Proceedings of the International Field Exploration and Development Conference 2023

In recent years, exploration in the Junggar Basin Mahu area has been making breakthroughs. Horizontal well + volume fracturing is an economical and effective development method, the initial production capacity is high, but the rate of production decline is fast, the stable production period is short and so on. According to the classification and distribution characteristics of oil layers, the tight conglomerate reservoirs can be divided into three types and six types. Based on the method of correlation coefficient and grey correlation degree, combined with the dynamic analysis of actual production, it is clear that oil saturation, horizontal section length, permeability (vertical and horizontal permeability) and high-quality reservoir length are the main geologic factors affecting productivity. The production law of each horizontal well is analyzed by grouping, the horizontal section length, displacement, proppant dose and production of the engineering factors are obviously correlated after the analysis of the classification of reservoir and the length of drilled reservoir as the classification standard. By analyzing the development factors that affect the development of horizontal wells, it is found that the pressure-sensitive effect is obviously correlated with the production. Combined with the geological factors, engineering factors and development factors that affect the development law of horizontal well volumetric fracturing, it is determined that the main control factors affecting the development law of horizontal well volumetric fracturing are pressure sensitivity effect, length of oil zone drilled, length of horizontal section, propping dose, displacement and length of first-class oil layer, it lays a foundation for efficient fracturing and development of Mahu tight conglomerate reservoir.

The Bohai Oilfield has huge reserves with viscosity greater than 350 mPa·s, but conventional methods cannot be used for development. In order to effectively utilize this portion of the reserves, this project aims to carry out small three-dimensional physical experiments on horizontal well steam flooding in the Bohai thin layer heavy oil reservoir N oilfield with a viscosity of 2000 mPa·s of 50 ℃ degassed crude oil. A thermal recovery three-dimensional physical simulation experimental device is used to establish an equal proportion physical model. The well layout method of one injection and one production is adopted, and the experimental parameters are determined using similarity criteria based on the actual injection parameters of the oilfield The influence of small well spacing on the development law of steam drive steam chamber in horizontal wells. From the experimental results, it can be seen that large well spacing horizontal wells have long heating time and long heating distance for the reservoir, large heating area for the reservoir temperature, and slow steam breakthrough, which can achieve a longer period of stable oil production and increase production. At the same time, on-site pilot experiments have achieved good development results. Through this study, it effectively guides the efficient development of thermal recovery in N oilfield and similar heavy oil fields in Bohai, providing technical support for the sustainable development of the Bohai oilfield.

Unstable pressure analysis is an important technology to monitor and evaluate the development performance of gas drive. The study divides the fluid distribution into three zones, namely, pure gas zone, miscible zone, and pure oil zone. Considering the complexity of carbonate reservoirs, a three-zone unsteady channeling well test model is established, and through perturbation transformation, pulling the Laplace transform realizes the solution of the model, obtains the solution of the unstable bottom hole pressure of gas drive in low-permeability carbonate reservoir, and analyzes the influence of reservoir physical properties and fluid physical properties on the pressure derivative. Studies have shown that the bottom hole pressure derivative curve has obvious transition characteristics in the fluid transition zone, and the distribution range of the oil and gas transition zone can be judged from this, and the inversion of reservoir parameters and fluid physical properties can be achieved by fitting a double logarithmic curve. It is found that the interface radius between the first zone and the second zone mainly affects the second stage to the fifth stage. As the interface radius decreases, the radial flow stage in the first zone gradually disappears. The interface radius of the second zone and the third zone mainly affects the sixth stage to the seventh stage. As the interface radius decreases, the radial flow stage in the second zone gradually disappears. At the same time, the radial flow in the third zone gradually expands. The findings of this study can help for better understanding of pressure transient behaviors of gas drive in low permeability carbonate reservoirs.

The K1br Formation reservoir of A Oilfield in Kazakhstan is a shallow ordinary heavy oil reservoir. The pilot development effect is poor using the cold development method, and the reserves have not been effectively utilized. In order to utilize the reservoir effectively, it is necessary to conduct research on optimizing reasonable development methods. In view of the problem that the initial production of the infill wells is reduced due to the large well spacing steam thermal development and then infilling of similar oil reservoirs at domestic and abroad, firstly, the reasonable development method is determined through literature research and combination with on-site tests of steam stimulation, secondly, the reasonable well spacing of thermal development is determined through reservoir engineering method, numerical simulation method and empirical formula, and then, the reasonable injection and production parameters are optimized. The research results indicate that steam injection thermal development is feasible for the K1br Formation reservoir, and it will have a better effect by directly adopting the 70 m × 100 m reverse nine-spot small pattern for the thermal development. After the implement of the project, the average daily oil production per well is able to increase from 0.7 t in cold development to 4.5 t in thermal development, the daily oil production level is able to increase from 2.4 t/d in 2017 to 655.9 t/d in 2021 with the oil-steam ratio of 0.74, so the steam stimulation is able to achieve better development effect.

Both indoor and on-site pilot experiments have demonstrated the enormous potential of CO2 injection to improve crude oil recovery, but there is currently no consensus on how to evaluate reservoirs suitable for CO2 injection development. Most traditional methods rely on developing subjective screening conditions; some conditions are contradictory in practical applications. In addition, the nested relationships between reservoir characteristics, fluid properties, and development stages also result in low accuracy in the prediction results obtained by an independent judgment of various parameters. This study constructed a database of actual development effects of CO2 injection in oil reservoirs, considering a total of 19 parameters such as reservoir characteristics, fluid physical properties, and development stages. The missing data was optimized using the K-nearest neighbor (KNN) algorithm, which provided a possibility for the practical application of multi-parameter evaluation in the field. On this basis, based on support vector machine (SVM), classification and regression tree (CART), KNN, random forest (RFC), optimized distributed gradient enhancement library (XGBoost), and the principle of minority obeying the majority, the problem of overfitting and distortion of a traditional single algorithm is avoided, and a fast, accurate and intelligent screening model of reservoir CO2 injection suitability is established. The results show that the model accuracy of the above five algorithms is 0.910, 0.854, 0.809, 0.865, and 0.921, respectively. The accuracy of the proposed mixed model is 0.933, confirming the accuracy of the CO2 injection suitability screening method established in this study. In addition, the main factors affecting the suitability of CO2 development are ranked as follows: crude oil viscosity, reservoir heterogeneity, reservoir permeability, reservoir pressure, original reservoir pressure, current oil saturation, reservoir depth, surface crude oil density, etc. The degree of miscibility of the CO2 crude oil system should not be the primary criterion for real-time CO2 flooding. The composite machine learning method proposed by this research institute is flexible and accurate, which can avoid misjudgment caused by fixed indicator ranges. It is of great significance to achieve rapid screening of CO2 development reservoir suitability under the dual carbon strategy goal.

As the global demand for energy escalates, the depletion of conventional oil and gas reserves has necessitated a shift towards unconventional reservoirs. These reservoirs, however, present significant challenges for oil recovery due to their complex rock properties, compositional heterogeneity, small pore throat size, low permeability, and low fluid mobility. Traditional methods, such as the injection of chemical agents to alter the oil-water interfacial properties, have proven less effective due to the intricacies of unconventional reservoirs. Moreover, while fracturing technologies can enhance permeability to some extent, they are yet to overcome issues of rapid production decline and final recovery rates below 10%. Nanomaterials, owing to their nanoscale dimensions and high surface-to-volume ratio, present a promising avenue for improving oil recovery. Their high surface energy enables easy adsorption onto solid surfaces or water/oil interfaces, suggesting potential for enhancing recovery in unconventional reservoirs. This comprehensive review focuses on the role and mechanisms of nanomaterials in improving oil recovery in unconventional reservoirs. It discusses a plethora of mechanisms including reduction of interfacial tension, alteration of wettability, stabilization of foam, emulsification, increase in solubility, improvement of oil flowability, and enhancement of spontaneous imbibition. Each mechanism is critically examined, considering the influence of various factors on their effectiveness. This analysis provides a theoretical foundation for the application of nanomaterials in diverse reservoir environments. By appreciating and fully understanding these mechanisms, we can optimize the performance advantages of nanomaterials, paving the way for more efficient and sustainable extraction techniques in unconventional reservoirs.

In the long-term development of heavy oil reservoirs with water flooding, the injected water usually flows through the high permeability layer, resulting in significant invalid circulation. Polymer flooding can increase swept volume and improve oil displacement efficiency. Reasonable technical criteria for injecting polymers into ordinary heavy oil reservoirs have been proposed by numerical simulation using a typical actual well pattern. The impacts of polymer injection volume, polymer solution concentration, injection rate, number of injection slugs, interval time between injection slugs, polymer solution concentration of subsequent slugs, and injection methods were evaluated. The results showed a large polymer injection volume, polymer solution of 2,000 mg/L, an injection rate of 0.056 PV/a, multiple slugs, small intervals, lower polymer concentration of subsequent slugs, and simultaneous injection of multiple wells would yield better oil production by polymer flooding. The proposed reasonable technical criteria of polymer flooding can improve the development effect and guide the field operation.

The Changqing gas field is a typical low-permeability tight lithological gas reservoir with strong heterogeneity and poor physical properties. With its development deepening, the gas well production rate gradually decreases, which gives birth to the rising number of low-yield and low-efficiency gas wells year by year. Due to the corrosion and scaling, sand production and deposition, water lock damage and other reasons, wellbore and reservoir blockage is formed in the production process. It will seriously affect the gas well productivity, even cause gas well effusion and water flooding, affect the development benefits of gas fields. In view of this problem, the study and analysis of blockage types are starting with the research on the mechanism of blockages, and the causes of gas well blockage are clarified from the two aspects of wellbore and reservoir. On this basis, the main technical countermeasures with wellbore coiled tubing sand flushing, reservoir hydrolysis lock of the near wells in the Upper Paleozoic gas reservoir, wellbore chemical descaling and reservoir depth unblocking of the near wells in the Lower Paleozoic gas reservoir were gradually established, which achieved differentiated de-blocking and recovery. Though the field scale application of the technology being carried out, more than 750 gas wells with an average daily gas increase of 9,000 m3 were revived. Until now, the total gas production has been obtained more than 1.5 billion m3, equivalent to 1.2 million tons of oil. The input-output ratio is as high as 1:9.0. The outstanding effect and economic benefits effectively solve the problem of low production or production stoppage caused by plugging. It can provide some technical support and guarantee for the improvement of de-plugging technology in Changqing gas field and other similar gas reservoirs.

The southeast of Sulige gas field is a typical tight gas field with low porosity and low permeability, tight reservoir, strong heterogeneity, difficult to use reserves, insufficient gas supply energy of gas Wells, generally low production or no natural productivity. Industrial oil flow cannot be formed after conventional well completion, and economic exploitation can only be realized by hydraulic fracturing. Although the staged fracturing of horizontal Wells has been applied on a large scale, the optimization system of pumping plug fracturing parameters has not yet been established. The optimization of fracture parameters provides an important basis for the optimization of fracturing construction design and the evaluation of fracturing effects. Therefore, based on the analysis of reservoir parameters and dynamic data in the southeast Sulige Gas Field, the effects of fracture orientation, fracture number, fracture spacing, fracture length, fracture conductivity and other parameters on fracture extension and post-compression productivity of horizontal Wells were simulated by using fracturing and numerical simulation software, and the optimal fracture parameters were optimized, which provided an important basis for the optimization of fracturing design and reconstruction mode of horizontal Wells in tight gas reservoirs.

With the continuing development of tight multilayer reservoirs, commingled production technology has been widely adopted for multilayer tight gas reservoirs and coalbed methane co-production. This paper assembles the cores with different physical properties in single-core, three-core, and four-core modes in tandem. Different core combinations are used to conduct experiments on single-layer production, direct co-production, and sequential and timing co-production to evaluate the behavior and characteristics during co-production. When the core is combined complexly, the recovery factor decreases significantly after half the pressure reduction. The gas production difference between high and low-permeability layers forms an interlayer interference and is superimposed on the effect of seepage resistance. As a result, the high-permeability layer recovery factor is greatly influenced. Furthermore, the core is combined complexly, and the high-permeability layer has a higher contribution ratio to the output gas. Additionally, it is easy to obtain the maximum gas production by selecting the combination timing of developed and undeveloped formations with the same pressure.

