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The productivity of low-permeability reservoirs is affected by multiple factors. After the development of water injection by pressure drive, it will also be affected by factors such as construction, resulting in large differences in the productivity of different oil wells. According to reservoir engineering knowledge, the factors affecting the productivity of pressure drive water injection development are preliminarily determined. The conceptual model of pressure drive water injection development of low permeability reservoir is established by numerical simulation method. Combined with orthogonal design, the main control factors of pressure drive water injection development productivity are determined. The main control factors include injection production well spacing, water injection volume of pressure drive measures, water content before pressure drive, porosity, and quantitative analysis of the main control factors. Through correct analysis and evaluation of these factors, it provides guiding significance for the productivity prediction of pressure drive water injection development in low permeability reservoirs and the optimization of pressure drive water injection scheme.

In view of the practical problems faced by the CO2 sequestration in aquifers, this paper considers the influence of injection rate, water production rate, and other factors on CO2 injection amount, residual sequestration amount, dissolution sequestration amount, and pressure evolution under the constraint of cap rock breakthrough pressure is studied by using a numerical simulation method, and the sequestration potential is evaluated. The results show that: (1) Water production measures can improve CO2 injection, dissolution sequestration, and residual sequestration. (2) Low ratio of vertical permeability to horizontal permeability is conducive to the security and stability of CO2 sequestration in the long term. The research content provides support for the evaluation of CO2 saline aquifer sequestration potential and field practice.

Traditional machine learning methods are difficult to accurately forecast oil production when development measures change. A method of oil reservoir production prediction based on normalized mutual information and a long short-term memory-based sequence-to-sequence model (Seq2Seq-LSTM) was proposed to forecast reservoir production considering the influence of liquid production and well spacing density. First, the marine sandstone reservoirs in the Y basin were taken as the research object to establish the sample database. Then, the feature selection was carried out according to the normalized mutual information, and liquid production, production time, equivalent well spacing density, fluidity and original formation pressure were determined as input features. Finally, a Seq2Seq-LSTM model was established to forecast reservoir production by learning the interaction from multiple samples and multiple sequences, and mining the relationship between oil production and features. The research showed that the model has a high accuracy of production prediction and can forecast the change of production when the liquid production and well spacing density change, which can provide scientific recommendations to help the oilfield develop and adjust efficiently. [ABSTRACT FROM AUTHOR]

Predicting the productivity of fractured five-spot patterns in low permeability reservoirs at high water cut stages has an important significance for the development and optimization of reservoirs. Taking the reservoir heterogeneity and uneven distribution of the remaining oil into consideration, a novel method for predicting the transient productivity of fractured five-spot patterns in low permeability reservoirs at high water cut stages is proposed by using element analysis, the flow tube integration method, and the mass conservation principle. This new method is validated by comparing with actual production data from the field and the results of a numerical simulation. Also, the effects of related parameters on transient productivity are analyzed. The results show that increasing fracture length, pressure difference and reservoir permeability correspond to an increasing productivity. The research provides theoretical support for the development and optimization of fractured five-spot patterns at the high water cut stage.

Difficulty in water injection during the water injection development (water injection production refers to the injection of water into the reservoir from injection wells during the development process of an oil field; due to its good economic efficiency and high feasibility, it has become the main method of oil field development) process of the G block reservoir is an important problem to solve. Three cores of the G block are used as the object of this study, and the laser particle size test is conducted on the target core to obtain the particle size distribution of the core. X-ray diffraction mineral content analysis is used to obtain the proportion of different mineral contents. On this basis, online nuclear magnetic technology is used to carry out the research on the change of reservoir physical properties during the high-magnification water injection process. The experiment shows that three cores (cores 8-2, 16-1, and 9) are identified as medium sandy fine sandstone with silt (the three-level naming method was adopted and the name has been changed to medium sandy fine sandstone containing silt, because the proportion of fine sand is greater than 50%, the content of medium sand is between 25%~50%, and the content of silt is between 10%~25%), medium sandy fin sandstone containing silt, and silt fine sandstone, by laser particle size testing. Their clay mineral contents are 2.47%, 2.51%, and 4.76%, respectively; the permeability (water) of the three cores continues to decrease with the increase in water injection, but the nuclear magnetic porosity and the signal intensity of different fluids in the nuclear magnetic T2 and nuclear magnetic two-dimensional spectrum show different variation patterns with the increase in water injection. The clay minerals of core 8-2 and core 16-1 are relatively small. The nuclear magnetic porosity increases rapidly to the maximum value and then decreases slowly with the increase in water injection. The right peak signal intensity in the T2 spectrum rises first and then drops, while the clay mineral content of core 9 is relatively high. The change trend of nuclear magnetic porosity is firstly decreasing and then increasing, and the signal intensity of the right peak in the T2 spectrum decreases first and then increases. The research concludes that in the early stage of water injection, clay minerals undergo hydration and a small amount of particle migration; in the later stage of water injection, due to the scouring effect of water, the fine silt and clay minerals in the cement easily fall off and migrate to the pore throat to the block. Some damage to the pore throat leads to a decrease in permeability, thus affecting the development effect. [ABSTRACT FROM AUTHOR]

