Oil Relative Permeability Curves Research Articles

Issue with Stone-II three phase permeability model, and a novel robust fundamentals-based alternative to it

The objective of this paper is to present a fundamentals-based, consistent with observation, three-phase flow model that avoids the pitfalls of conventional models such as Stone-II or Baker's three-phase permeability models.While investigating the myth of residual oil saturation in SAGD with comparing model generated results against field data, Gupta et al. (2020) highlighted the difficulty in matching observed residual oil saturation in steamed reservoir with Stone-II and Baker's linear models. Though the use of Stone-II model is very popular for three-phase flow across the industry, one issue in the context of gravity drainage is how it appears to counter-intuitively limit the flow of oil when water is present near its irreducible saturation.The current work begins with describing the problem with existing combinatorial methods such as Stone-II, which in turn combine the water-oil, and gas-oil relative permeability curves to yield the oil relative permeability curve in presence of water and gas. Then starting with the fundamentals of laminar flow in capillaries and with successive analogical formulations, it develops expressions that directly yield the relative permeabilities for all three phases. In this it assumes a pore size distribution approximated by functions used earlier in the literature for deriving two-phase relative permeability curves. The outlined approach by-passes the need for having combinatorial functions such as prescribed by Stone or Baker.The model so developed is simple to use, and it avoids the unnatural phenomenon or discrepancy due to a mathematical artefact described in the context of Stone-II above. The model also explains why in the past some researchers have found relative permeability to be a function of temperature. The new model is also amenable to be determined experimentally, instead of being based on an assumed pore-size distribution. In that context it serves as a set of skeletal functions of known dependencies on various saturations, leaving constants to be determined experimentally.The novelty of the work is in development of a three-phase relative permeability model that is based on fundamentals of flow in fine channels and which explains the observed results in the context of flow in porous media better. The significance of the work includes, aside from predicting results more in line with expectations and an explanation of temperature dependent relative permeabilities of oil, a more reliable time dependent residual oleic-phase saturation in the context of gravity-based oil recovery methods.

Effect of Temperature on Two-Phase Gas/Oil Relative Permeability in Viscous Oil Reservoirs: A Combined Experimental and History-Matching-Based Analysis

Summary Thermal enhanced oil recovery (TEOR) is the most widely accepted method for exploiting the heavy oil reservoirs in North America. In addition to improving the mobility of oil due to its viscosity reduction, the high temperature down in the hole due to the injection of the vapor phase may significantly alter the fluid flow performance and behavior, as represented by the relative permeability to fluids in the formations. Therefore, in TEOR, the relative permeabilities can change with a change in temperature. Also, there is no model that accounts for the change in temperature on two-phase gas/oil relative permeability. Further, the gas/oil relative permeability and its dependence on temperature are required data for the numerical simulation of TEOR. Very few studies are available on this topic with no emerging consensus on a general behavior of such effects. The scarcity of such studies is mostly due to experimental problems to make reliable measurements. Therefore, the primary objective of this study was to overcome the experimental issues and investigate the effect of temperature on gas/oil relative permeability. Oil displacement tests were carried out in a 45-cm-long sandpack at temperatures ranging from 64°C to 210°C using a viscous mineral oil (PAO-100), deionized water, and nitrogen gas. It was found that the unsteady-state method was susceptible to several experimental artifacts in viscous oil systems due to a very adverse mobility ratio. However, despite such experimental artifacts, a careful analysis of the displacement data led to obtaining meaningful two-phase gas/oil relative permeability curves. These curves were used to interpret the relative permeability curves for gas/heavy oil systems using the experimentally obtained displacement results. We noted that at the end of gasflooding, the “final” residual oil saturation (Sor) still eluded us even after several pore volumes (PVs) of gas injection. This rendered the experimentally determined endpoint gas relative permeability (krge) and Sor unreliable. In contrast, the irreducible water saturation (Swir) and the endpoint oil relative permeability (kroe) were experimentally achievable. The complete two-phase gas/heavy oil relative permeability curves are inferred with a newly developed systematic history-matching algorithm in this study. This systematic history-matching technique helped us to determine the uncertain parameters of the oil/gas relative permeability curves, such as the two exponents of the Corey equation (No and Ng), Sor and krge. The history match showed that kroe and Swir were experimentally achievable and were reliably interpreted, except these four parameters (i.e., Corey exponents, true residual oil saturation, and gas endpoint relative permeability) were interpreted from simulations rather than from experiments. Based on our findings, a new correlation has been proposed to model the effect of temperature on two-phase gas/heavy oil relative permeability.