When the offshore high-porosity and high-permeability reservoir enters the high water-cut stage, it is complicated to determine the remaining oil distribution regulation and potential exploitation strategy under the factors of reservoir rhythm, plane heterogeneity, fault boundary, and longitudinal interlayer. Due to the influence of reservoir rhythm, sand distribution, well network and well interference. To enhance the oil recovery, the reservoirs in the sand was targeted for the study. Combining the production dynamics of the work area and the information from the numerical simulation, the remaining oil distribution were studied in depth. Corresponding adjustment for well tapping strategy was proposed. The layer remaining oil distribution is influenced by the rhyme and the perforated interval, which is mainly enriched in the upper sand body; The planar residual oil distribution is influenced by the sand distribution, well network, perforated interval, which distribution pattern is characterized as “relatively concentrated on the whole”. Well network adjustment can effectively utilize the remaining oil, including sidetracking old wells and infilling new wells. The infilled new wells can realize the effective development of the remaining oil-rich area and form a new injection and extraction correspondence with the surrounding injection wells, and the water content of the sand body rises slowly, which is 5.02% higher compared with the base plan.

Hydrogen is a clean energy and plays an increasingly important role in the energy field. Hydrogen production from natural gas is an important source of hydrogen, but it is also accompanied by carbon emissions. It is beneficial to move the natural gas hydrogen refining site to the underground oil and gas reservoirs that are difficult to develop. The complex reservoir structure of gas reservoir is a challenge to hydrogen production from underground natural gas. In this paper, CMG Stars software is used to simulate methane combustion and in situ hydrogen production reaction in multiple storage media, and explore the influence of geological parameters and injection parameters on hydrogen production efficiency of gas reservoirs. The simulation results show that, the fracture reconstruction area is the main place for hydrogen production reaction, the better hydrogen production efficiency can be obtained when the matrix permeability is less than 0.1 mD, and hydrogen production efficiency can also be improved with the increase of injected oxygen concentration and injection amount. The research results have clarified the reaction space of in-situ hydrogen production from natural gas and the factors affecting the efficiency of underground hydrogen production. It will provide a basic reference for the implementation of this technology..

Acidizing pre-treatment is a frequently employed technique to address technical challenges in reservoir fracturing and excessive pump pressure at the wellhead during hydraulic fracturing construction. The development of high-temperature-resistant solid acid products involves the synthesis of solid acid capsule core materials, selection of optimal capsule wall materials, and preparation process. The experimental evaluation encompassed various factors such as the solubility of solid acid at different temperatures, the acid production capacity during hydrolysis, the degradation capacity of guar fracturing fluid, and the effect of acid corrosion on fracture conductivity. The study found that the solid acid demonstrated excellent stability and temperature resistance at room temperature. Even at a high temperature of 150 ℃, the acid still showed slow dissolution. When used for hydrolysis acid production with a 30% addition, the highest equivalent hydrochloric acid concentration was above 15%. The use of solid acid can enhance the degradation of the guar fracturing fluid system, leading to a shorter degradation time and reduced residue content. Additionally, solid acid can react with the reservoir rock after hydrolysis acid production, resulting in an acid-etched fracture that improves the reservoir permeability. Field applications showed that using solid acid as a pretreatment acid for reservoirs effectively improved the stress field of the reservoir and reduced the fracture pressure by 10 MPa.

With the entry of oilfield into the middle and late stages of development, in order to maintain stable production and increase recoverable reserves, the technology of Secondary Development & Tertiary Recovery has come into being. However, its effect greatly affected by the conversion timing of drive medium. This paper analyzes the factors of the conversion time in Oilfield X of Dagang, carries out optimization study from the aspects of technology, economy and well pattern life cycle, constructing an optimization chart of multi-factor decision-making. Under different oil prices and viscosity ratio conditions, by comparing the economic benefits of different conversion timing, the research found that the earlier the conversion to tertiary recovery chemical drive, the greater the increase in recovery rate. Considering the well network lifecycle, it is best to complete the conversion and maintenance of the well network within 5 years to achieve a win-win situation in improving the recovery rate and economic benefits. This optimization method has been successfully applied to Oilfield X, and also provides reference for the research of similar problems in other mature oilfields.

As for steam channeling often occurred in the late stage of multiple rounds of the cyclic steam, it is necessary to investigate plugging agent with excellent performance. Aiming at the problems of poor stability (less than 30 days) of HPAM gel as a plugging agent at 150 ℃, a nano-SiO2 strengthened polymer phenolic gel with good thermal stability by using HPAM with a molecular weight of 1.8 × 107 was investigated. The ideal formulation of the gellant was selected from the mass amount of polymer, cross-linker, and the nano-SiO2 particles. The thermal stability and application performance were also be evaluated. The experimental results showed that when the gel was prepared with 0.3% HPAM, 1% water-soluble phenolic resin as a cross-linker, and 1% nano- SiO2 as a stabilizer, the dehydration rate was less than 5% after being aged for 150 days at 150 ℃. Dynamic light scattering experiments (DLS) results showed an increase in the hydrodynamic radius and stability at high temperatures of the polymer solution after the addition of nanoparticles The results of rheological experiments showed that the addition of nanoparticles significantly increased the viscosity retention of gellant, gel's yield stress and long-term thermal stability without affecting the viscosity of the gellant.

More than half of the remaining reserves in deep reservoirs with high water cut (buried depth of more than 4500 m) are still trapped underground and have not been effectively utilized. Gas injection has become the preferred method to enhance oil recovery (EOR) due to its technical advantages of injection capacity and reservoir damage. However, the microscopic mechanism of different gases and crude oil is complex, so it is necessary to deeply understand the oil-gas interaction and the microscopic displacement characteristics. Through high temperature and high pressure microscope displacement experiment and image processing technology, the occurrence state of micro-remaining oil after CO2, hydrocarbon gas and N2 injection into heterogeneous reservoir after water flooding is quantitatively characterized at 115 ℃ and 55 MPa, and the displacement mechanism of gas injection in EOR is elucidated. The results show that the microscopic mechanism mainly includes immiscible transport displacement, miscible extraction and miscible swelling. In the high permeability region, the miscible extraction mechanism is the main mechanism, and the gas preferentially flows along the water channeling with less resistance, which can directly contact a large number of micro-remaining oil, accounting for 85.06% of the total microscopic mechanism. In the middle and low permeability region, immiscible transport displacement is the main microscopic mechanism, accounting for 59.63% and 51.78% respectively. Among them, most of the gases in the low permeability region cannot directly contact with the micro-remaining oil, and the remaining oil can be effectively utilized by dissolving CO2 into the water phase to form carbonated water, and the miscible swelling mechanism accounts for 34.22%.

Nowadays, the steam conformance analysis and vapor-liquid interface (liquid pool level) of the typical horizontal well in SAGD operation is relatively mature. With the advancement of technology, some of multi-lateral horizontal wells engage in SAGD operation. However, steam conformance and liquid pool description, especially the lateral section is still one of the main difficulties. In this study, based on the modification of steam conformance formula, the judgment method of main horizontal and different types of multi-lateral wells is established. Meanwhile, the liquid pool of different types of multi-lateral wells is characterized by using the steam conformance. The research will provide technical support for the production improvement in multi-lateral horizontal wells in SAGD operation.

The three types of oil reservoirs in Xingbei Development Area belong to low permeability reservoirs, which are characterized by thin thickness, low permeability and poor connectivity. After a long period of water flooding development, the heterogeneity between layers and planes is more prominent, the remaining oil is scattered, and the water flooding development is difficult. Therefore, it is urgent to develop and implement a new technology of greatly enhanced oil recovery. According to the reservoir characteristics of interior in different oil displacement system optimization and evaluation of chemical agents for various performance parameters, study drug compatibility with reservoir, the performance is good, the cost is relatively low chemical flooding technology is applied to the scene. The results show that chemical flooding in low permeability reservoir can displace the remaining oil which is not produced during water flooding, and the effect of increasing oil production and dewatering is obvious, oil well center stage of chemical flooding to improve oil recovery by more than 12%, the cost per ton of oil is 29% lower than that of common polymer flooding. It has a good prospect of popularization and application. It provides a new way of enhancing oil recovery for three types of reservoir in low permeability.

Obtaining maximum economic benefits during the effective contract period is an important goal for overseas oilfield development. Enhanced liquid production is an effective means to increase oil production and recoverable reserves at a low cost during the middle-later development period. An overseas sandstone oilfield with low amplitude structure has good reservoir homogeneity and unstable internal interlayer. After over 40 years of development, it has entered the high or even ultra-high water cut stage, and the water cut of production wells increased rapidly. Based on the dynamic and static data such as the production, oil and water relative permeability, a study was conducted on the reasonable dimensionless liquid production index and liquid raising multiple at different water cut stages. The results show that when the water cut is lower than 80%, the dimensionless liquid production index increases slowly, and the growth rate rises with the increase of water cut. When the water cut rises to 80%, the theoretical liquid raising multiple reaches 4.2. When the water cut rises to 98%, the theoretical liquid raising multiple reaches 8. The liquid raising measures were applied to production wells with a water cut of reaching 97%. The application results show that the daily oil production increment of a single well was 42 bbl/d, and the water cut decreased by 0.4%, which has good effect. This study provides guidance for determining the reasonable liquid production of sandstone reservoirs at different water cut stages.

Both Well pattern and reservoir heterogeneity are important factors affecting the effectiveness of CO2 flooding development, and blind well placement in inhomogeneous reservoirs can seriously limit the efficient development of CO2 flooding. In this paper, the effects of square and triangular well pattern with different degrees of inhomogeneity on the flowline field and residual oil distribution field are investigated using numerical simulations, and their effects on the drive effectiveness are evaluated comprehensively by sweep efficiency, miscibility degree, production gas oil ratio and recovery degree. The results show that the heterogeneity of the reservoir changes the intensity of the streamline in the process of CO2 flooding, the presence of the main river channel causes the injected CO2 in the low-permeability zone to preferentially accumulate and break through to the high-permeability zone, and the oil displacement efficiency in the sweep region of the main river channel decreases compared to that of the homogeneous reservoir. The use of different well patterns for CO2 drive will result in different sweep characteristics and residual oil distribution. Compared with the diamond-shaped inverted nine-spot well pattern, the straight-line row well pattern is more likely to spread to the center of the area and the surrounding crude oil, and still maintains a high sweep efficiency in heterogeneous reservoirs. Compared with the homogeneous reservoir, the recovery rate of the high-grade poor reservoir increases by 3.1%, while the recovery rate of the diamond-shaped inverted nine-spot well pattern decreases by 11.95%. The recovery rate of the staggered well pattern in the high-grade poor reservoir is 31.58% lower than that of the homogeneous reservoir, and the sweep efficiency was reduced by 26.49% compared to homogeneous reservoirs when the CO2 injection reached 2.0 HCPV. The research results have certain guiding significance for the deployment of CO2 flooding well pattern in heterogeneous reservoirs.

The proven unused and controlled reserves of tight oil blocks are huge, however, under the elastic development of horizontal wells in tight oil reservoirs, there are many problems such as rapid production decline, low production, ineffective conventional water injection development, and large energy gaps in the formation. Effective technical means are urgently needed to supplement the energy of the formation. In order to explore new ways to effectively utilize tight oil blocks and improve the utilization of remaining oil in tight reservoirs, a carbon dioxide huff and puff pilot test was conducted in a horizontal well in A area in 2020. The daily oil production of a single well increased from 1.7t/d before huff and puff to 8.6t/d, and the test results were significant. The dynamic characteristics of carbon dioxide huff and puff applied to supplement energy in horizontal wells in tight reservoirs were determined, achieving a breakthrough in the production improvement effect of high viscosity crude oil and strong water sensitive tight reservoirs. Based on the results of this experiment, combined with on-site test data tracking and analysis, numerical simulation, fine modeling and other technologies were further utilized to optimize multiple injection and production technical parameters such as gas injection rate, injection rate, and soaking time. Carbon dioxide huff and puff was performed on selected horizontal wells in the A area in 2022. The daily oil production of a single well increased from 0.4t/d before huff and puff to 4.4t/d, and the water content decreased by 32.6 percentage points, the goal of effectively reducing water content while increasing production has been achieved, and the application effect of carbon dioxide huff and puff technology in the development of horizontal wells in tight oil reservoirs in peripheral oilfields has been improved. This provides ideas and technical support for the energy replenishment of horizontal wells in tight oil reservoirs in the future.