Interfacial dilational rheology is one of the important means to explore the interfacial properties of adsorption films. In this paper, the interfacial rheological properties of the mixed system of sulfobetaine ASB with a linear alkyl group and two anionic surfactants, petroleum sulfonate (PS) and alkyl polyoxyethylene carboxylate (AEC), were investigated by interfacial dilational rheology. The effect of the introduction of polymer hydrophobically modified polyacrylamide (HMPAM) on the interfacial properties of the mixed system was analyzed. In this experiment, the surfactant solution was used as the external phase and n-decane was used as the internal phase. A periodic sinusoidal disturbance of 0.1 Hz was applied to the n-decane droplets, and the changes of parameters such as droplet interfacial tension and interfacial area were monitored in real time with the help of a computer. The results show that the betaine ASB molecule responds to the dilation and compression of the interface through the change of ion head orientation, while the feedback behavior of petroleum sulfonate PS and AEC molecules embedded with oxygen vinyl groups in the molecule is diffusion and exchange between the interface and the bulk phase. Therefore, the interface film formed by ASB alone is higher, and the film formed by PS and AEC molecules alone is relatively lower. After adding two kinds of anionic surfactants to the betaine system, the ionic head of PS or AEC molecules will be attached to the positive center of the hydrophilic group of ASB molecules by electrostatic attraction and no longer adsorb and desorb with the interface deformation. The interfacial rheological properties of the compound system are still dominated by betaine, with higher dilational modulus and lower phase angle. When a small amount of HMPAM is added, or the content of hydrophobic monomer AMPS in the bulk phase is low, the intermolecular interaction at the interface is enhanced, the slow relaxation process is intensified, and the interfacial film strength is increased. As the content of AMPS further increases, hydrophobic blocks and surfactant molecules will form interfacial aggregates similar to mixed micelles at the oil-water interface, which will regulate the properties of the film by affecting the adsorption of surfactants at the interface. As long as the interfacial tension is the same, the properties of the interfacial film are the same. Based on the colloid interface science and the background of enhanced oil recovery, this study provides a reference for the field application of chemical flooding formulations. [ABSTRACT FROM AUTHOR]

After the near-abandoned production wells in the high part of the fault block reservoir are closed for a period of time, the remaining oil in the low part will accumulate at the fault in the high part to produce secondary enrichment. At present, research on the secondary enrichment of the remaining oil mainly focuses on the remigration method of the remaining oil, and there is less research on the mechanism of the secondary enrichment of the remaining oil. In view of the above problems, a planar numerical model is established to analyse the remaining oil secondary enrichment law, combined with the longitudinal numerical model to analyse the mechanism of the remaining oil secondary enrichment, and nine factors are selected to study their influence on the remaining oil secondary enrichment law, further determining the main control factors through sensitivity analysis. Based on the numerical simulation results, the reservoir conditions conducive to the secondary enrichment of the remaining oil are determined. The research shows that the remaining oil secondary enrichment mechanism includes pressure redistribution after well shut-in and the comprehensive effect of the micro force. The increase in the formation dip angle, permeability and water injection intensity before well shut-in is beneficial to accelerate the secondary enrichment of the remaining oil. Permeability and formation dip angle are the main controlling factors of positive correlation parameters, and the shut-in water cut is the main controlling factor of negative correlation parameters and the most sensitive. In addition, when the permeability is greater than 200 mD, the formation dip angle is greater than 9°, and the shut-in water cut is less than 95%, which is conducive to the secondary enrichment of the remaining oil. This study has reference significance for the field to understand the mechanism and influencing factors of the secondary enrichment of the remaining oil. [ABSTRACT FROM AUTHOR]

