Water Flooding Development Research Articles

Interwell Connectivity Analysis Method Based on Injection–Production Data Time and Space Scale Coupling

In this paper, aiming at the challenges of injection–production optimization, especially the contradiction between injection and production in water flooding development of oil and gas fields in China, an interwell connectivity analysis method (TAGNN) based on the time–space scale coupling of injection–production data is proposed. This method uses the existing injection–production well data, combined with the reservoir system seepage mechanics law, to quantitatively characterize and evaluate the interwell connectivity, which overcomes the limitations of traditional methods. The TAGNN method introduces asymmetric time alignment and advanced feature extraction technology to solve the problem of asymmetric injection–production data in time dimension, and considers the spatio-temporal scale coupling characteristics of injection–production data, which can capture the temporal variation and spatial distribution characteristics of data at the same time. The experimental results showed that this method more accurately reflected the interwell connectivity status and improved the fitting and prediction accuracy, compared with the existing GNN method. This method can promote the effective injection of water from the injection well to the production well and optimize the injection production structure and development plan, thereby improving the recovery rate.

Inversion of interlayer scale using dynamic data of production wells in bottom water reservoirs: Sangtamu Oilfield, Tarim basin

The target reservoir is a typical blocky bottom water reservoir. There are several interlayers of varying scales inside it, which impact the characteristics of the oil production and water breakthrough curves of the wells in the water flooding development oilfield, resulting in strong heterogeneity within the reservoir. The Sangtamu Oilfield has an average well spacing of approximately 600 m, causing a challenge in accurately identifying the range of small-scale interlayer spreading. This, in addition, challenges the subsequent 3D geological modeling process. This paper proposes a method to accurately characterize the size of various interlayers in a reservoir by using production dynamics data from bottom water reservoirs to invert the interlayer scale. By classifying the water breakthrough curve styles derived from theoretical testing, the range of reservoir internal interlayer scales is compared and inverted based on the actual water breakthrough styles of wells in the Sangtamu oil field. In the process, many interlayer scales derived from various types of geologic data acquisition were combined to form a quantitative geologic knowledge database of interlayers that synthesizes both dynamic and static data. This method has been applied in the Tarim Basin’s Sangtamu Oilfield, where the reservoir numerical simulation history was used to fit the model. This resulted in an overall fitting coincidence rate of 96% in the Sangtamu Oilfield and a single-well fitting coincidence rate of over 90% in well LN14. This method offers a new viewpoint on characterizing the interlayer’s scale in the area of the non-dense well network.

Practical Streamline Method for Quantitatively Characterizing Waterflooding in Narrow Channel Reservoirs.

In waterflooding development of narrow channel reservoirs, the water cut rises quickly, and the reservoir becomes nearly fully flooded, yet oil recovery remains low. The narrow strip sand body and long-term water injection create a complex oil and water distribution, making it difficult to evaluate the degree of reservoir utilization during waterflooding. This paper establishes a practical streamline method to quantitatively characterize the waterflooding mobilization degree of narrow channel reservoirs. The streamline method, based on the boundary element method, first characterizes the narrow channel reservoir with complex morphologies and calculates the pressure field. Then, the velocity field is determined, and the streamlines are tracked using the Euler method. The characteristic line method is adopted to solve the saturation equation along each streamline, resulting in the overall saturation distribution of the model. Compared to the stream-tube and numerical simulation methods, the practical streamline method has several advantages, including the automatic generation of flow paths, low calculation dimensions, fast calculation speed, and high calculation accuracy. The method accurately describes the complex boundaries of the channel, realizes the quantitative characterization of waterflooding mobilization degree partitioning, and clarifies the streamline patterns and oil-water flow processes. Finally, the method was applied to a typical narrow channel reservoir to quantitatively evaluate the waterflooding mobilization degree of a well group, resulting in reasonable development and adjustment suggestions. These findings provide guidance for development adjustments in similar types of narrow channel reservoirs.