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.

Low salinity water flooding: Evaluating the effect of salinity on oil and water relative permeability curves using coupling of DLVO and geochemical reactions

Enhancing the oil recovery of carbonate reservoirs with acidic oil depends on injected brine composition and salinity throughout the low salinity water flooding. The typical description of this phenomenon on oil and water relative permeability curves is being put forward by the process-dependent interpolation function, which barely addresses the underlying fundamentals governing the direct impact of wettability alteration and geochemical reactions on flow saturation functions. The main objective of this work is to perform an integrated investigation of the effect of salinity on oil and water relative permeability curves by dynamic coupling of the Derjaguin, Landau, Verwey, and Overbeek (DVLO) theory and geochemical reactions. We studied both the single and two-phase systems using the basis of the geochemical reactions to track the variations of the wetting and non-wetting phase relative permeability curves. In the single-phase scenario, the results show the superiority of the reactive flow modeling technique with kinetic-controlled reactions, in the range between [2–4] of the Damkohler number, to yield a better result for the experimental effluent ions' concentrations than the equilibrium approach. In addition, the single-phase results under dynamic conditions propose Civan correlation as the best predictor of residual resistance factor (RRF) by numerically adjusting the correlation of coefficients based on the physical variables - salinity, dimensionless consumed ion concentration, and Peclet number. Accordingly, the results indicate a novel linkage between the single-phase and two-phase results in the sense that RRF under single-phase mode can be used to estimate the change in the wetting phase relative permeability under the two-phase mode. The single-phase methodology provides the capability for an improvement – up to 15% - in the prediction of the pressure drop curve. For two-phase cases, our procedure involved coupling the characterized geochemical reactions and the DLVO theory to consider the effect of injected water composition on contact angle as the static two-phase parameter. The phase-field method is coupled with DLVO theory to calculate the relative permeability curves for the non-wetting phase, which corresponds to the contact angle at each simulation time step. The two-phase results indicate an improvement – up to 30% - in the prediction of the recovery factor curve, on a history-matching basis, using the DLVO theory with contact angle-dependent correlation of non-wetting phase relative permeability curve. The main novelties of this study are using the single-phase dynamic permeability impairment results in calculating the variation of the wetting-phase relative permeability curve. Moreover, dynamic coupling of DLVO and non-linear contact angle-dependent correlation is used to calculate the non-wetting phase relative permeability curve. According to these novelties, more accurate prediction of the laboratory production profiles can be obtained.

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

A new approach to measure wettability by relative permeability measurements

Wettability is a key factor controlling the flow of fluids, solutes, heat and electrical current in porous media, and therefore it is important in studies of various processes including CO2 storage, secondary and tertiary oil recovery, as well as the displacement of water and nonaqueous phase liquid (NAPL). Although Amott-Harvey and USBM are conventional industry-standard techniques for measuring average wettability, they have some limitations. In this paper, we show that, in a plot of the relative permeability of a fluid, the area below the curve is closely related to the wettability. By using the areas below the water and oil relative permeability curves, we derive a new wettability index (called modified Lak). To demonstrate the applicability of this new index and testing other indices, we performed primary imbibition relative permeability, and primary imbibition and secondary drainage capillary pressure measurements on twenty carbonate reservoir samples. In general, all indices predicted oil-wet character of the tested rocks. USBM was associated with the broadest range of variation, whereas the new index corresponded to the smallest range of variation. Amott-Harvey and Lak, however, fell between USBM and the new index, with fairly similar ranges of variation. In addition, we report the correlations between different indices, and the change of wettability indices vs. reservoir depth. Advantages and limitations of different wettability indices are also discussed. Since each wettability index has some limitations in revealing the true state of wettability, none of these indices can be considered as an absolute measurement. Therefore, different indices should be regarded as complementary to each other, and determination of wettability should not be limited to only one method.

