanism of EOR by polymer flooding was investigated for high-porosity and high-permeability terrestrial ordinary heavy oil reservoirs. Through laboratory experiments, we analyzed the characteristics of oil-water relative permeability curves, mobility control ability, and microscopic seepage characteristics during polymer flooding of ordinary heavy oil reservoirs. On this basis, the effect of the mobility ratio on seepage characteristics and the mechanism of EOR enhancement were clarified. The results show that the polymer can effectively improve the mobility control effect of the displacing fluid. As the polymer solution and ordinary heavy oil have the characteristics of high viscosity and low mobility, there is a minimum mobility ratio in the process of polymer flooding. Namely, the characteristics of dual low mobility exist in the process of polymer flooding for the ordinary heavy oil. It effectively enhances the profile control and plugging ability of the polymer, thus expanding the sweep volume of larger pores and improving the displacement efficiency of smaller pores. Based on the two factors mentioned above, it is found that the dual low mobility characteristics can improve the recovery of ordinary heavy oil by polymer flooding. Therefore, it is proposed that an enhanced profile control and plugging effect due to the dual low mobility characteristics is an important EOR mechanism for ordinary heavy oil development by polymer flooding.

Correct relative permeability data from steady-state experiments for capillary end effects

Water-oil relative permeability curves can be obtained from co-injection experiments at steady-state (SS) conditions. The two-phase Darcy's law can be used to calculate the relative permeability directly only when water saturation is constant along the core. However, the capillary end effect (CEE) causes water accumulation or depletion at the end of the core depending upon the wettability. This work modifies the Intercept Method initially proposed by Gupta and Maloney. Similar to their work, we again envisage carrying out a steady-state (SS) co-injection experiment. For each ratio of water to oil flowrate (F=qwqo), we require experiments at different total flowrates. From each run, we obtain pressure drop across the core and average water saturation inside the core.We demonstrate mathematically that a plot of average water saturation vs. reciprocal of oil flowrate gives a straight line whose intercept is the water saturation in the unaffected region. A plot of pressure difference vs. oil flowrate yields a straight line whose slope gives the oil relative permeability which can be used to calculate water relative permeability. It is necessary to perform the SS experiment at least three times for the same F=qwqo (at different oil/water rates). The same procedure is used for other values of F to obtain more data points to construct the relative permeability curves. An experimental step-by-step procedure for experimental engineers to follow is given in appendix C.

Comparing Centrifuge, Steady-State and Semi-Dynamic Methods for Relative Permeability and Capillary Pressure Determination: New Insights

Relative permeability and capillary pressure are essential parameters for understanding multiphase flow in porous media and scenarios of production in oil or gas reservoirs. There are several experimental methods for determining the relative permeability curves: unsteady-state (USS), steady-state (SS), and semi-dynamic (SD) methods. Each method has advantages and weaknesses. Although the USS approach leads to fast data results, the interpretation neglects the capillary pressure effects and provides a limited amount of data points obtained after breakthrough. The SS method is time consuming but enables covering a wider range of saturation with data points if the test is well designed. The SD method may be more time consuming than the SS method but provides both relative permeability to the injected phase and capillary pressure. The relative permeability to the produced phase is then determined by numerical means. The main objective of this study was to compare the water-oil relative permeability curves obtained from the steady-state and semi-dynamic methods performed at reservoir conditions with live fluids. Carbonate core plugs of same rock type and same properties were selected for this experimental program. The samples were brought to the same irreducible water saturation at a constant brine-oil capillary pressure using a centrifuge before being dynamically aged with live oil. In addition to monitoring the average saturation using material balance (MB), a linear X-ray scanner was used for in-situ saturation monitoring (ISSM) along the core samples. The oil relative permeability from the SD method was simulated with fixed water relative permeability and capillary pressure by history-matching the oil production and the differential pressure signal. Two additional centrifuge tests on twin plug were performed in order to measure imbibition capillary pressure and oil relative permeability at pseudo-reservoir conditions. This comparative study shows that the SD method provides similar capillary pressure and oil relative permeability curves to those obtained by centrifuge methods. Even if all Kr curves are in an acceptable envelop, some differences are observed between SD and SS Kr curves: several investigative leads are given to explain this discrepancy. It is also shown that a better saturation method needs to be implemented, especially when dealing with heterogeneous rocks. While a more robust ISSM method is being tested at TOTAL, the results presented in this paper are very encouraging.

