Water Phase Permeability Research Articles

Study on combination of surfactant and acid for depressure and increasing injection oil displacement in heterogeneous sandstone reservoirs

This study addresses the challenges faced by unconventional tight sandstone reservoirs, including low porosity, permeability, high clay content, and complex wettability, which lead to increased flow resistance and injection pressures. The research aims to optimize depressure and increasing injection methods by investigating the effects of various two-phase and three-phase displacement systems, employing experimental treatments including acids, alkalis, and surfactants. Nuclear magnetic resonance, computed tomography, scanning electron microscopy, inductively coupled plasma, and wettability tests are utilized to investigate the mechanisms of these treatments. Key findings indicate that weak alkaline ethylenediaminetetraacetate tetrasodium and weak acids like hydroxyethylidene diphosphonic acid and acetic acid can cause significant pore blockage, while hydrochloric acid can dissolve pore minerals, achieves a high depressure rate of 89.42%. Although surfactants exhibit a negative effect in two-phase displacement systems, they demonstrate considerable potential in three-phase displacement. Surfactants can modify the wettability of rock surfaces, reduce oil saturation, and improve water phase permeability, resulting in a depressure rate of 11.68%. Notably, the combination of surfactants and HCl enhances the depressure rate to 60.82% and improves oil displacement efficiency from 26.12% to 57.96%. The optimal formulation identified is “0.5% unconventional agent (CNI-A) +3% HCl,” which improves oil displacement capacity and alleviates injection pressure, providing valuable insights for the management of heterogeneous sandstone reservoirs.

Three dimensional time-variation simulator for water flooding reservoir based on “effective water flux”

Long-term water flooding leads to changes in pore throat structure, resulting in alterations in macroscopic reservoir petrophysical parameters. However, commercial numerical simulation software does not have this capability. Ignoring variations in physical parameters during the formulation of development plans and numerical simulations can lead to significant prediction errors, which severely impacts oil field recovery. This paper, based on an analysis of effective flow rate and waterflood intensity, proposes a new erosion degree characterization parameter: Effective water flux, to represent the time-varying patterns of physical parameters. It is embedded into a black oil model to develop a time-variation simulator, whose accuracy and stability in both black oil and time-variation models are validated through comparison with the commercial numerical simulation software CMG. The study further explores the effects of different parameter variations on the development process. It was found that increases in permeability and oil viscosity exacerbate heterogeneity and reduce displacement efficiency, while decreases in residual oil saturation and water phase permeability under residual oil saturation enhance water flooding efficiency. In complex models, the effects of variations in different parameters intertwine, collectively influencing development outcomes. This paper advances the development of time-variation numerical simulation technology.

Performance evaluation and physical simulation experiment of SiO2 nanoparticle synergistic crosslinked polymer system

Abstract As natural gas development gradually shifts from early to mid to late stages, water outflow from gas wells has become an inevitable problem. In this study, polyethyleneimine cross-linked polymers were synthesized and nano particles were introduced to obtain SiO2 nanoparticle synergistic cross-linked polymer systems. Rheological experiments show that the system has stronger shear resistance and higher yield stress, and the linear viscoelastic region has a stress amplitude less than 3.5Pa, exhibiting good elastic properties in the range of 0.01 to 10Hz. In terms of stability, after 45 days of aging, the viscosity retention rate of the system is 77.66%. When the mineralization degree is 224852mg/L, the viscosity retention rate is greater than 76.33%, indicating that the system has good aging stability and salt resistance.The physical simulation experiment of core displacement shows that SiO2 nanoparticle synergistic cross-linked polymer gel has gas-water selective plugging ability, and the reduction of water phase permeability is much greater than that of gas phase. The gas phase permeability can remains at about 75%, which is 2300 times that of water phase permeability, and has a good water plugging effect.