A new computational approach to predict hot-water flooding (HWF) performance in unconsolidated heavy oil reservoirs

In this study, a new computational approach for predicting the performance of hot-water flooding in unconsolidated heavy oil reservoirs is presented. The proposed model predicts the changes in the oil–water viscosity ratio (μo/μw) by estimating the reservoir temperature distribution through porous media. Then, the dimensionless and normalized variables were redefined to forecast water fractional flow as a function of temperature and water saturation. Moreover, the proposed approach predicts the cumulative heavy oil production and recovery factor more accurately and with less required input data and runtime compared to commercial simulators such as CMG-STARS (computer modeling group), etc.Estimated results were validated using laboratory experimental data and numerical simulation outputs. A total of 4 core-flooding experiments were conducted at injection temperatures of 20–80 °C. Numerical simulation models based on the laboratory HWF tests were developed in CMG-STARS. The water–oil relative permeability curves were tuned to history match simulation results with those obtained from experiments.Finally, the predicted cumulative heavy oil productions, recovery factors (RF) and production rates by the proposed approach were compared to the results from the laboratory sandpacked tests and simulation runs for three scenarios. The relative errors between heavy oil recovery factors obtained from computational approach and experimental data were measured to be 11.01%, 14.51% and 13.69% for injection temperatures of 40, 60 and 80 °C, respectively.

Experimental investigation of the effect of temperature on two-phase oil-water relative permeability

Relative permeability is affected by several flow parameters, mainly the operating temperature and fluid viscosity. Fluid viscosities change with temperature, which correspondingly affects the relative permeability. Temperature is believed to have a considerable effect on oil–water relative permeability, thus a vital input parameter in petroleum reservoir production modelling. The actual effect of temperature on oil-water relative permeability curves has been a subject of debate within the scientific community. The literature shows contradictory experimental and numerical results concerning the effect of temperature on oil-water relative permeability. This work investigates the effect of temperature on oil-water relative permeability using well-sorted unconsolidated silica sandpacks, by adopting the unsteady-state relative permeability method, and by applying numerical history matching technique. The series of experiments were conducted at different temperatures of 40, 60, and 80 °C under three levels of injection flow rate (0.0083, 0.0125, 0.0167 cm3/s) for two different oil samples. The findings show that oil-water relative permeability is a function of temperature, water injection flow rate and oil viscosity. Generally, the profile of oil and water relative permeability curve changes with varying temperature, oil viscosity and water injection flow rate at the same operating condition.

Nanoemulsion flooding for enhanced oil recovery: Theoretical concepts, numerical simulation and history match

In current scenario of depleting oil reserves, chemical flooding is a vital enhanced oil recovery (EOR) technique. Present study discusses laboratory flooding experiments of surfactant/nanoparticle nanoemulsions on sand-pack system, with bulk approach to model and simulate the flooding strategies portraying the potential of nanoemulsion assisted EOR. Physicochemical properties of nanoemulsions were characterized in terms of droplets size, interfacial tension, wetting behavior, viscosity improvement and crude oil displacement. A numerical methodological simulation is performed on porous media through CMG-STARS simulator. Cartesian single porosity model equipped with well pattern, injection fluid flow-rate and rock-fluid properties was developed via simulation tool during compositional investigation. Tuning of relative permeability values to successfully fit with cumulative oil production and water cut was extremely challenging role during model development. Oil saturation profiles and relative permeability curves displayed the alteration in wetting behavior of sand-pack system to strongly water-wet from oil/intermediate-wet condition. 23–28% tertiary recoveries were achieved, contingent to composition of surfactant/nanoparticle in injected nanoemulsion. History match (HM) of production data via CMOST for experimental and simulation outcomes exhibited a good match with global HM error < 6%. Numerical simulation investigation facilitates a holistic approach to predict the performance and practicability of nanoemulsions as chemical EOR fluid.