The Temporal and Spatial Evolution of Flow Heterogeneity During Water Flooding for an Artificial Core Plate Model

In the process of reservoir water flooding development, the characteristics of underground seepage field have changed, resulting in increasingly complex oil–water distribution. The original understanding of reservoir physical property parameters based on the initial stage of development is insufficient to guide reservoir development efforts in the extra-high water cut stage. To deeply investigate the spatio-temporal evolution of heterogeneity in the internal seepage field of layered reservoirs during water flooding development, water–oil displacement experimental simulations were conducted based on layered, normally graded models. By combining CT scanning technology and two-phase seepage theory, the variation patterns of heterogeneity in the seepage field of medium-to-high permeability, normally graded reservoirs were analyzed. The results indicate that the effectiveness of water flooding development is doubly constrained by differences in oil–water seepage capacities and the heterogeneity of the seepage field. During the development process, both the reservoir’s flow capacity and the heterogeneity of the seepage field are in a state of continuous change. Influenced by the extra resistance brought about by multiphase flow, the reservoir’s flow capacity drops to 41.6% of the absolute permeability in the extra-high water cut stage. Based on differences in the variation amplitudes of oil–water-phase permeabilities, changes in the heterogeneity of the internal seepage field of the reservoir can be broadly divided into periods of drastic change and relative stability. During the drastic change stage, the fluctuation amplitude of the water-phase permeability variation coefficient is 114.5 times that of the relative stable phase, while the fluctuation amplitude of the oil-phase permeability variation coefficient is 5.2 times that of the stable stage. This study reveals the dynamic changes in reservoir seepage characteristics during the water injection process, providing guidance for water injection development in layered reservoirs.

Causes and Evolution of High Injection–Production Ratios in Low-Permeability Reservoirs: The Role of Water Absorption in Barrier and Intercalated Layers

During the waterflood development of low-permeability reservoirs, the lithology of barrier and intercalated layers adjacent to the reservoir, with specific permeability and porosity, has a significant impact on water injection efficiency and reservoir energy recovery. However, current research on injection–production parameters and pressure changes in low-permeability reservoirs has not fully considered the effect of these barrier layers. Therefore, this study focuses on the Chaoyanggou Oilfield, a typical low-permeability reservoir, aiming to reveal the influence of water absorption by barrier layers on water injection efficiency and pressure changes in the reservoir. The study systematically analyzes the evolution of the injection–production ratio at different development stages by constructing a comprehensive lithological geological model and applying numerical simulation methods. It explores how the water absorption characteristics of barrier layers affect reservoir pressure and injection efficiency. The results demonstrate that argillaceous siltstone and silty mudstone have significant water absorption effects on injected water, critically influencing pressure distribution and fluid flow dynamics in the reservoir. As the water cut increases, the injection–production ratio gradually stabilizes, and the elastic water storage in the reservoir becomes crucial for establishing an effective oil displacement system. The water absorption of barrier layers accounts for 30% to 40% of the injected water. A high injection–production ratio alone does not lead to rapid energy recovery or increased production. Only by balancing the injection–production ratio, reservoir pressure, and water absorption in barrier layers can the efficiency and recovery rate of waterflood development in low-permeability reservoirs be further improved.

Well-Test Interpretation Model of Water-Injection Well in a Low-Permeability Reservoir and Its Application

For low-permeability reservoirs, water-flooding development is usually adopted, which leads to induced fractures near the wellbore, increasing reservoir heterogeneity, and making water-flooding development more complex. This paper focuses on low-permeability reservoirs, considering the characteristics of induced fractures and elliptic-flow composite, and the well-test model for injection wells is established. The mathematical model in Laplace space is obtained through dimensionless transformation and Laplace transformation. Subsequently, the Mathieu function is introduced to obtain the bottom hole pressure, and the pressure response curve is drawn. The six flow stages of the curve are defined, and the sensitivity of parameters such as half-length of induced fractures, range of lateral-swept area, permeability in unswept area, and outer boundary distance at constant pressure are analyzed. The results show that the half-length of the fracture mainly affects the linear flow of the fracture, the range of the lateral wave-affected area mainly affects the radial flow of the swept area, the permeability of the unswept area mainly affects the radial flow of the unswept area, and the outer boundary distance at constant pressure mainly affects the boundary flow. Based on the production performance of a certain injection well in J Oilfield, a series of key parameters are obtained through analytical solution model inversion, including the induced-fracture half-length of 10.32 m, the lateral-swept range of elliptic partition flow of 128.95 m, the permeability of the swept area of 6.87 mD, and the mobility ratio of 119.92, which show the superiority of the analytical solution model.