The prediction of permeability and the evaluation of tight oil reservoirs are very important to extract tight oil resources. Tight oil reservoirs contain enormous micro/nanopores, in which the fluid flow exhibits micro/nanoscale flow and has a slip length. Furthermore, the porous size distribution (PSD), stress sensitivity, irreducible water, and pore wall effect must also be taken into consideration when conducting the prediction and evaluation of tight oil permeability. Currently, few studies on the permeability model of tight oil reservoirs have simultaneously taken the above factors into consideration, resulting in low reliability of the published models. To fill this gap, a fractal permeability model of tight oil reservoirs based on fractal geometry theory, the Hagen–Poiseuille equation (H–P equation), and Darcy's formula is proposed. Many factors, including the slip length, PSD, stress sensitivity, irreducible water, and pore wall effect, were coupled into the proposed model, which was verified through comparison with published experiments and models, and a sensitivity analysis is presented. From the work, it can be concluded that a decrease in the porous fractal dimension indicates an increase in the number of small pores, thus decreasing the permeability. Similarly, a large tortuous fractal dimension represents a complex flow channel, which results in a decrease in permeability. A decrease in irreducible water or an increase in slip length results in an increase in flow space, which increases permeability. The permeability decreases with an increase in effective stress; moreover, when the mechanical properties of rock (elastic modulus and Poisson's ratio) increase, the decreasing rate of permeability with effective stress is reduced. [ABSTRACT FROM AUTHOR]

The siltstone reservoir with many small layers of pay zones is usually produced by slant holes. However, severe sand blockages take place when the siltstone reservoir is developed by slant holes. Currently, the sand blocking mechanisms and the effect of sand blocking on productivity of slant well are still challenges for engineers and scholars. In this paper, based on the existing productivity model of inclined slant wells, the mechanical skin factor, which describes the effect of sand blocking on productivity, is proposed. Meanwhile, many experimental works have been done to investigate the sand blocking mechanisms in siltstone reservoirs. From the experimental work, it is concluded that with the increase of displacement PV number and displacement flow rate, the permeability of sand control system decreases by 40%. When solid particles enter the casing and block the gravel and sand control screen in the annulus, the skin factor increases sharply and the productivity decreases by more than 80%. Through the productivity calculation of multilayer sand control wells, it is considered that larger gravel packing radius can keep particles away from the well bore, which is helpful to ensure oil well productivity. Furthermore, the influence of differential filling radius on the fluid production capacity of each layer of sand control well is analyzed. It is proved that optimizing the filling radius of each layer can improve the production effect of mediate- and low-permeability layers. This method has been applied in Kendong #12 block. The daily oil production rate is increased by 9.61 t/day, and the oil recovery of this block is increased by 2.12%. [ABSTRACT FROM AUTHOR]

Surface active components, salt component, and polar molecules in the fluid may adsorb on the solid surface and form the boundary layer during low-speed flow in a porous medium, which will influence the flowing law in the porous medium. Previous studies on flowing in low-permeability reservoirs mainly focus on the effects of the threshold pressure gradient. But few of them have considered the time-varying effect of the boundary layer thickness in solving the numerical simulation. The correlation among the boundary layer thickness and pressure gradient was established by regressing the experimental data of boundary thickness versus pressure. On this basis, the mathematical model of oil-water two-phase flow which involves influence of the boundary layer was constructed, and the comparative analysis of the development effect is performed. Results demonstrated that the boundary layer thickness is sensitive to the throat radius and pressure gradient, and the boundary layer thickness decreases dynamically with the increase of pressure gradient. The displacement velocity and accumulative oil production with boundary layer effect decrease when comparing with that without the boundary layer effect. Meanwhile, the boundary layer accelerates the breakthrough of water. With the reduction of production pressure difference, the difference between accumulative oil production with and without the boundary layer effect increases, which indicate that the dynamic effect of the boundary layer is intensified. [ABSTRACT FROM AUTHOR]