Experimental determination of relative permeabilities and critical gas saturations under solution-gas drive

Relative permeabilities are crucial to predict oil production from underground reservoirs. Multiple previous studies are limited to measuring/estimating relative permeabilities within the region where both phases are mobile. This study presents a novel experimental method to measure the oil relative permeability under presence of the trapped gas for gas-oil systems under depressurization. The experiments were carried out with the carbonaceous reservoir and outcrop samples. The results show a highly variable amount of immobile gas for North Sea chalk (from 8% up to 26% volume) and a significant reduction in oil relative permeability (up to 75%). The relative permeabilities were found to be power-law type functions. A comparison with the previously developed pore-network based model for gas-oil relative permeabilities is presented, allowing for reconstruction of both gas and oil relative permeability curves in the whole saturation range.

Effect of Displacement Pressure on Oil-Water Relative Permeability for Extra-Low-Permeability Reservoirs.

The oil–water relative permeability is an important parameter to characterize the seepage law of fluid in extra-low-permeability reservoirs, and it is of vital significance for the prediction and evaluation of the production. The pore throat size of extra-low-permeability reservoirs is relatively small, and the threshold pressure gradient and capillary pressure cannot be negligible. In this study, the oil–water relative permeability experiments with three different displacement pressures were carried out on the same core from the extra-low-permeability reservoir of Chang 4+5 formation in Ordos basin by the unsteady experimental method. The results show that the relative permeability of oil increases, while the relative permeability of water remains unchanged considering the capillary pressure and oil threshold pressure gradient compared with the JBN method. As the displacement pressure enlarges, the relative permeability of oil and water both increases; the residual oil saturation decreases, therefore the range of the two-phase flow zone is improved. Moreover, the isotonic point of water–oil relative permeability curves moves to the upper right region, and the reference permeability improves as well with the increasing pressure.

Study on the effect of polymer viscosity and Darcy velocity on relative permeability curves in polymer flooding

Relative permeability curves in polymer flooding are important parameters to reflect the two-phase flow performance in reservoir rocks, which have important application in numerical simulation, reservoir engineering and prediction of crude oil production. Although the researches on the relative permeability curves in polymer flooding have made some progress at present, the relative permeability curves used in these researches are generally obtained by traditional experiment methods (steady-state method and unsteady-state method) or microscopic pore-scale modeling method. However, these methods are incapable of considering the physicochemical properties (i.e. rheology, residual resistance factor, adsorption and diffusion) of polymer completely. In this paper, a numerical inversion method based on automatic history matching is used to determine relative permeability curves in polymer flooding. The method performs automatic history matching by Levenberg-Marquardt (LM) algorithm on the unsteady-state experimental results and the predicted results of the numerical simulation model. As the physic-chemical properties of polymer solution have been fully taken into account in the numerical simulation model by far, the method makes up for the shortcomings of the traditional methods. Based on the inversed relative permeability curves, the effects of polymer viscosity and Darcy velocity in the rheo-thinning regime on relative permeability curves are then studied respectively. The results show that polymer viscosity and Darcy velocity in the rheo-thinning regime have little influence on the shape of oil relative permeability curve, but have obvious influence on the shape of water relative permeability curve. The deviation between the water relative permeability curve of polymer flooding and the one of water flooding increases linearly with the increase of polymer viscosity and decreases in power function with the increase of Darcy velocity in the rheo-thinning regime. At last, the prediction model of relative permeability curves under the influence of polymer viscosity and Darcy velocity in the rheo-thinning regime is established by multiple nonlinear regression method. The verification results show that this prediction model is reliable and can be used to predict the relative permeability curves at different polymer viscosities and Darcy velocities in the rheo-thinning regime.