Ternary wetting modification technology: A remedy for water blockage and prevention sand in unconsolidated sandstone gas reservoirs

In the development of unconsolidated sandstone gas reservoirs, water and sand production pose challenges, reducing gas deliverability and causing reservoir damage. This paper presents a novel ternary water control and gas recovery technology using hydrophobic modification. The technology focuses on reversing capillary forces at the far-well edge of the reservoir to prevent water intrusion and creating a hydrophobic gravel layer around the wellbore to enhance water resistance. Additionally, the slotted liner cavities are treated to improve erosion resistance and maintain smooth gas flow, effectively controlling water and sand. The approach aims to minimize water and particle migration, thereby improving gas phase permeability. Researchers assessed the technology's effectiveness using a sand-gravel-slotted liner model and examined how sand wettability, gravel size, and liner slot width affect water resistance. Results show that the technology significantly reduces water phase permeability and gas sand content, increases water breakthrough pressure, and maintains the original permeability of the gas reservoir. When the formation sand contact angle θsand > 156°, the particle size ratio D50/d50 = 6.5, and the slit width is 0.30 mm, the water-resisting ability is the best. The research results can provide corresponding theoretical construction parameters for the field engineering of high-water cut-off loose sandstone gas reservoirs.

Evaluation of the Effects of Nano-SiO2 Microemulsion on Decompression and Augmented Injection in the Eunan Tight Reservoir

The residual oil saturation of the matrix near the well zone of a tight reservoir is high due to the tight reservoir’s complex conditions, such as the small pore throat radius and low permeability of the matrix and the development of microfractures, which can result in serious water channeling, even after long-term water injection development. The aim of this paper is to improve the effects of depressurization and augmented injection for tight reservoir waterflooding development by reducing the tight matrix’s residual oil saturation, increasing and maintaining its water phase permeability near the well zone using a nano-SiO2 microemulsion system with a small particle size and high interfacial activity. Therefore, four nano-microemulsion systems were evaluated and screened for their temperature resistance, salt resistance, interfacial tension, solubilization, and dilution resistance. A microemulsion system of 13% A + 4% B + 4% C + 4% n-butanol + 6% oil phase + 69% NaCl solution (10%) + 1% OP-5 + 0.5% anti-temperature agent + 0.3% nanosilica material was preferred. According to the core displacement experiment, the depressurization rate can reach 28~60% when the injection concentration of the system is 1~10% and the injection volume is 2~5 PV. The results of the on-site test show that the water injection pressure dropped to 17.5 MPa, which was lower than the reservoir fracture re-opening pressure. The pressure reduction rate was approximately 20%. The validity period of the depressurization and augmented injection has reached 23 months to date.

Study on oil seepage mechanisms in lamellar shale by using the lattice Boltzmann method

The shale oil and gas resources in the world are rich and are an important part of unconventional oil and gas resources. In this paper, firstly, by comprehensively using CT scanning technology, the three-dimensional pore-fracture structure characteristics of shale core samples of different sizes is characterized, and a three-dimensional digital core is established; Secondly, SEM and FIB-SEM techniques are systematically used to describe the microstructure and fracture network development characteristics of shale matrix pores and fractures, and a three-dimensional pore and fracture network model is established; Thirdly, Combined with LBZ simulation method, the mechanism of two-phase fluid transport in shale cross-scale fracture network is explored. Results show that: (a) The relatively dispersed mesopores and macropores in space constitute the main storage space of methane. Some pores in the study area of shale samples have good connectivity, and some samples only have connected pores in the study area of their magnification. (b) A large number of intergranular pores and fissures developed together with the intergranular pores of clay minerals, forming a good network connection system between microscopic pores in laminated shale. (c) when the hydrophilic mineral proportion is increased from 30% to 70%, the relative permeability of oil phase at water saturations of 20%, 40% and 60% has an increase of 6.8%, 7.8% and 4.2%, respectively, and the relative permeability of water phase at water saturations of 20%, 40% and 60% has a decrease of 1.8%, 2.6% and 6.5%, respectively. (d) When the oil phase contact angle is increased from 30° to 70°, the relative permeability of oil phase at water saturations of 20%, 40% and 60% has an increase of 1.9%, 2.7% and 2.2%, respectively, and the relative permeability of water phase at water saturations of 20%, 40% and 60% has a decrease of 1.2%, 2.1% and 3.5%, respectively.