Quantitative Characterization of Surfactant Displacement Efficiency by NMR—Take the Tight Oil of Chang 8 Member of Yanchang Formation in Fuxian Area, Ordos Basin, as an Example

Surfactant flooding is a pivotal technique for enhancing oil recovery efficiency. The Chang 8 member of the Yanchang Formation in the Ordos Basin exemplifies a quintessential tight oil reservoir. Specifically, 47.9% of wells yield less than 0.1 t/d, 27.0% produce between 0.1 and 0.2 t/d, and 18.8% generate outputs ranging from 0.2 to 0.3 t/d, while only a mere 6.3% exceed production rates of over 0.3 t/d, indicating minimal efficacy of water flooding development in this context. In this study, we conducted an extensive investigation into the geological characteristics of the Yanchang 8 reservoir within the Ordos Basin, leading to the identification and evaluation of three surfactants based on their interfacial tension properties. The optimal injection concentration was determined through on-line displacement nuclear magnetic resonance imaging analysis that refined surface activity conducive to developing the Chang 8 member, ultimately resulting in increased spread volume and enhanced crude oil production from individual wells. The results indicate the following: (1) The interfacial tension of NP-10, FSD-952, and GPHQ-1 at concentrations of 0.05%, 0.1%, 0.2%, 0.3%, 0.4%, and 0.5% exhibited a pattern of initial decrease followed by an increase. The mass concentration corresponding to the minimum interfacial tension for NP-10 is identified as 0.1%, which is also the case for GPHQ-1; however, for FSD-952, this occurs at a concentration of 0.4%. Among the surface-active agents NP-10, GPHQ-1, and FSD-952, GPHQ-1 demonstrated the lowest interfacial tension value at an impressive measurement of 0.0762 mN/m. (2) When the displacement of the 0.1% GPHQ-1 surfactant reaches 10 PV, the displacement efficiency improves from 69.69% to 76.36%, representing an increase of 6.67%. The minimum pore size observed during GPHQ-1 surfactant displacement is 0.01 μm. In contrast, when the displacement of the NP-10 surfactant at a concentration of 0.1% reaches 10 PV, the efficiency rises from 68.32% to 72.02%, indicating an enhancement of 3.7%. The corresponding minimum pore size for NP-10 surfactant displacement is recorded at 0.02 μm. Furthermore, when the displacement of the FSD-952 surfactant at a concentration of 0.4% achieves 10 PV, its efficiency increases from 69.93% to 74.77%, reflecting an improvement of 4.81%. The minimum pore size associated with the activated portion of FSD-952 is noted as being approximately 0.03 μm.

Study on characteristics, efficiency, and variations of water flooding in different stages for low permeability oil sandstone

AbstractWater flooding is an important way to improve recovery in low‐permeability sandstone oil reservoirs. How to decouple the water flooding process using dynamic and static information is a hot topic. In this paper, taking the Paleocene low‐permeability oil sandstone, BY area, eastern Nanxiang Basin as an example, the microscopic water flooding process in the low‐permeability sandstone matrix was systematically investigated, and the characteristics of water channeling under the conditions of fracture existence were analyzed using the dynamic and static monitoring data. The results show that the target layer mainly develops frequently thin stacked composite sand bodies. Under the combined influence of matrix and fracture seepage, the low‐permeability sandstone developed by water flooding shows that there is a single direction of efficiency. The direction of advantageous water advancement is 45° north–east, and the speed of water flooding advancement is 2.57 m/day. Microscopic water‐drive oil experiments show that bound water is mainly distributed in the original low‐permeability sandstone as a membrane in the pore wall and as short rods in the throat. Differences in pore structure and petrophysical properties affect the residual oil content and degree of oil recovery. For sandstones with good petrophysical properties, mild water flooding can improve crude oil recovery. The increase in oil production is mainly concentrated in the early stage of water flooding development, and the increase in oil recovery degree is not significant with the increase in injection multiples in the middle and late stages. However, for sandstones with relatively poor petrophysical properties, water flooding is more effective in the early and late stages than in the middle stages. Therefore, it is necessary to adjust the water flooding measures according to the differences in the petrophysical properties of the sand body. Local tectonics and natural fracture strikes are important factors affecting the direction of the expansion of water flooding fractures. Overall, the prevention of water channeling in low‐permeability sandstones has to take into account the complex coupling between water flooding fractures, natural fractures, and hydraulic fractures.