Digital rock workflow to calculate wettability distribution in a reservoir rock

Wettability has a strong influence on multi-phase flow behavior through reservoir rock. Reservoir rocks tend to have spatially varying wettability. Prior to contact with oil, rocks are almost always naturally water-wet. As oil invades the pore-space over geologic time, the initial water-wet state may be altered in certain locations due to adhesion of substances within the oil phase to the grains. Mechanisms of wettability alteration depend on various properties such as pressure, temperature, mineral chemistry, surface roughness and fluid composition. In this study wettability alteration in a reservoir rock is studied through direct simulation using multiphase Lattice Boltzmann method where the computational grid is constructed from segmented micro-CT images of the rock sample. The pore-grain interface is defined by a triangulated surface mesh for accurate fluxes near boundary and local curvature calculation. A capillary pressure drainage simulation is conducted in a water-wet Berea sandstone sample initially filled with water. When oil invades the pore space as the capillary pressure is increased, a fraction of the pore-grain surface is altered towards an oil-wet condition, as determined by a novel wettability alteration process. This process calculates local curvature at every surface element of the rock, obtains local capillary pressure from the simulation and assumes a disjoining pressure to determine water-film breakage at every location of the pore-grain surface. As a result, a spatially varying rock wettability is created. Using this new wettability distribution, the simulation is continued to allow the fluid phases to redistribute accordingly. The process is iteratively carried out until both fluid saturation and wettability distribution converged at a given applied capillary pressure. Afterwards, the pressure is ramped up to the next stage and the process is repeated again. It has been found that the wettability alteration is a slow dynamic process where the non-wetting phase can gradually invade finer pore space as the surrounding grain wettability is altered. In this study, it has also been found that wettability alteration of the reservoir rock produces lower connate water saturation during primary drainage compared to the simulation results without alteration. The resulting spatially varying wettability distribution from primary drainage is used for a subsequent water flooding simulation to calculate water-oil relative permeability curves. The methodology presented in this work can be leveraged to better understand and predict an improved mixed wetting conditions found in the reservoir rocks which is needed for more accurate displacement tests such as relative permeability simulations.

Coupled tripartite investigation of breaker fluid invasion and impact on hydrocarbon recovery in sandstone reservoirs

Breaker fluids are designed to dissolve filter cakes by breaking their long-chain molecules, thereby removing solid deposits on the wellbore wall. Although breaker fluids are not intended to infiltrate the hydrocarbon reservoir, they can invade and cause formation damage by altering sandstone reservoirs' wettability and relative permeability. This can lead to a reduction in the overall reservoir performance. This study coupled tripartite methods to investigate the potential impact of breaker invasion and transport in hydrocarbon reservoirs and its multiscale effect on the performances of sandstone reservoirs. We utilized experimental, analytical, and numerical methods to assess and predict the susceptibility of reservoirs to breaker fluid invasion and transportation. Our experimental and empirical investigations considered varying breaker fluid formulations to evaluate the effects of breaker fluid concentration, formation temperature, and solution gas-oil ratio (GOR) on residual-oil saturation (ROS) and oil-water relative permeability. By adopting the ROS and relative permeability associated with the 50% v/v breaker fluid mixture, the performance of the hydrocarbon reservoir was numerically simulated under the limiting scenarios of no-invasion, moderate-invasion, and deep-invasion of breaker fluid. The results indicate a positive correlation between breaker fluid concentration and ROS, highlighting the risks that breaker fluid invasion and deep infiltration pose to hydrocarbon recovery. Further, results show that both live-oil condition (LOC) and dead-oil condition (DOC) reservoirs are susceptible to the detrimental impacts of breaker fluid infiltration, while their invasion can reduce hydrocarbon recovery in both LOC (−6%) and DOC (−28%). The multi-scale effects on reservoir performance are more pronounced at near-wellbore and DOC than at far-field and LOC. Findings from this work provide valuable insights into the complexity of breaker-fluid invasion in sandstone reservoirs and the mitigation of associated risks to reservoir performance.

A Novel Equivalent Numerical Simulation Method for Non-Darcy Seepage Flow in Low-Permeability Reservoirs

The low permeability and submicron throats in most shale or tight sandstone reservoirs have a significant impact on microscale flow. The flow characteristics can be described with difficultly by the conventional Darcy flow in low-permeability reservoirs. In particular, the thickness of the boundary layer is an important factor affecting the formation permeability, and the relative permeability curve obtained under conventional conditions cannot accurately express the seepage characteristics of porous media. In this work, the apparent permeability and relative permeability were calculated by using non-Darcy-flow mathematical modeling. The results revealed that the newly calculated oil–water relative permeability was slightly higher than that calculated by the Darcy seepage model. The results of the non-Darcy flow based on the conceptual model showed that the area swept by water in non-Darcy was smaller than that in Darcy seepage. The fingering phenomenon and the high bottom hole pressure in the non-Darcy seepage model resulted from the larger amount of injected water. There was a large pressure difference between the injection and production wells where the permeability changed greatly. A small pressure difference between wells resulted in lower variation of permeability. Consequently, the non-Darcy simulation results were consistent with actual production data.