Relative permeability of two-phase fluid flow through rough fractures: The roles of fracture roughness and confining pressure

The relative permeability of two-phase fluid flow through rough fractures was investigated by conducting the triaxial two-phase fluid flow experiment on sandstone fractures. The relative permeability in rough rock fractures is greater than that predicted by the Corey model and the viscous coupling model due to interphase resistance. Therefore, the flow resistance between two-phase fluids is lower than that of the Corey model and viscous coupling model. The resistance between two-phase fluids increases with the increase of fracture roughness and confining pressure, causing the decrease of relative permeability of two-phase fluid flow. It is also found that the influence of fracture roughness on relative permeability of water phase is more obvious than that of gas phase, while the influence of confining pressure on relative permeability of gas phase is more obvious than that of water phase. The relative role of fracture roughness and confining pressure in two-phase fluid flow decreases while the relative permeability approaching the equal-permeability point. Based on the influence of fracture roughness and confining pressure, a relative permeability model for rough rock fractures under the effect of confining pressure is established. This model describes the two-phase fluid flow behavior in rough rock fracture under different confining pressure well. Further analysis on relative permeability in terms of fractional flow of water was conducted. It shows that the confining pressure and fracture surface roughness play a hindering role in the two-phase fluid flow. This hindering effect is mainly on nitrogen at the low fractional flow of water and mainly on water at the high fractional flow of water.

Method for oil and water relative permeability calculating in Western Siberia formations according to capillarimetric and geophysical data

The most important filtration characteristics of productive formations are the oil and water phase and relative permeability. Methods for obtaining relative phase permeabilities can be divided into laboratory and analytical. Currently, the main source of information about RFP are techniques based on laboratory core studies. However, for each productive reservoir, it is desirable to have analytical models describing experimental data on RFP with an accuracy sufficient for practical purposes. The existence of such models will make it possible to increase the accuracy of development computer modeling. The analytical expressions obtained in this study allow us to take into account the influence of the pore channels heterogeneity in size on the relative phase permeabilities magnitude. It is shown that the pore channels heterogeneity in size can be estimated by the residual water saturation amount, which in turn can be determined from the geophysical well studies. Keywords: relative permeability; residual water saturation; pore channels; capillarimetric and geophysical studies.

Implication of interfacial tension reduction and wettability alteration by surfactant on enhanced oil recovery in tight oil reservoirs

Tight oil reservoir is usually characterized by poor physical properties with oil recovery less than 10%. The objective of the study is to investigate the effect of 4 different types of surfactants to change rock surface tension and interfacial tension as well as its impact on enhanced oil recovery (EOR) in tight oil reservoirs. Results shows that the fluoride FC-1 and GS surfactant has more potential for wettability alteration and interfacial tension reduction respectively. The interfacial tension decreased from 6.072 mN/m to 2.04 mN/m, 0.03 mN/m, 0.1 mN/m, and 0.04 mN/m under the action of FC-1, GS surfactant, FC-2, and FC-3, respectively. FC-1 made the wettability changed from original hydrophilic or oil-hydrophilic to hydrophobic and oil-phobic. While the effect of wettability modification by other three was not so obvious and the contact angle was no more than 45 degrees. So, the GS and FC-1 was selected for displacement tests to investigate the effect in augmenting injection and enhancing oil recovery. The average reduction rate of injection pressure by fluoride and Gemini surfactant was 32.4% and 14.2%, respectively. Under the action of fluoride and GS surfactant, the water-phase permeability increased by 36.8% and 29.9%, respectively. The improvement of recovery mainly occurred in primary water flooding, while the amount of oil displaced by surfactant solution and secondary water flooding was little or even no, with the recovery efficiency improved by 0–8.4%. The effect of fluoride was more obvious, revealing that changing rock wettability is more favorable than reducing the interfacial tension for oil recovery in tight sandstone oil reservoirs.

Relative permeability estimation of oil−water two-phase flow in shale reservoir

Oil−water two-phase flow is ubiquitous in shale strata due to the existence of connate water and the injection of fracturing fluid. In this work, we propose a relative permeability model based on a modified Hagen−Poiseuille (HP) equation and shale reconstruction algorithm. The proposed model can consider the nanoconfined effects (slip length and spatially varying viscosity), oil−water distribution, pore size distribution (PSD), total organic matter content (TOC), and micro-fracture. The results show that the increasing contact angles of organic matters (OM) and inorganic minerals (iOM) increase the relative permeability of both oil and water. As the viscosity ratio increases, the relative permeability of oil phase increases while that of water phase decreases, due to the different water−oil distribution. The effective permeability of both oil and water decreases with the increasing TOC. However, the relative permeability of water phase increases while that of oil phase decreases. The increasing number and decreasing deviation angle of micro-fracture increase the effective permeability of oil and water. However, micro-fracture has a minor effect on relative permeability. Our model can help understand oil−water two-phase flow in shale reservoirs and provide parameter characterization for reservoir numerical simulation.