Currently, the method for confirming the phase inversion point of an emulsion only exists at a macro level, and it is almost impossible to determine the phase inversion point from a micro level. In order to further enrich the methods for determining the phase inversion point, this study attempts to investigate the phase inversion point from a microscopic perspective. Based on the actual water content method, the macroscopic volume of the emulsion was converted into the total number of emulsion droplets in a micrograph. Secondly, the viscosity method and the actual water cut method were used to determine the phase inversion point. Finally, a new method was used to determine the phase inversion point of the emulsion, and compared with the viscosity method and the actual water cut method. Results showed that first, after a series of simplifications, the RN value (the product of the average radius and number of droplets) was employed to represent the actual macroscopic water content, and the RN micro-scale method was formed to determine the phase inversion point of the emulsion. Second, the phase inversion point determined by the new method was consistent with the results calculated by the viscosity method and the actual water cut method, both of which were 60%. This confirms the validity of the new method. The establishment of the new method has enriched the diversity of methods for determining the phase inversion point and set a precedent for determining the phase inversion point from a microscopic perspective, which is of great significance to the development of phase inversion point research.

Due to factors such as high crude oil viscosity, large well spacing, and strong reservoir heterogeneity, the P612 thermal composite chemical steam flooding has problems such as serious steam channeling and low thermal efficiency. In this study, through two-dimensional visualization experiments, the development law of steam channeling channels is clarified, and the scale of steam channeling channels in P612 well group is calculated using the material conservation method. Based on this, the mechanism analysis of improving injection and production parameters, multiple rounds of combined plugging and adjustment, and other processes is carried out. The results can guide the implementation of steam drive efficiency improvement measures. The research shows that different levels of flow channels will inevitably be formed during steam flooding of ultra-heavy oil. The radius of the pseudo steam channeling channel between X121 and X122 is about 1.753 m, which is much smaller than the well spacing of 140 m. After the formation of main flow channels, the development of secondary flow channels is limited. Improving injection or production parameters and multiple rounds of combined plugging can effectively improve the steam absorption profile and increase the degree of utilization of secondary flow channels. However, for the plugging and adjustment of ultra-heavy oil reservoirs, the effective time has a lag, and the wellhead temperature shows a trend of falling and rising. Through the superposition of two efficiency improvement measures, the daily oil output of a single well in the well group of P612 steam flooding was increased from 1.4 t/d to 1.9 t/d. The results have deepened the understanding of steam flooding for ultra heavy oil, and can provide some reference and guidance for the development of steam flooding in other similar reservoirs.

As gas field is getting older, it is common that liquid accumulation at the bottom of gas wells causes the sharply drop of gas production or even shutdown. Foaming, as one way to drain water out of wells, has developed into two kinds. Conventional foaming agent works chemically and unfriendly to environment, and sometimes is little useful when agent disagree with underground water in high temperature, salinity and condensate oil. However, microbial foaming agent is of low toxicity, no pollution, and easy degradation. Gaoqiao, as one of development units of Jingbian gas field, is still plagued with serious water accumulation after years’ efforts of chemical foaming. Thus, it is worthy to carry out microbial drainage, a systematic work, including foaming drainage principle, microbial strains selection, field experiment and effect analysis. The microbial foaming drainage has a great success in three aspects. Firstly, the microbial foaming agent can drain water more effective than chemical foaming. Secondly, with the help of microbial foam, 18 wells have an average production increase of more than 5000 m3/d and that of more than 0.5 million m3/a. Finally, the degradation of microbial foam drainage is no pollutant to nature.

In order to solve the problem of rapid decrease in oil production rate in the late stage of depletion development of tight reservoirs in the Mahu area, as well as issues such as shortage of CO2 gas source, high cost, and corrosiveness, a method of natural gas displacement is proposed to develop tight reservoirs. The mechanism, development characteristics, and influencing factors of natural gas displacement to improve tight oil recovery are discussed from the aspects of micro development mechanism and macro development effect through the experimental study of feldspar core displacement. The important operating parameters such as gas injection speed and gas injection timing are optimized. The experimental results show that the gas injection rate has a great influence on the recovery factor, and there is a gas injection rate (0.10 cm3/min). That is optimized for development efficiency. The determination of the minimum miscibility pressure of crude oil and natural gas of 44.61 MPa provides a theoretical basis for the development of a tight oil reservoir by natural gas injection. Through displacement experiments conducted under current formation pressures of 37 MPa, depleted to 31 MPa, and depleted 25 MPa, it was found that the best time for natural gas injection is under the current reservoir pressure. The results optimize the key injection parameters that can guide the field application and confirm the feasibility and potential of natural gas to enhance tight oil recovery. To provide a strong basis for field development.

High pouching oil is characterized by high freezing point, high wax content and high wax extraction temperature. During the development process, the oil reservoir is prone to wax precipitation, forming cold damage, resulting in low water drive recovery. Using microbial high-throughput sequencing analysis, chemical flooding experimental evaluation methods, core physical simulation and CT scanning, the technology of microbial+chemical composite flooding combination to improve oil recovery of high pour point oil is proposed, and the microbial chemical composite flooding formula is developed, This system has the dual advantages of chemical flooding, which can greatly improve the oil displacement efficiency and reduce the wax component of crude oil by microorganisms. Finally, the slug combination of microbial and chemical flooding formula is optimized through physical model experiment. The experimental results show that the oil displacement efficiency of microbial+chemical composite flooding is 35.19% higher than that of water flooding, 7.27% higher than that of single chemical composite flooding, and 1.16 t/t higher than that of polymer flooding. This study provides an effective replacement technology for mode conversion and enhanced oil recovery in the later stage of development of high pour point oil reservoirs.

Carbon dioxide huff and puff technology is widely used in X oilfield. At present, there are many kinds of huff and puff technologies in the field, but the oil increasing mechanism of different huff and puff technologies is not clear. The scope of application and the timing of replacement need to be further studied. Based on the classification and evaluation of natural water drive reservoir in X oilfield, this paper establishes an abstract geological model, uses laboratory experiments and numerical simulation methods to carry out research on the oil-increasing mechanism and technical limits of different huff and puff technologies. Combined with reservoir engineering theory, the index of movable oil recovery degree is proposed to clarify the dimensionless limits of different huff and puff technologies. The results show that the three huff and puff methods of carbon dioxide huff and puff, composite huff and puff and deep huff and puff have obvious effect of water control and oil increase. When the movable oil recovery degree is between 26% and 45%, the carbon dioxide huff and puff is the best. When the movable oil recovery degree is between 45% and 58%, the composite huff and puff is the best. When the movable oil recovery degree is between 58% and 77%, the deep huff and puff is the best. The research results can effectively guide the differential design of precise huff and puff in natural water drive reservoir, and have a good prospect of popularization and application.

Gasikule oilfield is one of the main oil fields in Qinghai oilfield with a long period of waterflood development. In the process of development, the scaling problem of well shaft, ground system and waterflood formation is serious, which brings great challenges to production. Therefore, it is of great significance to explore the compatibility of formation water and injected water and the characteristics of formation scaling in the process of waterflood development. In this study, the compatibility experiment of injected water and formation water was carried out by simulating the formation environment, and the long sand-filling model was developed according to the physical parameters of the target reservoir. The pressure changes at different positions of the core during the water injection process were studied experimentally, so as to investigate the scaling position of the core and its influence on the injected water pressure. Moreover, the mineral composition at the pressure changes were analyzed by X-ray diffraction. The results show that calcium carbonate is the main component of scaling sample at different layers, and scaling mainly occurs at the inlet end of core (near well zone). With the increase of injection amount and waterflooding time, more scale is generated, and blockage is formed at the inlet of core, resulting in increased water injection pressure and water injection difficulty. By comparing the inlet pressure values of deep and shallow layers, it can be found that scale is formed in the core of deep layer at the early stage of water injection, and water injection pressure rises slowly. After 80 h, since the scaling generated, the water injection pressure increased by nearly 50% to 24 MPa. At the initial stage of water injection in core of shallow layer, there was rarely scale formation, until 180 h later, the pressure began to rise gradually. In addition, under the same injection rate, temperature has a great influence on the scale generation. It is easier to generate scale with higher temperature. This study can provide theoretical guidance for the optimization of injection water quality and the prevention of scale formation in the process of waterflooding development.

With the development of non-thermal technology for high salt heavy oil reservoirs, amphiphilic polymer has become a good chemical agent due to its emulsification of heavy oil and flow control characteristics. In order to adapt to the harsh conditions of high salinity and improve the emulsification ability of polymer, this paper independently synthesized a salt thickening amphiphilic polymer named PADtC and characterized its structure through 1H NMR. Rheometer and blender stirring were used to systematically study the properties of rheological and heavy oil emulsification viscosity reduction. The results indicated that PADtC had excellent high salt resistance performance. PADtC exhibited special salt thickening characteristics. It has excellent emulsification viscosity reduction ability for heavy oil at a concentration of 1500 mg·L−1, with a viscosity reduction rate of up to 98%. The prepared heavy oil emulsion had a particle size of 22 μm and concentrated in distribution. The research results can provide new products for the non-thermal technology of high salt heavy oil reservoirs.

Shale reservoirs are characterized by high heterogeneity and ultra-low permeability. For most shale reservoirs with insufficient formation energy, CO2 injection is one of the most economical and effective extraction technologies to improve the shale oil recovery factor. At the same time, fractures also have a significant impact on the oil recovery factor of shale reservoirs. This work uses a high-temperature and high-pressure three-dimensional physical simulation experimental device to restore the realistic conditions of shale reservoir reservoirs during the huff-n-puff process. The results show that the CO2 huff-n-puff and puff recovery factor of shale oil reservoirs are mainly concentrated in the first four rounds, and the effect of improving the oil recovery factor decreases with the increase of production rounds. Compared to non-fracture CO2 huff-n-puff, the presence of fractures significantly affects CO2 huff-n-puff in shale reservoirs, with an 8.95% increase in the oil recovery factor after fracture creation. Fractures can expand the coverage area of CO2 and effectively increase the range of CO2 production. This study reveals the pressure field variation pattern during CO2 huff-n-puff and puff in shale oil reservoirs under different matrix-fracture patterns, providing theoretical guidance for large-scale field application of CO2 huff-n-puff injection and extraction optimization.

At present, the unconsolidated sandstone reservoirs with medium and high permeability have the problem that the longer the development cycle, the more serious the blockage, resulting in the reduction or shutdown of the well, and the conventional fracturing design cannot meet the needs of unconsolidated sandstone unplugging and increasing production to form “short and wide” fractures with high diversion capacity. This paper proposes using Tip Screen-out fracturing, and considering formation pollution and proppant compaction, to design a reasonable conduction capacity. The step of fitting the volume ratio of the pre-liquid to correct the half-length of the crack is added, and the accurate crack size is further calculated, and the key parameters such as the half-length of the crack and the crack conductivity can be calculated according to different fracturing processes, such as displacement, pre-liquid volume, sand volume, etc. The results show that the tip screen-out fracturing of unconsolidated sandstone will produce a “short and wide” fracture with high conductivity. The correction coefficient of proppant sand concentration was negatively correlated with the closing pressure, which influenced fracture conductivity. This study forms a complete set of calculation methods for tip screen-out fracturing of unconsolidated sandstone, which has guiding significance for the fracturing design of medium and high permeability unconsolidated sandstone oil and gas reservoirs.