In general, there is stress sensitivity damage in tight reservoirs and fractures. Furthermore, the flow in tight reservoirs is the low-velocity non-Darcy flow. Currently, few researches of pressure analysis for volume fracturing vertical well are conducted simultaneously considering the low-velocity non-Darcy flow and stress sensitivity. In the paper, a novel flow model of a volume fractured vertical well is proposed and solved numerically. Firstly, the threshold pressure gradient, permeability modulus, and experimental data are, respectively, utilized to characterize the low-velocity non-Darcy flow, matrix stress sensitivity, and fracture stress sensitivity. Then, a two-region composite reservoir is established to simulate the vertical well with volume fracturing. After that, the logarithm meshing method is used to discrete the composite reservoir, and the flow model is solved by the method of finite difference and IMPES. Finally, the model verification is conducted, and the effects of the low-velocity non-Darcy flow and stress sensitivity on the pressure and pressure derivative are analyzed. The six flow regimes are identified by the dimensionless pressure and pressure derivative curve. They are, respectively, the fracture linear flow regime, early transition flow regime, radial flow regime, crossflow regime, advanced transition flow regime, and boundary controlling flow regime. The stress sensitivity and threshold pressure gradient have a great effect on the dimensionless pressure and pressure derivative. With the increase of reservoir stress sensitivity, the pressure and pressure derivative are upward at the advanced transition flow and boundary controlling regimes. However, the pressure and pressure derivative are downward at the advanced transition flow and boundary controlling regimes when the fracture sensitivity increases. An increase in the threshold pressure gradient results in a high dimensionless pressure and pressure derivative. This work reveals the effects of low-velocity non-Darcy flow and stress sensitivity on pressure and provides a more accurate reference for reservoir engineers in pressure analysis when developing a tight reservoir by using the volume fracturing vertical well. [ABSTRACT FROM AUTHOR]

Multiple fractured horizontal wells have been widely used to develop unconventional tight gas reservoirs. Currently, many well testing models were established to study the performance of fractured horizontal wells in tight gas reservoirs. However, none of these models thoroughly takes stress-sensitivity of natural fractures and variable conductivity of artificial fractures into consideration. Based on the consideration of stress-sensitivity of natural fractures and variable conductivity of artificial fractures, a novel well testing model for fractured horizontal well in tight gas reservoirs is proposed. And the semianalytical solution of this new model is obtained by dividing the artificial fracture into different segments under the integrative methods of Laplace transformation, point source function, perturbation theory, superposition principle, and Stehfest numerical inversion. After validation, the semianalytical solution is consistent with that of Zerzar’s model (2004). Also, typical pressure and pressure derivative curves are plotted. According to typical curves, seven regimes can be derived, namely, bilinear flow, linear flow, early-time pseudoradial flow, biradial flow, intermediate-time pseudoradial flow, and pseudo-steady state interporosity flow, and late-time pseudoradial flow can be identified. In addition, this paper analyzes the impact on pressure and pressure derivative curves exerted by variable conductivity and stress-sensibility. The results show that variable conductivity mainly affects the early flow regimes, including bilinear flow, linear flow, and early-time radial flow, while the stress-sensitivity mainly affects the later flow regimes, including intermediate-time pseudoradial flow, pseudo-steady state interporosity flow, and late-time pseudoradial flow. The typical curves will ascend with the increasing of stress-sensitivity coefficient. The research provides a method for precise prediction of formation parameters and has a significant impact on the tight gas reservoir development. [ABSTRACT FROM AUTHOR]

Abstract: Based on the dual-phase unstable flow theory of oil and water, the production indices calculating method of multilayer water drive reservoirs are established, which takes the changes of rock permeability and oil viscosity into consideration. The flowing resistance and production pressure drop of every sublayer is taken as the weighting coefficient in the allocation of well productivity. The solution of pressure equation is obtained by the implicit difference equation. And the water saturation is calculated by the streamline model, which enhanced the stability of solution. Using this model the production indices such as water cut and the degree of reserve recovery can be calculated for the development unit of multilayer reservoir at different development stage. The calculation method is applied into field example and the result shows the good agreement with the actual case. This research provides an important measure for the optimization of layers recombination modes. [ABSTRACT FROM AUTHOR]

In the petroleum industry, there is a consensus that the spontaneous imbibition (SI) is important for improving the recovery of tight reservoirs. However, how great is the effect of SI on the recovery of tight reservoirs when comparing with displacement? In the paper, a model for quantitative evaluating the effects of SI and displacement on tight reservoir development is built by fractal theory and verified by comparing with published experimental data. Two evaluation parameters (EP and EPR), which can be determined by the proposed model, are introduced to discuss the problem that how great the effect of SI on the recovery of tight reservoirs when comparing with displacement is. The influences of related parameters on EP and EPR are conducted. The results show that reservoir properties have a great effect on the imbibition time. And the effects of reservoir properties on the flow rate of SI is similar to that of displacement. The effect of SI becomes significant comparing with displacement when the water viscosity decreases. However, with the decrease of contact angle or the increase of interfacial tension force (ITF), the effect of SI becomes significant. The decrease of displacement pressure difference indicates the effect of SI becoming relatively significant. When the ITF and displacement pressure difference are 35.5 mN/m and 1 × 104 Pa, respectively, the maximum oil flow rate of SI is 1.85 times of displacement. This work has a crucial role in promoting the development of tight reservoirs. • A model for quantitative evaluating the effects of SI and displacement of tight reservoirs is proposed. • The effects of reservoir properties on the flow rate of SI is similar to that of the displacement. • The effect of SI on recovery could not be ignored. [ABSTRACT FROM AUTHOR]