Testing origin of reservoir quality difference of tight sandstones in the Yanchang Formation, Ordos Basin, China

The Chang 7 and Chang 8 members of the Upper Triassic Yanchang formation are high-yielding tight sandstone oil reservoirs deposited in different sedimentary environments in the Ordos Basin. Lacustrine sediments are dominant in Chang 7 members, while delta front sediments are dominant in Chang 8 members. The causes of reservoir quality differences in the different sedimentary environments are not clear, which renders tight-oil exploration and development difficult. In this study, X-ray diffraction analysis (XRD), optical microscopy, scanning electron microscope (SEM), mercury injection tests and oil-water relative permeability tests were used to study the origin of reservoir quality differences between the Chang 7 and 8 reservoirs. The results show the following: 1) the Chang 8 and Chang 7 reservoirs are dominated by primary intergranular pores and dissolution pores, respectively. 2) Grain-coating chlorite is present in the Chang 8 reservoir, which is known to enhance the ability of reservoirs to resist compaction and prevent the growth of quartz. However, the reservoir pore space could be preserved only when the abundance of grain-coating chlorite is below the threshold of 4 vol%. 3) Carbonate cementation occurs pore-throat spaces, and the porosity of the reservoir tends to improve with carbonate content increase in the range of 0–10 vol%. This phenomenon is caused by carbonate minerals formed in different times. 4) The strong heterogeneity of pore sizes is the reason for rapid rise of capillary force of pore mercury saturation curve in Chang 8 reservoir. The throat volume controls the mercury saturation of the pore throats. The Chang 8 reservoir exhibit larger throat volume and higher permeability than Chang 7 reservoir. 5) The Chang 7 reservoir has small pore radius and poor connectivity. Therefore, it is difficult for water to displace the oil phase. As a result, the water phase permeability increases rapidly, the residual oil saturation is high, and the water productivity of the reservoir increases rapidly. In conclusion, the reservoir quality of Chang 8 Member is better than that of Chang 7 Member, and this can be attributed to the following factors: i) Chang 8 reservoirs have larger grain sizes and more abundant grain-coating chlorite, ii) the low content of illite and carbonate cement reduces reservoir cementation capacity and iii) the pore connectivity is better, because the throat radius and effective throat volume are larger. The results provide guidance for the efficient development of tight oil in these reservoirs.

A new relative permeability model of coal reservoir considering interface effect

During the process of gas and water production in coal reservoirs, the interface effect between gas and water should not be ignored. In this study, based on nuclear magnetic resonance technology, the unsteady displacement experiment was carried out with coal samples to monitor the interface effect, and a new relative permeability model (with a specific benchmark) is established and verified which considering the interface effect. The results show that the NMR method can be used to monitor the interface effect effectively, and in the experiment movable water controlled by the pressure difference is limited (11% and 20%), and that controlled by the interface effect is dominant (89% and 80%), which means the interface effect plays a dominant role in the two-phase flow. In the flow, the gas phase drives the water phase, and this additional driving effect results in that the relative permeability of water phase is greater than 1. The verified results show that the new model can effectively describe the driving effect which can not be achieved by the capillary force model.

Microscale Evaluation of Tight Oil Mobility: Insights from Pore Network Simulation

Pore network modeling based on digital rock is employed to evaluate the mobility of shale oil in Qingshankou Formation, Songliao Basin, China. Computerized tomography technology is adopted in this work to reconstruct the digital rock of shale core. The pore network model is generated based on the computerized tomography data. We simulate the dynamics of fluid flow in a pore network model to evaluate the mobility of fluid in shale formation. The results show that the relative permeability of oil phase increases slowly in the initial stage of the displacement process, which is mainly caused by the poor continuity of the oil phase. In the later stages, with the increase in the oil phase continuity, the range of relative permeability increases. With the increase of organic matter content, the permeability of the water phase remains unchanged at low water saturation, but gradually increases at high water saturation. At the same time, it can be seen that, with the increase in organic matter content, the isosmotic point of the oil–water phase permeability shifts to the left, indicating that the wettability to water phase gradually weakens.