In order to study the displacement mechanism between horizontal well fractures, seepage law, and the impact of horizontal well renovation parameters on development effectiveness, a large-scale outcrop rock sample physical simulation test was established. Based on the actual conditions of the oil reservoir, model parameters were designed to study the percolation mechanism of inter fracture displacement, the influence of fracture parameters and injection parameters on development effectiveness, and the influence of three displacement media tests: inter fracture water drive, natural gas drive, and surfactant drive on development effectiveness. This experiment revealed the displacement mechanism, seepage law, pressure change process, and production performance characteristics between horizontal wells in ultra-low permeability reservoirs. The experimental results indicate that: ① Physical model tests can effectively simulate the seepage law during the injection and production process of horizontal wells in ultra-low permeability reservoirs. ② Horizontal well fracture displacement is more likely to form linear displacement and improve oil recovery efficiency of the reservoir The horizontal well injection line has a well spacing of 200 m, a crack spacing of 156 m, and a half crack length of 178 m, resulting in the highest recovery rate. ④ The injection pressure is limited to the rupture pressure, and the higher the displacement pressure, the higher the recovery degree. ⑤ The final recovery rate of water flooding between fractures is the highest, and the recovery rate of natural gas and surfactant flooding between fractures is lower than that of water flooding between fractures.

The lifting process design of CO2 flooding test area in Y oilfield was lifted by conventional rod pump. After gas was detected in the oil well, the pump efficiency of conventional pump decreased significantly and the production was greatly affected. Therefore, different anti-gas lifting technologies were studied and field tests were carried out. Through laboratory tests and numerical simulation, the flow state of CO2 flooding oil Wells was systematically analyzed, and the gas separation efficiency experiments of multistage gravity separation gas anchor, multifunctional integrated gas anchor and gas-liquid separation anti-air pump were carried out under different gas-liquid ratios, and compared with the field application situation. The results show that the existing anti-gas lifting technology can satisfy the normal production of Wells with gas-liquid ratio below 250 m3/m3. The multistage gravity separation gas anchor is not as effective as the multifunctional integrated gas anchor. Different structures of multifunctional integral gas anchor have obvious differences in gas prevention effect. Gas-liquid separation anti-air pump can prevent the occurrence of gas lock, but use alone can not play a role in improving pump efficiency. For fractured gas detection wells, the ratio of gas to liquid rises faster after gas detection wells, and the basic liquid after gas channeling, all the anti-gas lifting technology applied at present can not play a role. The research results can be used for reference in the selection of lifting technology in similar situations.

In Since the CO2 test in X field, 28 Wells have been found with casing damage, more than 93% of them are gas injection wells. Gas injection well with casing damage, easy to cause oil and gas up to the surface. There are safety and environmental protection risks, and it also affects the integrity of well pattern and development effect. Gas injection well overhaul construction cost is high, a single well up to 2 million yuan. Therefore, the causes of casing damage and prevention measures are studied. By means of nondestructive testing, SEM + EDS and XRD analysis of corrosion products, the main cause of casing damage was determined by H2S corrosion. The basic conditions of H2S corrosion are determined by establishing the distribution model of pressure and temperature in gas injection wells. According to the results of the study on the causes and rules of casing damage, the template of casing damage risk assessment was formed, and the prevention measures of casing damage were formulated. From the field application effect, the proportion of casing damage was reduced from the initial 53.6% to 4.5%, greatly prolonging the service life of gas injection wells, and providing an important technical guarantee for the smooth development of the subsequent CO2 test in X oilfield.

The construction parameters of hydraulic fracturing have a direct impact on the propagation morphology of fractures and the post-fracturing productivity of single well. Optimizing the construction parameters can effectively improve reservoir stimulation effect and increase the recovery rate of single well. The W Block of Xinjiang Oilfield, characterized by medium porosity and low permeability mudstone sandstone, must rely on hydraulic fracturing technology to achieve economic development. Using Petrel-Kinetix fracturing numerical simulation software, a numerical simulation model of vertical well fracturing considering fluid-solid coupling was established, with J10 well in this block as the research object. The influence mechanism of the pad fluid ratio, fluid displacement, and sand ratio on the propagation morphology of fractures and reservoir stimulation volume was studied using this model. The optimization design of hydraulic fracturing schemes was carried out by evaluating the single well productivity under different hydraulic fracturing construction parameters. The research results indicate that the pad fluid ratio and fluid displacement have a significant impact on the length of hydraulic fractures in this block, while fracture width is mainly controlled by sand ratio. The shorter the fracture length required to achieve the same oil production, the higher the permeability and the thinner the reservoir thickness. As the pad fluid ratio, fluid displacement, and sand ratio increase, the reservoir stimulation volume and the cumulative oil production of single well will increase, but the growth rate will gradually slow down.

In fractured low-permeability oil fields, after water injection, the injected water is prone to protrude along the fractures or high permeability layers, forming a water drive dominant seepage channel. The ineffective circulation is severe, affecting the volume of water drive and reducing development effectiveness and benefits. Therefore, this paper focuses on the analysis of the deep profile control and flooding enhanced oil recovery technology of Cr ion gel diluted injection with sewage distribution in the fractured low permeability reservoir of C Oilfield. Firstly, the mechanism of deep profile control and flooding was analyzed, and the adaptability of this crude oil extraction method was evaluated through indoor core experiments. Secondly, the principle of well selection and layer selection for chromium ion gel flooding is determined. Thirdly, the field effect of this method for oil displacement is introduced, which is intended to clarify the practical value of this method and promote the gradual innovation of chemical flooding enhanced oil recovery technology for fractured low-permeability reservoirs in China.

There are thick massive carbonate reservoirs in the Middle East region with large reserves and high production, characterized by non-significant layering characteristics and large single-layer thickness. If vertical wells are used for commingled water injection development, the stability of the water flood front is significantly affected by gravity, which in turn affects the water flooding volumetric sweep efficiency. In order to clarify the influence law of gravity on this type of reservoir and improve the water flooding sweep efficiency, the mathematical analysis method was used to analyze the judgment of water flood front stability under gravity and the influence of reservoir thickness on water flood front stability. On this basis, the numerical simulation method was utilized to study the relationship between the water breakthrough time, the volumetric sweep efficiency at water breakthrough, the water recovery rate at water breakthrough and the perforation thickness under seven different conditions of gravity differentiation. The results show that under the influence of gravity, it is difficult to maintain stability in the water flood front of massive reservoirs with commingled water injection. The perforation thickness could be optimized in order to improve the volumetric sweep efficiency of water flooding. In homogeneous massive reservoirs, there is a negative correlation between the water breakthrough time and the perforation thickness. However, the relationship curve between volumetric sweep efficiency at water breakthrough, anhydrous recovery rate, and perforation thickness is related to the degree of gravity differentiation. When the degree of gravity differentiation is not significant, the relationship curve will show a change of first positive correlation and then negative correlation. When the degree of gravity differentiation is significant, there is a negative correlation between them. Therefore, there is an optimal perforation thickness affected by the degree of gravity differentiation. Based on the comparative analysis of volumetric sweep efficiency at water breakthrough under different gravity differentiation conditions, a graph was created to illustrate the relationship between the optimal perforation thickness and gravity differentiation. The research results can help increase the volumetric sweep efficiency and make the development design of massive carbonate reservoirs in the Middle East region more reasonable.

Hydraulic fracturing is an effective method for the development of tight shale oil reservoirs, which can improve the production and recovery efficiency of shale oil wells. The backflow of proppant after fracturing seriously affects the efficiency of fracturing construction and oil well production capacity, and sand flushing after fracturing also increases construction costs. Controlling blowout is the main way to prevent proppant backflow in shale oil horizontal wells, but many wells still have a large amount of proppant backflow into the wellbore during the initial stage of blowout. By establishing a visualization experimental evaluation method for proppant backflow, the critical velocity of proppant backflow and the influence of different confining pressure conditions on the critical velocity were obtained under conditions such as no proppant backflow and fiber anti proppant backflow. The backflow law of proppant at different stages was analyzed. The visualization experiment directly observed that the main sand produced in the early stage of proppant was collapsed sand, and even at very low flow rates, proppant still flowed back into the wellbore, The fiber anti proppant backflow technology can effectively improve the critical speed of proppant backflow and reduce the degree of sand production in the early stage. And one well test was conducted on Longdong shale oil field, and the effect of preventing proppant backflow was significant. This provides new ideas and theoretical basis for the evaluation and research of proppant reflux.

A series of calculations using the basic formulas can clarify the development potential of tight reservoirs, which is a meaningful study. Water-flooding is a widely used method for developing tight reservoirs, and as such, analyzing the potential for water-flooding and selecting an optimal development method are crucial for successful reservoir development. Based on the varying fluid flow states during the development of tight reservoirs, the ultimate permeability can be categorized into three types: ultimate imbibition permeability (Ki), ultimate displacement permeability (Kd), and ultimate displacement development permeability (Ku). The ultimate permeability of the tight reservoir in the Ordos Basin was calculated through the ultimate permeability calculation method and the basic parameters of the tight reservoir. According to the results of the ultimate permeability calculations for different tight reservoirs in the Ordos Basin, it was found that the permeability of the reservoirs (0.1 mD–1 mD) was higher than Ki (0.0034 mD–0.084 mD), but between Kd (0.236 mD–0.526 mD) and Ku (0.4691 mD–1.167 mD). Therefore, the potential for developing the tight reservoir in the Ordos Basin by the imbibition-displacement method during water-flooding was significant. Among all the tight reservoirs analyzed, Chang-6 has a greater potential for displacement development, whereas Chang-4 + 5 has a lower potential for imbibition development. However, its potential for imbibition-displacement development is higher. By analyzing the water-flooding development potential of tight reservoirs in the Ordos Basin from the perspective of ultimate permeability, this study can serve as a reference for selecting optimal development methods and identifying the difficulty levels associated with tight reservoir development.

In the late stage of waterflooding development, identifying the causes of oil well inefficiency is an important means to improve oilfield development effect. In view of the problem that the solution result of the capacitance-resistance model is only the contribution rate of water injection, the capacitance-resistance model is improved, and the calculation formula of the interwell connectivity is derived. According to the formula, the proportion of external energy supply is calculated to determine whether there is sufficient energy supply around the oil well. Then the dimensionless interwell connectivity is introduced to realize the quantitative characterization of interwell connectivity change between wells. It can further identify whether the cause of oil well inefficiency is reservoir blockage, preferential flow path, or just pump efficiency problems. Finally, according to the reasons of low efficiency, the corresponding governance strategies are made. The research has been applied in the southern Bohai Sea oilfield, 13 wells were effectively guided to implement corresponding measures, including plug removal, profile control, pump inspection, etc. After the adjustment, the total daily oil production has increased by 508 cubic meters per day.

Tight sandstone gas reservoirs are important strategic replacement resources in China and are the main type of unconventional natural gas reservoirs. Horizontal well multi-stage fracturing technology is an effective technical means for unconventional tight gas reservoirs to achieve industrial development value. For fractured horizontal wells, the production capacity factors mainly include geological and engineering factors. The effective thickness of gas layers, permeability, water saturation, permeability, and formation pressure are the basic factors that affect the gas well. The length of horizontal sections, the number of fractured sections, and the half length of fractures are controllable factors that affect the production capacity of horizontal wells. SDN Block of Sulige Gas Field is the largest demonstration area of horizontal wells in tight sandstone gas reservoirs in China. The number of wells put into production of horizontal wells accounts for about 40% of the total number of wells put into production in the block, and the annual output of horizontal wells accounts for more than 75% of the total annual output of the block. The development of horizontal wells is particularly critical to the long-term stable production of SDN Block. This paper combines block geological research, engineering parameters and means of production of gas wells, and uses numerical simulation technology, Quantitative analysis of the sensitivity of various influencing factors on the production capacity of horizontal wells, proposing the main controllable factors that affect the production capacity of horizontal wells, and combining economic evaluation, optimizing the engineering parameters of horizontal wells in this block to improve the overall development effect of tight gas reservoirs in the block.