Currently, many investigations on fractured well productivity are conducted. However, all this productivity studies are conducted based on the initial pressure and fluid distribution. In this work, taking the reservoir damage caused by fracturing fluid and the effect of fracturing fluid injection on pressure and saturation into consideration, a flow model of multistage fractured horizontal well is built, which is composed of fracturing fluid injection model and fracturing fluid flowback and production model. Numerical solving method is utilized to solve the model and model verification are presented through comparing with the test results of 12 fractured well. The effects of fracture fluid injection rate and fracturing fluid viscosity on pressure and saturation at the end of fracturing fluid injection are analyzed. And the effects of the reservoir oil viscosity, porosity, permeability, heterogeneous and reservoir damage on flowback and production characteristic are analyzed. The results show: (1) The distances of saturation and pressure variation area from the fracture are respectively 10 m and 20 m after the fracturing fluid injection is finished. When the fracturing fluid viscosity increases from 10 mPa s to 30 mPa s, the distance of pressure variation area from the fracture decrease. But the pressure and saturation near the hydraulic fracture increases. When the injection rate increases from 0.28 m3/min to 28 m3/min, the fracture length increases and the distances of pressure and saturation variation area from the fracture increase. The pressure near the fracture with a high injection rate is larger than that with a small injection rate. (2) With the development of reservoir, the water flow rate and water cut decreases, and the oil flow rate increases firstly and then decreases. When the reservoir oil viscosity increases from 1.5 mPa s to 2.5 mPa s, water cut increases. The maximum oil flow rate decreases from 16.4 to 6.2 m3/d. With the increase of reservoir permeability, the water cut decrease. When the reservoir porosity increases, the oil flow rate, water flow rate and cumulative fluid volume increase. While, the water cut decreases with the increase of reservoir porosity. When the residual resistance factor (RRF) increases from 1 to 1.08, the oil flow rate of when the RRF equals 1 is slight larger than that of when the RRF equals 1.08. The reservoir damage has slight effect on the water flow rate and water cut. (3) The development of heterogeneous reservoir is poorer than that of homogeneous reservoir when the development conditions are the same. This work provides a more accurate method to investigate the flowback and production characteristics of fractured well. • A flow model for fracturing horizontal well is proposed with considering fracturing fluid injection. • The permeability and relative permeability are modified with considering the fracturing fluid damage. • The effects of key parameters on the pressure and production characteristics are investigated. [ABSTRACT FROM AUTHOR]

CO 2 miscible flooding in low permeability reservoirs is conducive to significantly improving oil recovery. At present, the microscopic displacement simulation of CO 2 miscible flooding is mainly reflected in the simulation of the seepage process, but the pressure control of the seepage process is lacking, and the simulation of the characterization of CO 2 concentration diffusion is less studied. In view of the above problems, a numerical model of CO 2 miscible flooding is established, and the microscopic seepage characteristics of interphase mass transfer in CO 2 miscible flooding are analyzed by multiphysics field coupling simulations at the two-dimensional pore scale. The injection velocity, contact angle, diffusion coefficient, and initial injection concentration are selected to analyze their effects on the microscopic seepage characteristics of CO 2 miscible flooding and the concentration distribution in the process of CO 2 diffusion. The research shows that after injection into the model, CO 2 preferentially diffuses into the large pore space and forms a miscible area with crude oil through interphase mass transfer, and the miscible area expands continuously and is pushed to the outlet by the high CO 2 concentration area. The increase in injection velocity will accelerate the seepage process of CO 2 miscible displacement, which will increase the sweep area at the same time. The increase in contact angle increases the seepage resistance of CO 2 and weakens the interphase mass transfer with crude oil, resulting in a gradual decrease in the final recovery efficiency. When the diffusion coefficient increases, the CO 2 concentration in the small pores and the parts that are difficult to reach at the model edge will gradually increase. The larger the initial injection concentration is, the larger the CO 2 concentration in the large pore and miscible areas in the sweep region at the same time. This study has guiding significance for the field to further understand the microscopic seepage characteristics of CO 2 miscible flooding under the effect of interphase mass transfer., Competing Interests: The authors declare no competing financial interest., (© 2023 The Authors. Published by American Chemical Society.)