Separate-layer balanced waterflooding development technology for thick and complex carbonate reservoirs in the Middle East

Based on the waterflooding development in carbonate reservoirs in the Middle East, in order to solve the problem of the poor development effects caused by commingled injection and production, taking the thick bioclastic limestone reservoirs of Cretaceous in Iran-Iraq as an example, this paper proposes a balanced waterflooding development technology for thick and complex carbonate reservoirs. This technology includes the fine division of development units by concealed baffles and barriers, the combination of multi well type and multi well pattern, and the construction of balanced water injection and recovery system. Thick carbonate reservoirs in Iran-Iraq are characterized by extremely vertical heterogeneity, development of multi-genesis ultra-high permeability zones, and highly concealed baffles and barriers. Based on the technologies of identification, characterization, and sealing evaluation for concealed baffles and barriers, the balanced waterflooding development technology is proposed, and three types of balanced waterflooding development modes/techniques are formed, namely, conventional stratigraphic framework, fine stratigraphic framework, and deepened stratigraphic framework. Numerical simulations show that this technology is able to realize a fine and efficient waterflooding development to recover, in a balanced manner, the reserves of thick and complex carbonate reservoirs in Iran and Iraq. The proposed technology provides a reference for the development optimization of similar reservoirs.

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.

A prediction model for water absorption in sublayers based on stacking ensemble learning method

The water absorption profile can reflect the difference in the waterflooding status of each sublayer in the injection well, and predicting the water absorption profile has important guiding significance for formulating and adjusting the waterflood development plan. Currently, numerical simulation and radioisotope logging techniques are commonly used to obtain the water absorption in sublayers. However, the complex and increasingly heterogeneous subsurface formations in China's oilfields have made it impossible for the numerical simulation to reflect the actual reservoir water injection status by splitting the water absorption into sublayers. Although the radioisotope method is more accurate, it is more expensive and has less actual test data in oilfields. In addition, the water absorption prediction model built by traditional machine learning only applies to injection wells with a small amount of water absorption profile data, and its prediction accuracy needs further improvement. In this paper, a new machine learning prediction method is proposed to build a water absorption profile prediction model by stacking ensemble learning algorithm, which achieves the prediction of water absorption in sublayers for injection wells without historical data of water absorption profiles during the development period. In our model, based on the oilfield's static geological data and dynamic production data, the input feature parameters are comprehensively selected by a hybrid feature selection method to analyze the importance of each feature. The robust base-learners are extracted from the sub-model pool by comparing and analyzing the comprehensive prediction performance of each individual model, including ANN, KNN, SVR, RF, XGBoost, LightGBM, etc. The stacking ensemble model was trained using K-fold cross-validation on a randomly divided dataset, which improves the predictive performance of an individual model by combining the advantages of multiple base-learners so that it can accurately reflect the dynamic changes of the water absorption profile. Finally, a case study from the MG study area of the DG oilfield was conducted to verify the model's predictive effect. This case shows that the stacking model proposed in this paper has better performance in predicting the water absorption in sublayers compared with the traditional single model and other ensemble models, and the model has a strong generalization ability, which proves that the method can be used in studying the prediction of the water absorption in sublayers of injection wells.