About Identifiability of Oil and Water Relative Permeability Curves and Reservoir Heterogeneity through Integrated Well Test Study

Relative permeabilities (RP) play an important role in reservoir engineering. RP functions together with the permeability anisotropy coefficient predetermine waterflooding efficiency and oil/water ratio in production forecast. Traditionally multiphase flow parameters are estimated from core analysis data. But such measurements suffer from small representative elementary volume (REV) and limited characterization of reservoir properties. Therefore using core data in 3D reservoir modelling could lead to distorted description of actual flow conditions. Despite those functions (RP) could be history matched with assimilated production data, such a procedure would require long history of waterflooding. So the authors’ idea is to apply integrated well test study to estimate the displacement efficiency and/or relative permeability functions at downhole conditions. Well testing is traditionally applied in reservoir engineering for single-phase reservoir parameters estimation. Our approach is extended to multi-phase flow and is based on data collection at well bottomholes and subsequent data assimilation in flow model.In this paper we summarize both features of mathematical problem statement and identifiability of multiphase parameters through inverse problem solution, but also discuss 10+ -year experience in interpretation of two-phase well testing using our technologies. To estimate multiphase parameters, we have to jointly consider complex data of well logging and dynamic data of well testing. Both data sets are used in the inverse problem quality criteria, where the least squares method has been applied. Forward problem corresponds to a 3D multiphase fluid flow model in porous media. The latter consists of continuity equation with multiphase Darcy equation instead of moment balances. For data assimilation modern methods of optimal control theory were successfully applied. For all synthetic test cases real reservoir parameters were accurately recovered through the use of forward simulation data.In order to estimate reservoir heterogeneity, we applied a single-phase model to get the ratio of vertical to horizontal permeability. Data of well self-interference testing were used for vertical permeability estimation. Depending on the depth of reservoir pressure perturbation, reservoir properties could be properly inferred from observations. Two other options of 3D interference testing using vertical and horizontal wells are also presented.In other words, all the problems considered are identifiable, and the level of their correctness is completely predetermined by the amount and quality of observed data. And transition to digital (intelligent) oil-and-gas production and closed-loop reservoir management [1] provides a possibility to remove discussed restrictions and all inverse problems considered should be accounted as fully identifiable.

Convection beyond the Steam Chamber Interface in the Steam-Assisted-Gravity-Drainage Process.

In the steam-assisted-gravity-drainage (SAGD) process, heat energy is transferred from the steam chamber to the farther cold reservoir by conduction and convection mechanisms, so as to reduce the oil viscosity. In previous research works, although it was proved that convection is an indispensable part of the heat-transfer process, there is still a controversy about the formation mechanism of heat convection. In this study, an analytical mathematic model was proposed to explore the convective heat transfer in SAGD operation. Typically, this model integrates three heat convection forms that are generated by pressure difference, gravity, and thermal expansion of connate water,. Subsequently, the simulation results are compared with field data to evaluate the accuracy of the new model, and they are reasonably consistent with UTF field data. The results indicate that convective heat transfer plays a predominant role in the immediate vicinity of the steam chamber interface. Furthermore, this paper derives a mathematic model of oil production to explore the effect of heat convection on oil production under different operation conditions. The results demonstrate that heat convection has an adverse impact on oil production, but it is inevitable. This study also displays that some parameters, such as the lateral spreading rate, the thermal diffusivity, the viscosity coefficient, and the curvature of oil relative permeability curve, can significantly affect the oil production rate. Based on this study, the effect of convection mechanism on the heat-transfer process and oil production will be further clarified, and the parameters in the SAGD process can be optimized, so as to effectively enhance and predict oil production.