After fracturing, too fast discharge speed of oil and gas well “sand production” will lead to the deterioration of artificial fracture support condition and the decrease of conductivity, which will affect the production of oil and gas, or lead to the accumulation of sand at the bottom of the well and the burial of oil and gas layer or the erosion of sand production to puncture the surface test pipeline, which will affect the smooth progress of testing and oil and gas exploitation. In domestic oil fields such as Daqing, Shengli, Jilin, Dagang, Sichuan and so on, sand buried reservoir caused by proppant reflux has also occurred, resulting in reduced oil production or no oil production. At present, the solutions to the problem of “sand production” at home and abroad are self-consolidation proppant reflux technology, fiber backflow prevention technology, thermoplastic film backflow prevention technology and deformable proppant backflow prevention technology, etc. The field test effect still has technical shortcomings. In this study, the epoxy resin emulsion anti-reflux additive is combined with degradable fiber to form a composite chemical anti-reflux material, and the optimal ratio of composite chemical anti-reflux material is optimized. The synergistic effect of chemical cementation and physical entanglements is played to improve the compressive strength of consolidated sand column, which is conducive to reducing the proppant backflow. A high efficiency epoxy emulsion - degradable fiber compound anti-reflux additive was prepared. In addition, the material preparation process does not require a large amount of organic solvents, in line with the concept of environmental protection, to improve the current technical level and production capacity of the field has a significant contribution to reduce the damage to the formation.

CO2 miscible flooding can not only improve reservoir recovery, but also achieve carbon sequestration and alleviate the greenhouse effect. However, there are few studies on the development of CO2 flooding after water flooding in low permeability glutenite reservoirs, and the development mode and effect are not clear. This paper takes an oilfield as an example. Firstly, the main mechanism of CO2 flooding was clarified. Then, the minimum miscible pressure and oil displacement efficiency under immiscible, near miscible and miscible conditions were determined by laboratory experiments. Finally, the development method of CO2 miscible flooding in this area was optimized by numerical simulation and the recovery was predicted. The results show that CO2 miscible flooding can significantly expand the swept volume while improving the oil displacement efficiency. The oil displacement efficiency of miscible flooding is higher than that of near miscible and immiscible flooding, and CO2 miscible flooding can be realized under reservoir conditions in this area. The inverted nine-point well pattern with 350 m well spacing is suitable. It is recommended to use a gentle step gas injection method. The daily gas injection volume is 20 t/d in the formation energy supplement stage, 40–50 t/d in the miscible phase, and 60–70 t/d in the liquid extraction stage. It is expected that the recovery can reach 41.5% after 15 years, which is 22.3% higher than that of water flooding. This conclusion has guiding significance for the similar reservoirs.

Tight reservoir in Daqing periphery oilfield is abundant. However, due to low-permeability, poor physical properties, and insufficient formation energy, water injection is not effective, development effect is not ideal, and producing degree is low. Therefore, it is proposed to implement energy replenishment before fracturing, integral fracturing, and energy storage after fracturing. In the energy replenishment stage, surfactants are selected as injection medium to replenish energy and improve displacement efficiency. Surfactants are evaluated by established method; LH anionic surfactant and KR anionic non-ionic surfactant are preferred. Under alkali free condition, interfacial tension of two surfactants maintain at order of 10–3. Recovery degree in natural cores is more than 15%. Field application conducted in 30 wells in Block P, including 27 vertical wells and 3 horizontal wells. Oil is seen in vertical wells at 7.8% flow back rate. The average daily liquid production of 20 wells that have been pumped is 7.5 t per day, with a daily oil production of 1.3 t, and a cumulative oil increase of 223.8 t per well. The average daily oil increase of a single well in three months after fracturing is 5.2 t, 1.6 times and 2.2 times that of dessert fracturing and overall fracturing in same period. The average daily liquid production of 3 horizontal wells is 24.2 t, and the daily oil production is 9.6 t. The results show that overall design of the fracturing energy supplement scheme is reasonable, and the selected surfactant can supplement formation energy while improving displacement efficiency. This will provide technical support for developing tight reservoirs.

Being the earliest extra-low permeability 100 million ton integrated oilfield developed onshore in China, the uneven contradiction of reservoir water flooding becomes prominent. The development effect worsens in the Ansai oilfield with the development time extension. To explore the technical direction of enhancing oil recovery in the encrypting area of the extra-low permeability reservoir, the research and the test of multistage composite deep flooding technology were carried out in the Wangyao encrypting area of a typical block of the Ansai oilfield. A plugging agent with high strength and flexibility was used to seal cracks and large-scale dominant channels. Micro-nano polymer particles were designed to drive oil in the water-porosity area. The multistage compound deep profile control and flooding technology of “the combination of high strength flexible and elastic plugging agent plugging fractures and micro-nano polymer particles to drive oil” have been formed generally. The technique has been applied in 23 well groups in Wangyao well pattern-filling area. The average injection pressure of a single well is 0.17 MPa/1000 m3, far lower than the level of 1.1 MPa/1000 m3 in conventional profile control, which provided favorable conditions for deep migration of flood control agent and deep production of the reservoir. After deep profile control and flooding, the water cut rise rate in the test area was obviously controlled, the natural decline rate decreased from 11.7% to 5.9%, and the water cut rise rate decreased from 2.9 to 1.8. The reservoir plane water drive was improved, the profile produced degree was increased, and the development situation improved, which indicates that multistage compound deep profile control and flooding technology shows good technical adaptability in Ansai extra-low permeability reservoir.

With the increasing scale of polymer flooding in Daqing Oilfield and the gradual deterioration of reservoir properties, a large number of fracturing measures are required to maintain the normal injection and production of the block in the process of polymer flooding to ensure the oil displacement effect. Due to the strong phasing and rapid change of water cut and oil recovery in polymer flooding, the research on the influencing factors of polymer flooding fracturing has not reached the quantitative stage. Through big data analysis, numerical simulation and other methods, this paper clarifies the factors affecting the fracturing effect of polymer flooding, and realizes the quantification of the impact factors. It is the first time to realize the quantification of the timing of the measures. The instantaneous reservoir state is used to characterize the timing. In the analysis of polymer flooding reservoir, the reservoir state implementation. It has strong applicability and broad promotion prospects can be the oil-water distribution state, the accumulation state of the underground oil displacement system, etc. Quantification is conducive to accurately grasp the timing of the measures, and is of great significance. A formulaic optimization and quantification method has been formed by comprehensively considering the effect impact factors and fracturing opportunity quantification. The method has a large expansion space for further transformation, which improves the optimization efficiency and measure effect, and is convenient for later software algorithm.

X oilfield is an offshore fluvial facies heavy oil field. Due to the small platform space, it is different from the development and production methods of onshore oilfield, and it has long-term high intensity injection-production development. However, due to the strong heterogeneity of the reservoir and the large ratio of water to oil mobility, the water channeling of injected water is serious, and the water drive effect is gradually getting worse, so it is urgent to carry out the research of water injection well profile control and drive technology. For X oilfield, oil displacement effect analysis of weak gel and nano microsphere was carried out. Polymer microsphere mainly improves oil recovery through profile control and has good effect. The double pipe parallel displacement experiment shows that the weak gel can improve oil recovery and profile. The 2D plane model displacement experiment proves that the weak gel and polymer microsphere can improve the heterogeneous reservoir and enhance the oil recovery. This physical experiment provides guidance for polymer flooding in offshore fluvial heavy oil fields.

Hydraulic fracturing has become a key technology for developing unconventional coalbed methane reservoirs. Fracture parameters directly affect the fracture propagation patterns and the effect of hydraulic fracturing. However, how to optimize fracture parameters to improve coalbed methane recovery after fracturing is still unclear. In this study, combined with Petrel and WellWhiz3.3 numerical simulation software, a fracture propagation model of multi-stage fracturing in the horizontal well and a postfracturing production simulation model were established based on the basic characteristics of the coalbed methane reservoir in the Daning-Jixian block. The model was used to investigate the mechanism of the influence of cluster number and cluster spacing on the fracture propagation pattern of multi-stage hydraulic fracturing in horizontal wells, and revealed the impact of stage cluster ratio, fracturing stages number, cluster spacing and fracture half-length on the productivity of horizontal well after fracturing. Numerical simulation results show that: competitive propagation behavior exists among fractures when multiple clusters of fractures initiate and propagate simultaneously. The exterior fractures will suppress the extension of inner fractures and the complexity of fracture competitive propagation behavior increased with the number of clusters and the reduction of cluster spacing. Moreover, the cumulative gas production of the gas wells increases with the increase of stage cluster ratio, number of fracturing stages and half-length of fractures, and initially increased and then decreased with the increase of cluster spacing. Overall, this study can aid in improving the productivity of horizontal wells in coalbed methane reservoirs, thereby enhancing the economic feasibility of coalbed methane development.

K Oilfield is a shallow, unconsolidated sandstone conventional heavy oil reservoir. It has been developed using a patterned well network and two fire flooding methods, namely wet and dry, for nearly 15 years in the mining area. In order to summarize the characteristics of fire flooding development in K Oilfield, establish screening criteria suitable for fire flooding in K Oilfield, and evaluate the development effectiveness, this article conducts a fire flooding analysis based on production dynamic data and test materials, combined with a numerical simulation of the fire flooding mechanism model. The following understanding has been obtained: Fire flooding production wells in K Oilfield exhibit obvious effectiveness characteristics, and discerning criteria for the effectiveness of fire flooding have been established. Water production in dry fire flooding mainly comes from formation connate water. The water-free production period is long, and the water cut gradually increases after breakthrough.Water production in wet fire flooding comes from formation connate water and injected water. The water-free production period is short, and the water cut increases rapidly after breakthrough. Fire flooding is suitable for areas with oil formation thickness above 4m in K Oilfield, and a small well spacing of 100m is recommended for development. There are differences in the effectiveness between dry and wet fire flooding in K Oilfield. Dry fire flooding is affected by air override, resulting in poor mobilization in the lower part of the reservoir. Wet fire flooding, under the combined action of air override and water drive, has a greater vertical coverage compared to dry fire flooding and achieves better production results. The successful application of fire flooding in K Oilfield provides guidance for the development of fire flooding in shallow, conventional heavy oil reservoirs. Overall, the findings from the practice and understanding of fire flooding in K Oilfield contribute to the advancement of fire flooding techniques in shallow, conventional heavy oil reservoirs.

The primary recovery factor of extra-heavy oils with foamy oil flow characteristic is only 8–12%. In previous studies, an approach of chemical-assisted methane flooding to enhance recovery in foamy oil reservoirs after primary depletion was proposed. The approach includes injecting viscosity reducer naphtha, methane and surfactant solution slugs sequentially to recreate foamy oil flow in situ. This study further investigated the effect of the surfactant concentration on the process through indoor experiments. Extra-heavy crude oil sample with typical foamy oil features, taken from Venezuela Heavy-Oil-Belt, was adopted during the experiments. To begin with, 16 groups of interfacial tension test between oil added with surfactant solution of different concentration and methane were conducted. Afterwards, 6 groups of foam stabilization test were conducted to record the foam volume and the half-life period under different surfactant concentrations. Finally, 3 groups of 2D visualized micro-flow experiments were conducted to investigate the surfactant concentration effect on the generation of dispersed gas bubbles. The interfacial tension tests showed that the oil-gas interfacial tension decreased with increase in the surfactant concentration when the concentration was below its critical micelle concentration value. The test on foam stabilization showed that an increase in surfactant concentration improves the stability of foam liquid film, delays foam drainage, and prolongs foam life. The 2D visualized micro-flow experiment results illustrated that it presents a distinct foamy oil phenomenon, at a concentration of 2wt% and above. Above understandings provide guidance for on-site implementation.

The C15 block in Huabei Oilfield is characterized by complex structure and multiple oil-bearing intervals. After more than 40 years of development and adjustment, it has entered the period of high water content and high dispersion with low speed and low efficiency. In order to further increase oil recovery and improve development results, the second & tertiary combined chemical flooding technology is initiated for the C15–141 well area of C15 block. In the transition from water flooding to chemical flooding in the “second & tertiary combination” exploration stage, remaining oil description technology, well location optimization deployment technology and water flooding front regulation technology are improved according to the reservoir characteristics. The formulation of heterogeneous compound oil flooding system in high temperature reservoir was innovatively developed. The EOR project is applied, as the first candidate, in January 2022, on the C15 block and achieved great success. The injecting pressure rose 5 MPa. The injection profile and production profile were modulated, and the water driving degree was increased by 3.4%.The oil rate of field pilot rose to 57.1 t/d from 26.5t/d, and The water cut decreased by 10.5%. By March 2023, 7.77% of the project design injection volume has been completed and the project has increased oil output by 11.6 thousand tons. The preliminary good effect of the Second & Tertiary Recovery Combination Reservoirs under Chemical Flooding technology in C15 block will play a good supporting role in the application of the reservoir with high water cut and high dispersion of Huabei oilfield.