Formula system of reduce pressure and increase injection working fluid in Tamtsag oilfield

Tamtsag Oilfield is a low-permeability oilfield. In the actual production process, there will be “high water injection pressure and high injection difficulty”. In order to improve the waterflood development effect of low permeability reservoir, the selection of working fluid plays a key role. By measuring the interfacial tension between the working fluid and crude oil, combined with the depressurization and injection performance evaluation test, the anion-non-ionic surfactant working fluid system suitable for the characteristics of the Tamtsag reservoir was prepared. Under the condition that the formation water pH of oil formation in the Block 21 of Tamtsag oilfield is 7.5 and the salinity is 3000 mg/L, the injection increasing formula selected in this paper is: 0.9 % coconut oil diethanolamide+0.7 % sodium dodecylbenzene sulfonate+0.5 % anhydrous ethanol+3 % clay stabilizer. For cores with permeability lower than 80 mD, the depressurization rate can reach more than 25 %; For cores with permeability less than 15.9 mD, the depressurization rate can reach more than 30 %. The working fluid system can effectively improve the effect of increasing injection in Tamtsag Oilfield.

Mixed Horizontal Well Pattern and Fracturing Parameter Optimization of Low Permeability Reservoir

Horizontal well fracturing development is significant in improving the development effect of low permeability reservoirs and is widely applied in many low permeability reservoirs of China. In this study, the reservoir numerical simulation is used to establish different mixed horizontal well networks of the target reservoir. The result shows that the best waterflood development effect is achieved when horizontal segment orientation and crack orientation are at an angle of 45°. The horizontal segment length and fracturing parameters of mixed horizontal well networks are optimized. It is considered that the rational horizontal segment length of the horizontal well is 400 m, the rational number of cracks is 3, and the optimal crack conductivity is between 180-200 mD.m. Through the study of mixed horizontal well network and fracturing parameter optimization, the low permeability reservoir efficient horizontal well fracturing development is well guided.

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 Connectivity Analysis and Injection–Production Optimization of Strong Heterogeneous Sandstone Reservoir Based on Connectivity Method

The D reservoir in the Bongor Basin, southern Chad, is highly heterogeneous. In the stage of waterflood development, the injected water is seriously channeled along the dominant channel, and the water drive effect becomes worse. At the same time, due to the strong edge and bottom water, the water flooding situation is aggravated, the water cut is increased, and the development efficiency is reduced. To accurately identify the inter-well connectivity relationship, we developed a reservoir inter-well connectivity model based on the principle of inter-well connectivity and dynamic production data and reservoir geological parameters. Thus, the plane water injection split coefficient and water injection efficiency of each reservoir layer were obtained. The results are in good agreement with the calculation results of inter-well connectivity through verification with field tracer interpretation. The practical application results show that the method can increase the annual output of oil by 1.3%, which has a good oil increase effect. In this study, a model of inter-well connectivity in multi-layer sandstone reservoirs was established for the first time. The production performance of the model injection–production well was optimized in real time by a historical fitting and production optimization algorithm and then applied to real reservoirs, so that it could effectively improve the oilfield development and optimize the injection–production structure.

Integral Effects of Porosity, Permeability, and Wettability on Oil–Water Displacement in Low-Permeability Sandstone Reservoirs—Insights from X-ray CT-Monitored Core Flooding Experiments

Porosity, permeability, and wettability are crucial factors that affect the oil–water displacement process in reservoirs. Under subsurface conditions, the integral effects of these factors are extremely difficult to document. In this paper, waterflooding experiments were carried out using a core flooding system monitored with X-ray dual-energy CT. The mesoscale, three-dimensional characteristics of water displacing oil were obtained in real time. The integral effects of porosity, permeability, and wettability on the waterflooding in the low-permeability sandstone reservoirs were investigated. It was found that if the reservoir rock is water-wet, then the residual oil saturation decreases gradually with increasing porosity and permeability, showing an increasing waterflooding efficiency. On the contrary, if the reservoir rock is oil-wet, the residual oil saturation gradually increases with improving porosity and permeability, showing a decreasing waterflooding efficiency. The porosity, permeability, and wettability characteristics of reservoirs should be comprehensively evaluated before adopting technical countermeasures of waterflooding or wettability modification during oilfield development. If the porosity and permeability of the reservoir are high, water-wet reservoirs can be directly developed with waterflooding. However, it is better to make wettability modifications first before the waterflooding for oil-wet reservoirs. If the porosity and permeability of the reservoir are poor, direct waterflooding development has a better effect on oil-wet reservoirs compared with the water-wet reservoirs.