Effects of nanocomposite polymer flooding on Egyptian crude oil recovery

In this work, a laboratory study of enhanced oil recovery (EOR) was carried out using Egyptian crude oil of 37°API extracted from a reservoir in the Western Desert to identify the optimum conditions for the application of locally prepared nanocomposite polymer flooding under harsh reservoir condition. In contrary to the other studies, we tested the ability of nanocomposite polymer where nanoparticles are involved in the polymer matrix during polymerization process. Measurements of viscosity and shear rate of several solutions were taken. Displacement runs were conducted at different conditions of nanocomposite polymer salinities (10,000, 20,000, 30,000, 40,000, 50,000, 60,000 and 65,000 ppm), concentrations (1, 1.5, 2, 2.5, 3, 3.5 and 4 g/L) and slug sizes (0.2, 0.4, 0.6 and 0.8 PV). A linear sandpack (length of 62.5 cm and diameter of 2″) was prepared and wrapped with thermal jacket to simulate several reservoir temperatures. It was filled by selected sand size to produce linear sandpack model with reasonable porosity (22%) and permeability (129–157 mD) values. The model was used to perform several displacements runs for waterflooding and nanocomposite polymer flooding. The results of the flood runs are analyzed using the water–oil relative permeability curves. The measurements of the solutions properties showed that the critical concentration of the used nanocomposite polymer in the solution is 2 g/L. Also, it was observed that the used nanocomposite polymer solution could withstand a salinity of 60,000 ppm. As a result of the flooding, it was found that the optimum economical slug size of the used nanocomposite polymer is 0.4 PV at reservoir temperature of 40 °C. The results indicated also that the used nanocomposite polymer could withstand a reservoir temperature of 90 °C. The water–oil relative permeability curves showed an enhancement of oil relative permeability and a decrease in the water relative permeability using nanocomposite polymer over waterflooding. The cost of the used nanocomposite polymer with a concentration of 2 g/L and slug size of 0.4 PV is 0.626 $ for each barrel of the incremental oil recovery. Based on the results of this work, it is clear that involving nanoparticles such as silica in the polymer matrix composition improves its properties, thermal and salinity resistivity. Such study is an original contribution to carry out successful nanocomposite polymer EOR projects.

Influence of size and surface acidity of silica nanoparticles on inhibition of the formation damage by bentonite-free water-based drilling fluids. Part II: dynamic filtration

Although the application of nanoparticles in drilling fluid has been reported under static test by our research group, understanding inhibition formation of damage by filtration volume reduction in porous media under dynamic conditions is still a crucial issue. In this research, synthesised silica nanoparticles modified with acid treatment (Si11A) evaluated in previous results in the bentonite-free water-based drilling fluid (BFWBM) in static tests were analysed in the coreflooding test under dynamic and reservoir conditions. Si11A nanoparticles were evaluated by permeability return tests under reservoir conditions overburden, pore, and overbalance pressures, and temperatures of 3000 psi, 1700 psi, 1200 psi, and 87 °C, respectively. Coreflooding test with a concentration of 0.1 wt% Si11A nanoparticles based on our previous work showed a reduction in the filtration volume by 77%, decreasing the formation damage by 51% compared to the drilling fluid without nanoparticles. Also, the oil recovery obtained with the best design fluid using the Si11A nanoparticles was 10% higher than the baseline. Additionally, the effluents of crude oil obtained from permeability return test were evaluated at reservoir temperature using a rotational rheometer at shear rates varying between 1 and 100 s−1, obtaining a reduction of the viscosity up to 28% during nine pore volume injected using the BFWBM with S11A nanoparticles. The role of the nanoparticles in the drilling fluid is the rapid deposition in the mudcake to enhance the properties, the subsequent filtration volume reduction, and the enhancement of the petrophysics properties may be described by dynamic filtration curves, effective oil permeability and relative permeability curves.

Analysis of Test Method for Oil and Water Relative Permeability Curve in Tight Reservoirs

With the development of the international economy, the global demand for oil and gas resources has continued to increase in recent years. The development of high-permeability reservoirs has reached the middle and late stages, and resources are depleting. With the large-scale successful exploitation of tight oils in North America, low-permeability tight reservoirs have gradually become the main object of development. Compared with conventional reservoirs, tight reservoirs mainly develop nano- scale pore systems. It causes poor reservoir properties, high interlayer heterogeneity, low porosity and permeability, and generally no natural productivity in reservoirs. In tight reservoirs, the flow of oil-water phases is not affected by the scale, but also the wettability, they make the oil and water phases seepage more complicated. In this paper, the natural core of a tight reservoir in Daqing was selected. Experiments were carried out using two experimental methods: steady-state method and non-steady-state method. The characteristics of oil and water phases percolation in tight reservoirs were analyzed. The results by comparing the two experimental methods showed the steady state method is suitable for measuring the oil and water relative permeability curve of tight reservoirs.