Low-permeability tight reservoirs are difficult to develop effectively. Conventional surfactants have high adsorption losses and poor matching with the tight reservoir pore roar radius. To further improve crude oil recovery, Microemulsion named ME-1 was developed with methyl T9 decanoate MS-9 as the oil phase, and the phase behavior was studied by quasi-ternary phase diagram to screen the main surfactant, co-surfactant, and salinity, with the composition of 20% AEO-9 + 13.3% propylene glycol methyl ether + 25% MS-9 + 41.7% distilled water + 1% KCl. The performance evaluation results showed that: The particle size of ME-1 system was 86.1 nm, and the oil-water interfacial tension was 0.08–0.13 mN/m, which could reverse the surface wettability of oil-wet mica flakes (116.38°) to water-wet (53.06°). NMR characterized its static and dynamic percolation recovery as 32.56% and 41.17%, respectively, and the 2.5-dimensional microscopic model showed that ME-1 could effectively increase the swept volume and oil washing efficiency. The experimental results show that the microemulsion can rely on the small size feature to effectively enter into the micro and nanopore pore throat, trigger the wetting inversion, promote the oil phase flow, and break up the crude oil into the small-scale state for recovery. In summary, this system can be used in tight reservoirs to enhance recovery, providing key technical support and theoretical support for effective mobilization and efficient development of low permeability tight fractured oil.

In view of the complex water flooding law, serious interlayer interference and prominent non-Newtonian fluid characteristics of heavy oil faced by offshore delta S Oilfield in Bohai Sea at the "Double High" stage of high water cut and high recovery degree, how to lock the remaining oil enrichment area and realize the efficient production of heavy oil in this area is the key to the potential tapping and adjustment of the oilfield. In this paper, firstly, a large number of core sampling, seismic, logging and other data are used, combined with the type of lateral contact of single sand body, to quantitatively describe the plane configuration boundary and lock the remaining oil area formed by imperfect injection and production. Secondly, the mathematical model of dynamic change of water flooding sweep thickness is established by introducing the influencing factors such as heterogeneity and water injection /polymer injection in single sand body. Based on this, the main controlling factors of water flooding sweep thickness are analyzed, and the water-line advancement charts of different types of estuary dam are established. The actual drilling water flooding data of S oilfield are used for comparison and verification. Finally, the quantitative relationship between seepage velocity and viscosity of heavy oil is obtained by using indoor experimental data, and the equivalent numerical simulation of non-Newtonian characteristics of heavy oil in the remaining oil enrichment area is realized. The results show that after the offshore delta facies oilfield enters the high water cut stage, there are still many remaining oil enrichment areas formed by imperfect injection and production in the plane of single sand body. In the vertical distribution of remaining oil, due to different geological factors and development conditions, the thickness of water flooding will be quite different. The larger the formation heterogeneity, the larger the injection pore volume multiple, the smaller the reservoir thickness, the higher the proportion of the water flooding thickness to the single layer thickness. In the remaining oil enrichment area, the heavy oil recovery of the horizontal well infilled well pattern will be 10% higher than that of the basic well pattern. Based on this study, the error of the water flooded thickness distribution map is less than 20%, and the new wells used for guidance are in good condition. The above technologies effectively guide the research on the adjustment scheme of S Oilfield of Bohai Sea, and also provide technical guidance and direction for the stable and upper production of the same type of offshore oilfield in the high water cut stage, which has good application value.

Particle migration damage is widely common in offshore loose sandstone oilfield. And, the conventional acidification is used to remove the particle migration damage. However, it can decrease the cementation strength of reservoir rock and aggravate the particle migration damage. In this work, a two-step method of chelating weak acid combined chemical sand-consolidating fluid is proposed to treatment particle migrating damage. Luckily, this method not only protects the integrity and strength of the reservoir skeleton structure, but also avoids the re-migration damage. Moreover, the chemical liquid strengthen the cementation strength of the rock near the well zone, and inhibit the migration of movable particles with the formation fluid. The corrosion test, particle size test after corrosion and critical velocity test are employed to evaluate the comprehensive performance. The result shows that the corrosion ratio of chelating weak acid to clay minerals after 48 h can still be ~ 20% or above. It is found that migration particles larger than 800 μm can basically corroded or reduced. Especially, the corroded debris particle size located ~ 180 μm account the majority. It can stabilize the formation viscosity minerals, making the critical velocity of velocity sensitivity increase by 4 times. Besides, the experimental evaluation of compressive strength, erosion resistance and compatibility of chemical sand-consolidating fluid show that it can consolidate debris particles into cores with compressive strength up to 3.90 MPa, and its sand output rate is not higher than 0.011% under 9.15 MPa pressure difference. The field application case shows it has a significant stimulation and a long period of validity after the treatment of migration damage. The findings in this work might provide a insight into comprehensive treatment technology of particle migration damage in loose sandstone reservoirs.

At present, the dual-packer single-layer volume fracturing process is one of the main ways of re-fracturing old horizontal Wells in Changqing oilfield. However, there are still some problems, such as tubing erosion within the stuck distance, tool erosion damage, insufficient packer durability, long blowout time and low construction efficiency, which seriously restrict the scale promotion of old Wells. Therefore, the research on dual-packer single-layer pressure drag volume fracturing string was carried out. The transition between fracturing and plugging was carried out by using the controllable check valve switched by a ball, and the oil pipe dynamic sealing outside the oil pipe under the condition of annular pressure was realized by supporting the micro-collar oil pipe wellhead dynamic sealing device, finally achieving the purpose of dual-packer single-layer volume fracturing and continuous construction with pressure drag.The field application results show that the string can satisfy the pressure drag fracturing construction with dual-packer single-layer at the displacement rate of 8m3/min, effectively improve the overall construction efficiency, reduce the equipment occupancy rate, and solve the overflow problem during tripping, reduce well control risk and environmental protection pressure. It has a certain promotion and application prospect in the reconstruction of old Wells and the fracturing construction of casing damaged Wells.

Low-medium maturity organic-rich shale reservoirs have been widely concerned due to their huge reserves and oil and gas generation potential. In this study, the pyrolysis transformation process and product distribution characteristics of low-medium maturity shale via supercritical CO2 were investigated. The pyrolysis experiments were conducted on samples from the Yanchang 7 section in Changqing oilfield at high temperature and high pressure. The variation characteristics of shale pyrolysis products under supercritical CO2 conditions compared with dry distillation conditions were studied, and then the effects of different temperatures on the composition and properties of shale pyrolysis products under supercritical CO2 were further explored. The results showcase that the yield of shale oil and pyrolysis gas under supercritical CO2 is significantly higher than that of dry distillation, and the components of oil and gas are lighter. Additionally, the change of temperature remarkably influences the pyrolysis effect of shale under supercritical CO2. The yield of shale oil and pyrolysis gas increased from 0.62% and 0.82% at 360℃ to 4.7% and 7.72% at 480 ℃, respectively, and the content of asphaltene decreased from 1.16% to 0, with the maximum reaction rate ranging from 360 ℃ to 400 ℃. The rise of temperature greatly increased the light component as well as reduced the heavy component in shale oil, while the pyrolysis gas demonstrated the law that the component becomes heavier at first and then lighter. The major discoveries of shale pyrolysis transformation process and product distribution characteristics in supercritical CO2 medium not only enrich the theoretical basis in this field, but also provide strong support for the application of CO2 capture and utilization in shale in-situ transformation.

The gas injection and volumetric fracturing technology of horizontal wells have been widely used in the exploration and development of tight reservoirs. However, gas injection tends to trigger gas channeling and cause futile cycles of injected gas. Therefore, studies on optimization of well pattern parameters and injection parameters for gas drive after volume fracturing in tight reservoirs are needed. In this paper, a numerical simulation model of hydrocarbon gas drive for horizontal well volume fracturing by using CMG is established, which is based on the mechanism of hydrocarbon gas drive and the relevant data of block x233 in the Chang 72 reservoir. A comparative analysis of the mining effect of different well patterns was carried out by this model, and the optimization design of well pattern parameters and injection-production parameters was also carried out for the five-point well pattern. The results of the study show that the five-point well pattern has the best extraction effect and the inverted nine-point well pattern has the worst extraction effect on the block X233 in the Chang 72 reservoir. The 5-point well pattern has the optimal well spacing range of 150–250 m and the optimal row spacing range of 150–250 m. Horizontal wells with long fractures have a high recovery degree in the early stage and a low recovery degree in the later stage, and the optimal range of fracture strips is 7–13. The lower the bottomhole pressure of a production well, the earlier the gas is seen and the higher the degree of recovery, but the rise is increasingly slow. The higher the injection pressure of the injected wells, the earlier the gas is seen and the higher the degree of recovery, but the rise is also increasingly slow. This paper combines horizontal well volume fracturing with hydrocarbon gas flooding, and conducts a study on the optimization of well pattern and injection-production parameters of hydrocarbon gas drive, which has certain significance for the development of gas injection in tight reservoirs.

Due to deep burial depth and high pressure, CO2 can achieve miscible flooding in Jidong Oilfield, and the oil displacement efficiency can reach more than 90%.Thesweep coefficient is the key to restrict the implementation effect of this technology. Inorder to greatly improve the recovery efficiency, the numerical simulation and field statistics were combined to study the influencing factors of CO2 miscible flooding sweep coefficient from five aspects, such as reservoir heterogeneity, formation dip Angle, injection-production well pattern and injection-production speed. Heterogeneity, injection-production parameters and injection-production well spacing are the main controlling factors restricting the sweep coefficient of CO2 miscible flooding in low permeability reservoirs, and a calculation model of CO2 miscible flooding sweep coefficient is established. It has guided the formulation of CO2 miscible flooding scheme of G fault block, which is expected to increase the oil recovery rate by more than 30 percent. This paper explores a new model of water flooding to carbon flooding to greatly improve oil recovery in complex fault block strong heterogeneous multilayer sandstone reservoirs.

In order to obtain Changqing petroleum sulfonate complex system of better performance and adapting to Changqing reservoir conditions, takes Changqing petroleum sulfonate as the main agent, the synergistic effect of petroleum sulfonate and different surfactants was investigated. The results show that Changqing sulfonate and C16ArSO3 anionic surfactants, 6501 non-ionic surfactants, C18N cationic surfactant, betaine amphoteric surfactant compound having synergistic effect and higher interfacial activity. Considering interfacial activity and anti-adsorption, Changqing petroleum sulfonate and 6501, Changqing Petroleum sulfonate and octadecyl sulfopropyl betaine is preferred complex system.

After nearly ten years, the pilot test of in-situ combustion in the HQ1 area of the near-abandoned oil reservoir after steam injection development in Xinjiang Oilfield has achieved phased achievements. Based on this experience, the area started industrialization trials in 2018. During the ignition process of a gas injection well, the ignition string suddenly broke and fell into the bottom of the well, and the ignition operation was forced to stop, which had a serious impact on the production operation. Through chemical composition, mechanical test, microstructure observation, metallographic analysis, corrosion products were tested, so as to analyze the failure cause of the tubing fracture. The results show that the fracture of the N80 tubing is mainly due to the abnormal microstructure caused by corrosion in high temperature environment and the thinning of the tube wall, which leads to the decrease of bearing capacity and impact resistance and fracture. The study results will provide a brief reference for the safety and efficiency of subsequent ignition operations.

B3 block of Changqing Oilfield has low reservoir permeability and high salinity formation water. In order to solve the problems of poor injection and salt resistance of conventional polymers and further improve the development effect of polymer flooding, the adaptability of low molecular weight anti-salt hydrophobic associating polymers in this test area is studied. The viscosity, salt resistance, shear resistance, adsorption resistance and aging stability of the polymer were measured by laboratory experiments. The experimental results show that compared with polyacrylamide and functional polymer, the low molecular weight salt-resistant hydrophobic associating polymer has better salt resistance, shear resistance and stability. The viscosity of 2000 mg/L polymer is 28 mPa·s at 50 ℃ and 13600 mg/L mineralization (572 mg/L calcium and magnesium ion concentration). The core with 70–80 mD permeability was used for oil displacement experiments. The results showed that the viscosity retention rate of polymer flooding solution reached 80%, and the oil displacement efficiency can be improved by 14.8% on the basis of water flooding.