Characterization of the effects of wettability and pore pressure on the interfacial behavior of CO2 interacting with oil-water two-phase on pore walls

To date, research studies on film-like residual oil have mainly focused on reservoirs in the late stage of water flooding development. However, there have been relatively few studies on film-like residual oil on pore walls after gas flooding. In this study, a molecular dynamics simulation method was used to investigate the behavior characteristics of fluid-fluid and fluid-solid interfaces and the exploitation potential of film-like remaining oil in water-wet, mixed-wet and oil-wet systems under different pore pressures after CO2 flooding. The results indicated that in the oil-in-water system, the cohesive energy density (CED) of the water films was much greater than that of the CO2 and decane components, and the CED of water films in the water-wet systems was slightly greater than the CED of water films in the mixed-wet systems. Regardless of the water-wet or mixed-wet systems, Einter(CO2−decane) was the strongest between the components. Therefore, CO2 molecules could easily enter the oil films and divide the oil phase into clusters of different sizes. The interfacial tension at the CO2 + decane/H2O and H2O/SiO2 interfaces in both the water-wet and mixed-wet systems decreased with increasing pressure. Under the same pressure, the degree of decrease in interfacial tension at the CO2 + decane/H2O interface in the mixed-wet systems was smaller than that in the water-wet systems. The degree of decrease in interfacial tension at the H2O/SiO2 interfaces in the mixed-wet systems was generally greater than that in the water-wet systems. In the water-in-oil system, because the water films isolated the oil films from the CO2 molecules, the interaction energy between the CO2 molecules and oil phase was weak, so the oil films remained on the quartz surfaces. Due to the existence of the hydrogen bond network inside the water phase, the morphological changes in water films were also small when the CO2 molecules interacted with the water phase. At the CO2/H2O interfaces, under the same pressure, the resistance of CO2 molecules to pass through the water films in the oil-wet systems was greater than that in the mixed-wet systems, and the CO2 molecules in the mixed-wet systems were more likely to enter into the water films. The interfacial tension reduction at the interfaces in the mixed-wet systems was smaller than that in the oil-wet systems. At the H2O/decane interfaces, the power of CO2 molecules breaking through the oil-water interfaces and entering into the oil phase in both the mixed-wet and oil-wet systems was basically equal under the same pressure. The interfacial tension reduction at the interfaces in the mixed-wet systems was almost equal to that of the oil-wet systems. At the decane/SiO2 interfaces, the CED of the oil films in the oil-wet systems was greater than that in the oil-wet systems under the same pressures, and the Einter(CO2−SiO2) in the mixed-wet systems was greater than the Einter(CO2−SiO2) in the oil-wet systems, indicating that CO2 molecules were more easily adsorbed on the quartz surfaces in the mixed-wet systems, and the interfacial tension reduction at the interfaces in the mixed-wet systems was greater than that of the oil-wet systems. The interfacial tension at the CO2/H2O, H2O/decane and decane/SiO2 interfaces in both the mixed-wet and oil-wet systems decreased with increasing pressure. The research results provide a reference for understanding the fluid-fluid and fluid-solid interface behaviors and the exploitation potential of film-like residual oil during CO2 gas flooding.

Evaluation of Foam Gel Compound Profile Control and Flooding Technology in Low-Permeability Reservoirs