Relative Permeability Study in Part of Geleki Oil field of Upper Assam Basin

Relative permeability is a critical parameter for evaluation of reservoir performance. Relative permeability is a direct measure of the ability of the porous medium to allow flow of one fluid when two or more fluids are present. This flow property is the composite effect of pore-geometry, wettability, fluid saturation, saturation history, reservoir temperature, reservoir pressure, overburden pressure, rock-types, porosity and permeability types. The relative permeability curves are very important in reservoir studies. They are used in predicting production rate and recovery from the reservoirs during all recovery stages (primary, secondary, and tertiary). The wettability of a core does affect its waterflood behavior and relative permeability. Wettability affects relative permeability because it is a major factor in the control of the location, flow, and distribution of fluids in a porous medium. Present study aims at determining the relative permeability to oil and water of conventional core plugs from a parts of Geleki oil-field of upper Assam basin. This study is based on the determination of relative permeability to oil and water, and preparation of w ater and oil relative permeability (K rw and K ro ) curves vs water saturation (S W )and relative permeability ratio K rw /K ro curves vs oil saturation. Other aspects of the present study have been to determine irreducible water saturation and oil saturation and wettability of the reservoir rocks. Keywords: Relative permeability, flow property, water saturation

Obtaining Relative Permeability Curve of Carbonate Reservoir by the Weighted Method

Background: The oil-water relative permeability curve is an important experimental data and basis for oilfield development scheme and dynamic prediction. The characteristics of oil and water relative permeability curves in different reservoirs are otherness. Objective: In order to enable various effects to be reflected in the standardized relative permeability curve, the standardized relative permeability curve can reflect the characteristics of each core. Method: The core is taken from core wells in a similar flow unit. The oil-water relative permeability curves are measured by indoor physical simulation experiments. The oil-water relative permeability curves of representativeness and conforming to hydrodynamic characteristics are screened. Because the porosity and permeability of different cores have different effects on the relative permeability curve, the weight of the porosity and permeability of each core is added to the standard relative permeability curve in the process of solving standardized relative permeability curve. Results: A new method that the weight method to be used to solve the problem of the standardized relative permeability curve is obtained. The comparison of the new method and the average method shows that both of them are highly consistent. Conclusion: The patent on the solution of the relative permeability curve is improved. Considered the effect of different cores of porosity and permeability on the relative permeability curve. Calculated the weight of the porosity and permeability of different cores. The representative normalized relative permeability curve is obtained by using the weight method.

Stabilizing silica nanoparticles in high saline water by using polyvinylpyrrolidone for reduction of asphaltene precipitation damage under dynamic condition

Abstract In this study, the performance of stable nanofluid containing SiO2 nanoparticles dispersed and stabilized in high salinity brine for asphaltene inhibition in dynamic condition is evaluated. In the first stage of this work, the stability of silica nanoparticles in different range of water salinity (0–100000 mg·L−1) is investigated. Next, stable nanofluid containing highest salinity is selected as asphaltene inhibitor agent to inject into the damaged core sample. The estimated values of oil recovery for base case, after damage process and after inhibition of asphaltene precipitation using nanofluid are 51.6%, 36.1% and 46.7%, respectively. The results showed the reduction in core damage after using nanofluid. In addition, the relative permeability curves are plotted for the base case, after damage process and also after inhibition of asphaltene precipitation using nanofluid. Comparison of relative permeability curves shows, relative permeability of oil phase decreased after damage process as compared with the base case. But after using nanofluid the oil relative permeability curve has shifted to the right and effective permeability of oil phase has been improved.