In recent years, ultra deep fractured gas reservoir is a hot spot of natural gas exploration and development in Tarim Basin. This type of gas reservoir has poor matrix properties, developed fractures, and is severely affected by water invasion, resulting in a low recovery rate. Taking KS 8 gas reservoir in Kuqa depression of Tarim Basin as an example, using seismic, logging, core, well testing and production dynamic data, this paper analyzes the geological characteristics and production performance of gas reservoir, and systematically puts forward technical countermeasures for water-control development to improve gas reservoir recovery. Keshen gas reservoir has tight matrix, naturally developed fractures. The pressure propagation between wells is fast due to the developed multi-scale fractures, showing good connectivity of sandstones reservoirs. The water body has the characteristics of strong in the west and weak in the east. In the west part of Keshen 8 gas reservoir. Direction of formation water intrusion can be divided into two paths: from west to east and from northwest to southeast, and the water intrusion velocity is reach 50 m/d. Development technology measures such as appropriate production rate, differential production allocation of gas wells, and active drainage of vertical and horizontal wells are put forward to enhance the recovery of the gas reservoir. This study can provide reference for the development of similar gas reservoirs.

Aiming at the problem of steam stimulation recovery calculated by the traditional method specified by China Petroleum Institute is higher than actual value in Kenkiyak post-salt oil reservoir, based on the orthogonal simulation experiment and numerical simulation results, a new recovery calibration method of steam stimulation in shallow heavy oil reservoir in Kazakhstan is re-established by multiple regression method. The improved formula reduced the calculation error in this area from 5% to 2%, and the accuracy is greatly improved. The formula is suitable for the calibration of steam stimulation recovery of shallow ordinary heavy oil in Kazakhstan, which fills the gap of recovery calculation method of this kind of reservoir in Kazakhstan, and has been applied in Kenkiyak post-salt oil reservoir. The result of the method application were finally authorized by Kazakhstan Reserves Committee.

The yield of tight reservoirs declines rapidly in depletion development, gas injection after volume fracturing is an effective means to develop tight reservoirs. As the associated gas in oilfields, natural gas is a good injection gas with abundant resources and non-corrosive. In addition, in the gas injection process, gas channeling after volume fracturing is also a difficult problem that seriously affects the development effect, but huff-n-puff can effectively alleviate it. For these reasons, tight cores and tight oil were selected from the actual tight reservoir, and fracture-matrix tight cores were designed and made. Then, natural gas huff-n-puff experiments with different injection pressure and injection gas volume were conducted. Every experiment included three cycles, and the development effects and characteristics of different cycles were analyzed. The gas to oil replacement ratios (GORR) under different conditions were compared to evaluate the injection schemes. The development effects of different gas injection schemes were analyzed using NMR technology. The results demonstrated that natural gas could effectively develop tight oil by huff-n-puff. High injection pressure contributes to improving the oil recovery, and oil is mainly recovered in the first two cycles. At high injection pressure, the difference in oil recovery between two tight cores with different permeability is obvious. The higher permeability core has a higher oil recovery. Under the promise that the total gas injection is the same, the more gas injection in cycle 1, the greater the final oil recovery. Increasing the injection volume in a single cycle can improve the oil recovery in this cycle. The higher pressure and higher gas injection of the first cycle can cause a higher GORR. The research is conducive to the application of natural gas in tight oilfields.

As the main contributor to the production of Huabei Oilfield, the major sandstone reservoirs in Jizhong area have entered into middle and late development stages with high water cut, and the development effect has gradually deteriorated. Therefore, effective technical policies are the key to improving the development effect of reservoirs. Combining the characteristics of different sandstone reservoir types, existing problems and remaining oil potential, this paper has formed an adjustment technology that can effectively improve the development effect in the middle and late development stages of sandstone reservoirs in Jizhong area, through carrying out research on layer recombination and subdivision, differentiated adjustment of injection-production well pattern, the potential exploration of injection-production profile and other technology, which has been applied in more than 10 blocks. After the adjustment, the natural decline of these blocks has slowed down from 14.9% to 11.3%, the comprehensive decline from 8.7% to 2.3%, and the increase rate of water cut decreased by 1.9 percentage points.

High water cut sand wells in loose sandstone reservoirs greatly affect the development benefits of oil fields. Conventional sand control technology only has the function of sand control, but cannot solve the problem of high water cut. In this paper, a kind of calcium aluminate precipitation particle which can permeate oil and inhibit water was developed (particle size of 0.3 ~ 0.5 mm, 0.5 ~ 0.7 mm and 0.7 ~ 1.4 mm). The consolidation temperature is 30 ~ 80 ℃, the compressive strength is 3 ~ 5MPa, and the liquid permeability is 0.3 ~ 0.8 μm2. With core function of the material, combined with mechanical sand control, the oil permeates and water resistance artificial shaft wall sand control technology was formed. It can effectively reduce the water cut of the produced liquid and improve the development benefit of the high water well. This technology has been successfully implemented in more than 50 Wells in Dagang Oilfield, and the success rate of sand control construction is 100%. The cumulative recovery of oil production is 32,856 tons, and the cumulative increase of oil is 14,652 tons. The average water cut of the produced liquid in sand control Wells is reduced by 11.2 percentage points, and good sand control effect has been achieved.

With the development stage of medium and high water cut, The peak water intake in the profile of Wuliwan C1 reservoir is improved after weakened water, and water injection inrush is easy to lead to water flooding in small injection, but the proportion of non-suction well or weak suction well in the first interval section is high. The plane remaining oil is mainly distributed in the micro-seepage channel in the deep part of the reservoir and the water flooding is difficult. At the same time, the conventional measures are difficult to develop the remaining oil, and it is more difficult to further expand the swept volume after multiple rounds of microsphere flooding. Based on reservoir temperature, crude oil properties, formation water and produced water salinity composition in the test area, a lower medium phase microemulsion flooding system under the condition of high salinity was designed. The results show that the designed medium phase microemulsion system is composed of two surfactant complex, the volume ratio of the main surfactant A and the auxiliary surfactant B is 1:1, and the interfacial tension can reach 0.003 mN/m under the condition of 0.5% mass concentration, which has very low interfacial tension and good solubility. The swept volume of microsphere flooding was expanded, the oil washing efficiency was improved by the medium phase microemulsion flooding in the test area of Wuliwan C1 reservoir, which had an obvious effect on reducing water cut, and improved a new method for the effective use of remaining oil in the middle and high water cut reservoir.

Because of special physical and chemical properties of microemulsion, it has become one of the research hotspots of oil and gas exploitation as an important production enhancement aid. In this paper, an anionic nonionic surfactant (polyfatty alcohol polyoxyethylene ether acrylate sodium stylenesulfonate lauryl acrylate, P(AEO-9-AA-SSS-LA)) was prepared and mixed with cosurfactant, produced water and crude oil to obtain a new type of middle phase microemulsion. The structure of P(AEO-9-AA-SSS-LA) was characterized by infrared spectrum and nuclear magnetic hydrogen spectrum, and the particle size, interfacial tension, salt resistance, emulsion stability, temperature resistance and static adsorption capacity of the middle phase microemulsion were tested. The results show that the average particle size of the droplets of the middle phase microemulsion is about 25 nm, and the droplets are connected to each other in an orderly manner. The interfacial tension reaches 10−2mN/m, and the adsorption capacity of 0.01 wt% middle phase microemulsion after 24 h of adsorption in the oil sands is about 9 mg/g. In addition, the prepared middle phase microemulsion has excellent temperature and salt resistance, which is expected to be used in the field of tertiary oil recovery.

Polyacrylamide fracturing fluid is a common working fluid suitable for fracturing development of low permeability oil and gas fields at home and abroad. In the application process, due to incomplete gel breaking, untimely flowback and the reaction between polyacrylamide fracturing fluid and reservoir material, reservoir damage after fracturing is often caused, which is an influencing factor that must be considered in fracturing development of oil and gas fields. In this paper, the reflection relationship between molecular coil size in fracturing fluid solution with different decomposition gel breaking and gel breaker concentration was established by means of rheometer, laser dynamic light scattering and atomic force microscope. The compatibility of different metal cations in the solution with gel breaking solution was investigated by ampoule aging experiment. It was determined that iron ions were the main controlling factor leading to the complexation and precipitation of polyacrylamide molecules under the ion concentration of formation water. Furthermore, the influence of molecular coil morphology and size in gel breaking solution on fracture flow conductivity was investigated by physical simulation experiment of core flow. Finally, by studying the interaction mechanism between polyacrylamide fracturing fluid and reservoir fluid, the influence mechanism of fracturing fluid with different occurrence states on reservoir physical properties and fluid flow is explored, which provides a basis for the development of fracturing fluid and the improvement of gel breaking technology.

Adding functional monomers to improve heat resistance of Partially hydrolyzed polyacrylamide (HPAM) becomes a hot point in recent years. However, to fully comprehend the impact of the molecular architectures of the functional monomers on heat resistance, more research is still needed. Four polymers with the main chains of acrylamide (AM) and adding other functional agents were synthesized through free radical polymerization, and their structures were characterized. To ascertain the heat resistant performance, the viscosity, viscosity retention rate and viscosity recovery of the polymers were evaluated. At last, explain how the molecular structure of the polymer affects temperature resistance by comparing the viscoelasticity properties of polymers before and after structural breakdown. The results showed that the viscosity of the four distinct polymers decreased as temperature rose and even showed a trend toward irreversible viscosity loss at temperatures over 70 ℃. At 90 ℃, the irreversible viscosity loss was lowest in polymers containing N’ N-dimethylacrylamide (DMAA), at 37.8%, and highest in polymers containing Dodecyl phenol polyoxyethylene ether (DP), at 70.9%. The viscoelasticity analysis demonstrated that all storage modulus of the four polymers before aging were higher than their loss modulus, while after aging, the opposite trend emerged, which proved that the irreversible loss of viscosity was caused by the destruction of the spatial network structure due to the main chain broken under high temperature. Besides, the small decrease of the storage modulus and huge shear viscosity loss of PAADA manifested that the hydrophobic association and steric hindrance effects of polymer monomers with branching structures worked synergistically to reduce the chain broken. This suggests that functional monomers with branched structure and hydrophobic structures may be a better option for increasing heat resistance. This paper lay a theoretical foundation in rheology for the modification of HAPM with better heat resistance.

The oil-water distribution is essential for evaluating the oil displacement effect and development potential during flooding in high temperature and high salt reservoir. Low-field nuclear magnetic relaxometry(NMR) T1-T2 maps is one of the methods for analyzing oil- water distribution. In order to analysis oil-water distribution at different displacement stage, two-dimension NMR T1-T2 map, and oil-water two-phase displacement experiments were employed on sandstone samples and oil collected in Gasi Reservoir, Qinghai Oilfield. Combining NMR and core displacement results data analysis, the reason for whether oil is produced and the entire flow process of oil and water in the displacement experiments were explained, distribution characteristics of oil and water in the NMR T1-T2 map were analyzed, and evaluate the crude oil production characteristics during the flooding. The results indicated that the pore structure of the sandstone samples is single and show weak heterogeneity according to the NMR T2 spectrum, and the distribution of sandstone pore size is the main factor determining whether there is oil in the sandstone core in the displacement experiment. NMR T1-T2 map is an effective way to identify different components (oil and water) of sandstone samples and the oil-water distribution, and Hydrogen signal distribution regions of oil and water changed after the oil and the brine of 152144 mg/L injected into the sandstone core successively, and the recovery rate increased by approximately 71.3%. Along with the surfactant injected into the sandstone core, the changes of NMR T1-T2 map were slight, and the recovery rate increased by approximately 8.8%. Therefore, T1-T2 map provides another effective method for describing the displacement process.