Displacement behavior and mechanism of long-term water flooding in sandstone oil reservoirs

Sandstone oil reservoirs with huge bottom water and high permeability are generally developed with high flow rate. After long-term water flooding (LTWF), the water flooding characteristics are quite different from that of original reservoir. In this paper, the effects of the PV number, viscosity, and displacement rate during LTWF are studied through experiments. The mechanism is analyzed based on analysis of changes in oil composition, rock mineral composition and wettability. The oil-water relative permeability curves, oil recovery and wettability were obtained with new experiments methods, which avoids the oil metering error by measuring oil and water separately. The research indicates that when the viscosity increases, the water phase permeability decreases, the residual oil saturation increases, and the water content rate increases earlier. A higher water flooding rate results in a higher ultimate recovery. A higher asphaltene content results in a higher viscosity and more oil-wet reservoir conditions. After LTWF, the wettability tends to water-wet, which is more favorable for heavy oil recovery. Moreover, LTWF reduces the clay content, which creates a more water-wet surface and a larger reservoir pore throat environment. This research provides insightful characteristics of offshore sandstone oil reservoirs, which can be used to enhance oil recovery.

Water-wettability reduction of an anionic hybrid fluorinated surfactant and depressurizing behavior in super-low permeability sandstone reservoirs

A Novel hybrid fluorinated surfactant, sodium 2-[2-(perfluorooctyl)] acetoxy ethanesulphonate (HFS8) was synthesized. The objective of HFS8 was to reduce the amount of trapped water on the rock surface and the capillary pressure in super-low permeability sandstone reservoirs. Its critical micelle concentrations (cmcs) were 0.4 g/L in water and 30 g/L NaCl at 30 °C. The diameters of globular micelles were mostly circa 30 nm in water at the cmc. For the brine at the cmc, the contact angle reached 75.62°; the surface and interface tensions were 13.72 and 2.81 mN/m respectively. The micellization of HFS8 was entropy-driven and easier than the hydrocarbon surfactants. The water phase permeability of core and the oil recovery ratio were increased substantially using HFS8 as a wettability-altering agent, and wettability alteration was more effective than interface activity for depressurization. The amount of injected water increased observably after small amounts of HFS8 was injected into the super-low permeability core.

Physical Experiment and Numerical Simulation of the Depressurization Rate for Coalbed Methane Production.

The influence of the depressurization rate on coalbed methane desorption and percolation was studied using physical experiment and numerical simulation. First, low-field nuclear magnetic resonance technology provided a new approach to conduct desorption experiments with different depressurization schemes and obtain the compressibility (Cf) of coal samples. Then, the productivity calculation of different depressurization schemes was carried out via numerical simulation. The results showed that the first-slow-then-fast (FSTF) depressurization scheme had the highest desorption efficiency (94%), followed by one-stop desorption (85%), first-fast-then-slow desorption (79%), and uniform depressurization desorption (61%). T2 cutoff values and the corresponding compressibility were obtained by the saturation–centrifugation method and spectral morphology method, and a high-precision permeability expression for dynamic evaluation of numerical simulation was established by the historical production data fitting approach. Through numerical simulation, high production efficiency can be achieved using depressurization rates of medium (15 kPa/d) and FSTF schemes (8 & 50 kPa/d), and depressurization funnel expansion in the single-phase water flow stage plays a decisive role in stable and high-yield production in the later stage. Thus, the FSTF pressure reduction strategy could be advocated to promote gas production. Slow depressurization should be applied in ineffective desorption and the slow desorption stage for saturated coal seam or single-phase flow stage for undersaturated coal seam, given the higher single-phase water permeability. During the rapid and sensitive desorption stage, rapid depressurization is recommended because of large desorption capacity and low water phase permeability. This paper provides a possibility for the optimization of coalbed methane field production management.