Mechanistic Understanding of Delayed Oil Breakthrough with Nanopore Confinement in Near-Critical Point Shale Oil Reservoirs

Recently, significant breakthroughs have been made in exploring northeast China’s shale part of the Q formation. On-site observation reveals that the appearance of oil at the wellhead is only seen a long time after fracturing in many wells. Strong coupling between phase behavior and relative permeability curves in the reservoir with the near-critical point initial condition restricts the efficient development of this kind of shale oil. A series of compositional models are constructed to address the issues to reveal the cause of the late oil breakthrough. Nanopore confinement is checked by including this phenomenon in the numerical model. Before the simulations, the work gives detailed descriptions of the geology and petrophysics background of the target formation. Simulation results show that the delayed oil breakthrough is highly related to the coexistence of three phases at the beginning of production, which is not seen in common reservoirs. The extended period of purely water production complicates subsurface flow behavior and hinders the increase of medium- and long-term oil production. Early-time production behavior in such reservoirs is associated with the gas–liquid relative permeability curves and initial water saturation. Oil–water relative permeability curves affect the water-cut behavior depending on wetting properties. The potential oil-wet property slows down oil breakthroughs. Conceivably, purely gas and water phases exist due to the nanopore confinement of crude oil phase behavior; thus, the late oil production is barely related to the gas–liquid relative permeability curves.

On the Water-Oil Relative Permeabilities of Southern Algerian Sandstone Rock Samples

The water–oil relative permeability behavior of different plugs from the Hassi Messaoud reservoir in south Algeria has been investigated to understand the fundamental processes of two-phase flow taking place within the macro-structure of rock samples. The experiments were conducted on cylindrical reservoir samples (plugs) using the unsteady-state method to measure the oil–water relative permeabilities due to operational simplicity. The impact of factors such as wettability, overburden pressure and rock characteristics based on the relative permeability curves have been carefully assessed. During this test, temperature was kept in the range of 95 to 100 °C and pressure was maintained at 100 bar. Large variations in relative permeability curve trends have been experimentally observed for different rock samples under investigation, which can be explained by the heterogeneous nature of the studied reservoir. Results showed an intermediate alteration of wettability and for all studied samples, and the intersection point of the relative permeability values for oil and water is less than 50%, showing that these samples exhibit oil-wet behavior. Our results also show that displacement pressure increases from 0.13 to 2 psi, promoting a gradual displacement of oil relative permeability (Kro) toward higher saturations in water (45% to 60%). The results show that the oil recovery rate at breakthrough is approximately 16% to 28% of the initial oil in place (IOP), with an average of 23%. The final oil recovery rate, obtained by moving at constant pressure, ranges from 43% to 55% of the initial oil in place (IOP), with an average value of around 49%. The forced displacement at the end of the performed tests increased the average recovery rate by about 4%. These rates vary from 46% to 61% of the initial oil in place (IOP). The residual oil saturation (Sor) varies from 33.7% to 47.8% relative to pore volume (Vp); the average is about 42%. The residual oil saturation (Sor) is about 30% to 45% Vp after forced displacement at the end of the test, the average is about 38.5%, and the relative permeabilities Krw and Kro are equal to the water saturations of 33% to 50%; the average value is about 41%.

A New Method to Calculate the Relative Permeability of Oil and Water in Tight Oil Reservoirs by Considering the Nonlinear Flow

The theoretical research on the percolation mechanism and oil-water relative permeability of low-permeability oil reservoirs is the focus and hotspot of international researchers. Oil-water relative permeability is an important parameter that describes the characteristics of oil-water two-phase flow and is widely used in the dynamic analysis of development and numerical simulation technology in the reservoir. The traditional calculation method of oil-water relative permeability (i.e., the JBN method) is based on the Darcy flow law. When the velocity and the displacement pressure gradient do not follow the linear flow law, there are some errors in the results of oil-water relative permeability calculated by the JBN method. In this paper, the traditional JBN method is improved, and we establish a new processing method of experimental data for oil-water relative permeability considering the effects of nonlinear flow, capillary pressure, and gravity in tight oil reservoirs. The experiments on the flow characteristics of single-phase oil and oil-water relative permeability under nonsteady-state conditions were carried out. The flow velocity and displacement pressure gradient show nonlinear characteristics when single-phase oil is passed through a tight core. At the same time, when the air permeability decreases from 1.92 × 10 − 3 μ m 2 to 0.1 × 10 − 3 μ m 2 , the nonlinear characteristics are becoming more and more obvious. Compared with the traditional JBN method, when the nonlinear flow characteristics are considered, the oil phase relative permeability increases, and the water phase relative permeability is slightly lower. If nonlinear flow characteristics are considered, when the water saturation increases from 0.605 to 0.699, the difference of oil phase relative permeability calculated by the JBN method and this method is gradually decreasing and, with the increase of water saturation, decreases from 0.0029 to 0.0001. In addition, the effects of capillary pressure, gravity, and the nonlinear flow coefficient on the oil-water relative permeability in tight oil reservoirs are studied. The capillary pressure also has a great influence on the relative permeability of the oil phase, and the relative permeability of the oil phase increases with the increase in capillary pressure. In the development process of the low-permeability reservoir, the seepage characteristics of each flow area are different, and the oil-water relative permeability is also different. Therefore, the research results play an important role in guiding the understanding of seepage characteristics of low permeability of tight oil reservoirs.