In the waterflooding development of fractured ultra-low permeability reservoirs, the heterogeneity is becoming increasingly serious. The development of large fracture channels leads to serious water channelling and low recovery, and the effect of conventional profile control is not ideal. This paper proposed gel foam composite profile control and flooding technology to solve the above problems. Herein, the new intelligent gel and foaming agent systems were optimized through laboratory experiments, and their performance was evaluated. The new intelligent gel system has the characteristics of low viscosity, easy preparation, good injection, slow cross-linking, high strength, and long-term effectiveness. The injection parameters were optimized, and the indoor injection scheme was formulated, that is, the optimal injection volumes of gel and foam slugs were 0.3 and 0.6 PV, respectively. The injection sequence of composite slugs was to inject gel slugs first, then foam slugs. The injection mode of air foam slugs was multiple rounds of small slug injection. The final recovery rate in the indoor dual tube oil displacement experiment reached 35.01%, increasing by 23.69%. Furthermore, an oil output increase of 899 t and an average water cut decrease of 5% were acquired in the oil field test. It shows that the injection scheme can effectively improve oil recovery. The gel foam compound profile control and flooding technology herein has good adaptability in similar reservoirs and has good promotion prospects.

Simulation study of polymer flooding performance: Effect of salinity, polymer concentration in the Malay Basin

The major problem of the water flooding development process is the flood process's high mobility and viscous fingering. Previous studies have shown that polymer flooding is viable and can recover bypassed oil. However, the mechanism of the polymer flooding process is still tenuous in literature. Therefore, in this study, a two-dimensional model was used to simulate polymer flooding and forecast the mechanism of the polymer flood in the presence of electrolytes. Likewise, the effect of pH, pressure, and temperature on the polymer flooding process was investigated. Thereafter, the model was validated with an independent set of experimental data from the literature. The results show that the polymer flooding mobility ratio (M) was 0.36 indicating a favorable mobility control, thereby improving oil recovery by 60% of original oil in place (OOIP). In comparison, to water flooding mobility ratio of 3.6, which was greater than 1, thus resulted in viscous fingering, early water breakthrough, and oil recovery of 36% OOIP. Besides, at high salinity concentrations, the polymer adsorption was 3.3 mg/g compared to 2.2 mg/g from the experimental results. This indicates that the simulation results were consistent with the experimental results at the same concentration. Likewise, the simulation and experimental studies suggest high oil recovery was obtained at a higher injected pore volume. Finally, it can be concluded from this study that mechanical trapping and adsorption of the polymer on the pores of the porous media were the dominant mechanisms during the polymer flooding.

Pore-Scale Oil-Water Flow Behaviors in Different Development Adjustment Schemes for Enhancing Oil Recovery in Waterflooding

Development mode adjustment is an important measure to further enhance oil recovery after primary waterflooding. Investigating the oil-water flow behaviors in the pores is significant to deepening the understanding of the macrobehavior of waterflooding and the designation of the reservoir development plan. Previous studies mainly focused on the change in recovery factor and macroflow characteristics, while less attention was paid to the causes of the change in recovery factor and the difference in macrocharacteristics. In this paper, the numerical simulation technology by coupling the Navier-Stokes equation with the method of volume of fluid is employed to investigate the dynamic formation mechanism of the remaining oil at pore-scale in the primary waterflooding, and then the pore-scale oil-water two-phase behaviors under three waterflooding development adjustment schemes: changing flooding direction, turning extraction well to injection well, and increasing injection rate are studied. The research shows that when the viscous resistance of the water-bearing channel is less than the sum of the capillary barrier and drainage capillary resistance (the resistance in the displacement of wetting phase displacement using the nonwetting phase), the remaining oil is formed. Water➔oil➔water➔oil displacement mode is formed in the process of changing flow direction, which makes the force of the phase interface tend to balance, reduces the capillary effect in waterflooding, and improves oil recovery. In the process of developing the scheme of turning extraction into an injection well, through multipoint injection, it advances from the central water-bearing area to the oil-bearing area on both sides in multiple paths, forming a larger spatial spread range than that in the change of flooding direction. Under the influence of the capillary barrier effect and drainage capillary resistance, when the injection rate is increased, the remaining oil can restart to move only when the flowing rate exceeds a certain value. The small viscous resistance in the water-bearing channel and the lateral resistance from the capillary barrier limiting the lateral sweep of water are the primary reasons for the insignificant improvement of oil recovery under the condition of a low liquid injection rate. The findings of this study can help for better understanding of pore-scale flow mechanism behaviors and their influences on the macroscopic development features in the waterflooding process.