Investigation into the effect of polymer microspheres (PMs) on oil-water relative permeability and oil-in-water emulsion stability for enhanced oil recovery

A new gel particle named pore-scale polymer microspheres (PMs) has been considered as an effective chemical enhanced oil recovery (EOR) agent used for conformance control. But how to achieve deep profile control of PMs remains some problems. This work aimed at investigating the effect of PMs on oil-water relative permeability and oil-in-water emulsion stability. The results indicated that as PMs diameter matched well with pore-throats size, the PMs could exhibit a superior dynamic migration and plugging performance in the core; in this scenario, in the course of PMs flooding and subsequent water flooding, water phase permeability fluctuated obviously, and oil phase permeability increased and then decreased. Additionally, it was observed that the PMs could reduce the negative influence of elevated mobility ratio caused by the increment in oil viscosity to promote oil seepage. The zeta potential results indicated that the PMs facilitated enhancing oil-in-water emulsion stability, predominantly as a result of the increase of electrostatic repulsion between oil droplets, and deceleration of floating and convergence of oil droplets.

Impact of pore structure and clay content on the water-gas relative permeability curve within tight sandstones: A case study from the LS block, eastern Ordos Basin, China

The water-gas relative permeability of tight sandstones governs the gas production performance and recovery efficiency in a gas reservoir. Reservoir heterogeneity cannot be neglected when we extrapolate water-gas relative permeability curves. However, efforts to determine the variation with rock types and controls of the gas and water permeability have proven insufficient. Rock composition and pore structures play an important role in the spatial variation of water-gas relative permeability and vary with diagenesis evolution. In this study, we investigated the influence of pore-throat structure, clay content and cements on the water-gas relative permeability curves within tight sandstones using casting thin sections, field emission scanning electron microscopy (FESEM), X-ray diffraction (XRD), high pressure mercury injection (HPMI), and gas displacement tests on samples from the LS Block, eastern Ordos Basin, China. The results show that there is a weak relationship between the spatial variation of the water-gas relative curves and the physical properties and pore size distribution of tight sandstones. The length of the two-phase flow zone is not closely related to the porosity and permeability in tight sandstones. The gas relative permeability of the crossing point is closely related to the gas permeability, not the water phase permeability. Nevertheless, the clay content is positive to the gas saturation of the crossing point and the length of the two-phase flow. Subsequently, the water-gas relative permeability curves are divided into three types based on the simultaneous vadose region area (SVRA). Finally, the genesis of the change in the water and gas relative permeability of each type is analyzed.

Formation permeability evaluation and productivity prediction based on mobility from pressure measurement while drilling

Based on the measurement mechanism of mobility in pressure measurement while drilling, through analyzing a large number of mobility data, it is found that under the condition of water-based mud drilling, the product of mobility from pressure measurement while drilling and the viscosity of mud filtrate is infinitely close to the water phase permeability under the residual oil in relative permeability experiment. Based on this, a method converting the mobility from pressure measurement while drilling to core permeability is proposed, and the permeability based on Timur formula has been established. Application of this method in Penglai 19-9 oilfield of Bohai Sea shows: (1) Compared with the permeability calculated by the model of adjacent oilfields, the permeability calculated by this model is more consistent with the permeability calculated by core analysis. (2) Based on the new model, the correlation between the calculated mobility of well logging and the actual drilling specific productivity index bas been established. Compared with the relationship established by using the permeability model of an adjacent oilfield, the correlation of the new model is better. (3) Productivity of four directional wells was predicted, and the prediction results are in good agreement with the actual production after drilling.

The research of relative permeability curve for microbial flooding in Baolige oilfield

To adequately simulate environment of Baolige oilfield reservoir, research the seepage variation of microbial in the reservoir, we selected the current microbial flooding system, nature core, dehydration crude oil and injection water of Baolige oilfield. And the evaluation experiments of microbial flooding system and the relative permeability experiments of water flooding and microbial flooding were carried out. Results showed that the flooding system had obvious effect to reduce the emulsification, viscosity and IFT. Comparing to the water flooding, the two-phase seepage area expanded, oil phase permeability endpoint shifted to the right, and residual oil saturation decreased when using microbial flooding. The water phase permeability decreased and the oil phase permeability increased. The relative permeability in the isotonic point changed little, but shifted to the right. Microbial flooding anhydrous recovery period was longer, and the anhydrous recovery rate was higher. In the condition of the same injection, microbial flooding had higher degree of reserve recovery and the displacement pressure was lower. The experiment results fully reflected the two-phase flow in the microbial flooding process, and provided important parameters and basic basis for the prediction and effect evaluation of microbial flooding.