Low-permeability thin sandstone reservoirs are characterized by small thicknesses, low permeability, and low porosity, making them difficult to develop. This paper investigates a micro-fracturing blockage removal technique to improve the development performance of such reservoirs by injecting a certain amount of fracturing fluid into the wellbore to produce micro-fractures in the reservoir. This technique can improve the reservoir seepage conditions and increase crude oil production. The paper first introduces the principle and process flow of micro-fracturing blockage removal technology. It then analyzes the performance and influencing factors of fracturing fluid through numerical simulations. Finally, the application effect of micro-fracturing blockage removal technology in low-permeability thin sandstone reservoirs is verified through field tests. According to the results, the micro-fracturing blockage removal technology can effectively improve the production capacity and recovery rate of low-permeability thin sandstone reservoirs. It is a simple, economical, and effective method for reservoir development.

The water lock effect is a common problem in the development process of gas fields, mainly manifested as a decrease in gas phase permeability after the water saturation of the gas reservoir changes. The water lock damage caused by the accumulation of liquid at the bottom of the well in the near wellbore reservoir has led to a sudden decrease in gas well production, seriously affecting the efficient development of the gas field. The Sulige gas field belongs to a typical low-pressure, low-permeability, and tight sandstone gas field. Currently, it has entered the middle and late stages of production. Most gas wells are already in the low production and low-pressure stage due to the continuous decline of formation energy, and there are varying degrees of water production in the gas reservoir. The study of reservoir water lock has become a key technical field for improving oil recovery in gas fields. Based on the production demand of Sulige gas field and the problem of water lock in gas reservoirs, the conditions for water lock in gas reservoirs and the main factors affecting water lock in gas reservoirs were studied on the basis of multi factor analysis. Subsequently, the damage assessment of water lock in gas reservoirs was conducted; Analyze the main methods of water lock release in gas fields and conduct research on on-site water lock release agents; The on-site optimization of the water lock removal process has verified the feasibility of the water lock removal technology in this area, which is of great significance for the recovery of gas field production.

There are many factors that affect the development effect In the development process of medium porosity and permeability reservoirs. Clarifying the degree of influence of different influencing factors is conducive to further improving the development effect. This paper establishes the model and studies the main factors influencing the development of the reservoir based on the reservoir parameters of Zaoyuan oilfield and Wangguantun oilfield. Quantify the relationship between single factor changes and development effectiveness using reservoir numerical simulation methods. Based on this, the sensitivity of factors that affect development effectiveness is divided into three categories from high to low by establishing a sensitivity comparison method for different single factors. The influencing factors of high, medium, and low sensitivity levels. The research results provide a method for improving the development effect by optimizing and regulating the main influencing factors during the development process.

Fracture-flooding injects a large amount of water in a short period of time into those low-permeability sandstone reservoirs with insufficient injection and dramatic formation pressure drop, resulting in a significant increase in liquid production. However, there may not be a corresponding increase in oil production if no chemicals are used. In this study, a micro emulsion was prepared and used to improve the fracture-flooding effects. Its abilities to reduce interfacial tension, to change wettability, and to reduce oil viscosity were measured. Core displacement experiments were designed to simulate fracture-flooding using the micro emulsion and using water without chemicals. The oil displacement effects were compared, and the mechanisms of improving oil production for the micro emulsion were described. A pilot test was then conducted in a well group to verify its practicality. The results showed that the micro emulsion had nano-size droplets, reduced the interfacial tension between oil and water, changed the wettability of rock face, reduce the viscosity of the crude oil, and strengthened the imbibition process. In core displacements, the oil recovered by fracture-flooding with the micro emulsion was 24.9% higher than that by fracture-flooding with only water. The mechanisms were summarized as larger sweeping volume, higher displacement efficiency, and more oil-water replacements. The average oil production rate of the test well group was 55.6% higher than that of another well group with similar reservoir properties developed by fracture-flooding with only water. Therefore, the micro emulsion can improve the effects of fracture-flooding, which is of great significance for the promotion of the fracture-flooding technology and the efficient development of some low permeability reservoirs.

After the water drive well pattern of oilfield A cooperated with EOR for many times, the used reserves gradually decreased and the proportion of low-efficiency wells increased, which severely restricted the water drive development adjustment [1, 2]. In order to realize the full utilization of reserves and well resources, since 2020, SP reservoir combined with the evolution of stratigraphic well pattern of water drive well pattern has released the sealing potential of eight blocks that have finished EOR by means of reperforating, making good use of reserves. It is an urgent task to improve the relationship between injection and production, maintain the balance of formation pressure and effectively realize the transformation of flow field, alleviate the interlayer contradiction of various oil layers, improve the utilization degree, maximize the excavation of remaining oil in the well area for reperforating, and realize the replacement of water drive reserves [3]. Therefore, this paper focuses on the practice and research of the comprehensive adjustment method of injection-production system in the well area after reperforating. On the basis of improving the injection-production relationship, it strengthens the comprehensive treatment at both ends of injection-production, further promotes the precise water injection and accurate potential excavation, highlights the targeted adjustment of key areas and key well formations, and strives to excavate potential strata to adjust the remaining oil in the well area. It provides reference experience for subsequent adjustment of similar well area.

In view of the problems of high water content, high temperature and high salinity of formation water in old oilfields, the elasticity and strength of conventional swelling particle profile control agent rapidly decline after swelling, and the ability of heat resistance and salt tolerance is insufficient, so it is difficult to meet the demand for high-strength plugging near wellbore areas. Therefore, a high elastic dual network polymer particle profile control and water shutoff agent was prepared by two-step polymerization. Firstly, 2-acrylamide-2-methylpropane-sulfonic acid (AMPS) was used as monomer and N, N’- methylene bisacrylamide (MBAA) was used as crosslinker to form the first cross-linked network product which is rigidity by photoinitiated polymerization; Then, the first cross-linked network product was immersed in a polymerization system composed of acrylamide (AM), crosslinker (MBAA) and initiator, and the polymerization system slowly diffused into the first gel network to make it fully swelling, and the second cross-linked network product which is flexibility was formed by photoinitiated polymerization; Finally, the high elastic dual network polymer particle profile control and water shutoff agent was prepared by freezing, drying, grinding and screening. The experimental results showed that when the molar ratio of AMPS to AM was 1:40, the initial temperature was more than 20 ℃, the dual network polymer with high elasticity, high strength, heat resistance and salt tolerance could be prepared. The elastic modulus of the polymer is more than 2000 Pa, and the tensile deformation can reach 345%, Under the condition of 90 ℃ with the salinity is 20 × 104mg/L, it can be stable for 120 days, the core plugging rate is greater than 94.4%, which meets the technical requirements of high-strength plugging near the well in high-temperature and high salinity reservoirs.

Density functional theory (DFT) in quantum mechanics is widely used in the calculation of interaction energy between molecules due to its high accuracy and relatively small amount of calculation, and plays an important role in catalysis, metal coordination, supramolecular arrangement and stacking and other fields. The viscosity and flow characteristics of heavy oil are closely related to its internal composition and structure. However, the composition of heavy oil is very complex. This article focuses on the analysis of the main components and structure of heavy oil, and further studies the viscosity inducing and viscosity reducing mechanisms of heavy oil. Using the B3LYP scheme of density functional theory algorithm in quantum chemistry ab initio Gaussian-03 program ω 97 basis groups were fully optimized for the above model compounds and hydrogen bonding interaction models. Structural optimization of resin and asphaltene molecules was carried out using B3LYP/6.31G (d. p), with a minimum frequency of positive values and no imaginary frequencies, indicating that the optimized structure is stable. Through analysis, the polar group of resin and asphaltene in heavy oil is the main structure factor of viscous oil. The intermolecular van der Waals forces, π−π forces between aromatic layers, and hydrogen bonding are the main forces between heavy oil molecules. The main factors causing viscosity in heavy oil are the strong interaction force between large molecules and aggregated supermolecules, and the difficulty in thermal movement; The stacking, entanglement, interpenetration, and curling of macromolecular chains and circular molecules further increase the flow resistance, which is also an important factor in increasing the viscosity of heavy oil. Clarifying the viscous mechanism of heavy oil can lead to targeted molecular design of heavy oil viscosity reducing agents, significantly improving the viscosity reduction rate of heavy oil.

In the process of CO2 flooding, the complex brine-rock reaction occurs as the reservoir rock in the acidic circumstance formed by CO2 and brine, resulting in the changes of the physicochemical properties of the rock, thus affecting the seepage of crude oil in the reservoir and oil recovery. Therefore, combined with SEM and XRD analysis, contact angle test, mercury injection and relative permeability experiment, CO2-brine-rock static contact immersion experiment was carried out in this paper to systematically study the influence of brine-rock reaction on rock surface properties, pore throat structure and seepage characteristics of oil and water. The experimental results detected that at the effect of water-rock reaction, a large amount of hydrophilic quartz on the rock surface was exposed, the content of feldspar and calcite reduced, the content of kaolinite increased significantly, and the contact angle of water phase decreased by 15.7°. The solid particles produced by dissolution effect blocked the large pores in a lower permeability core (K ≤ 300 mD), which could reduce the core permeability and damage the core. However, for the core with a higher permeability (K ≥ 700 mD), the dissolution effect could increase the pore size and connectivity, effectively improved the permeability of oil phase and water phase, and reduced residual oil saturation of 10.3%. The results show that the brine-rock reaction can improve the wettability of the reservoir rock surface. The reaction has the effect of expanding pore size and increasing permeability in the higher permeability reservoir, and can improve the mobility of crude oil in the reservoir, and contributes to the oil recovery.

The heavy oil reservoirs in the sixth district of Gangxi Oilfield, with active bottom water, has serious problems of bottom water coning in the development, resulting in uneven movement of the oil formation in plane and longitudinal directions and low recovery rate. Scholars at home and abroad proposed a recovery technology that uses CO2 huff and puff to control water pressure cone and improve the development effect of heavy oil reservoirs in bottom water. To further prove the applicability of this technology, a small-scale mine trial of CO2 huff and puff to increase production in heavy oil reservoirs with bottom water has been conducted in Gangxi Oilfield, and the production increase effect of single well was obvious, which clarified the major controlling factors of the CO2 huff and puff control water stimulation effect. In this paper, based on the current geological reservoir status of the heavy oil reservoir in the sixth district of Gangxi Oilfield, the main control parameters affecting the huff and puff effect, including the CO2 injection volume, injection rate, injection pressure and well staging time, were optimized, and implements a larger-scale CO2 huff and puff and production increase measure. The results of the field implementation confirm that CO2 huff and puff can cooperate with bottom water to increase the elastic driving capacity of the formation, reduce the viscosity of crude oil, inhibit the cone of bottom water, and improve the oil drive efficiency of heavy oil reservoirs. This paper’s research results can be applied to guide similar reservoirs to adjust their development plans and implement CO2 huff and puff to improve the effectiveness of development and enhance the recovery rate. At the same time, CO2 huff and puff technology can also contribute to China’s goal of “carbon peak and carbon neutrality”.

The ultra-high water cut period is the key period for waterflooding oilfields to further improve recovery efficiency. The simultaneous implementation of water shutoff in production well and profile control in injection well is an effective technique to start the remaining oil in ultra-high water cut reservoirs, but there is a lack of reliable method to optimize the selection of deep profile control and water shutoff wells during field construction. To this end, a method to identify the corresponding relationship between injection wells and production wells is proposed by using the static, dynamic and monitoring data of the reservoir. Based on this, an improved gray slope correlation model is applied to calculate the injection-production correlation coefficient based on the dynamic data of oil and water wells. Furthermore, the water drive non-uniformity coefficient and interwell outburst index are constructed, and a well selection decision method for simultaneous operation of oil and water wells in the target area of ultra-high water cut oilfields is established. The effect of deep profile control of deep profile control and water shutoff test area in Zone 7 of the Gudong oilfield proved that the decision-making method is scientific. The new construction method has perfect consideration factors, easy access to data and strong practicability, which plays an important guiding role in the optimization selection of deep profile control and water shutoff wells in ultra-high water cut oilfields.

CO2 flooding is being widely practiced in low permeability reservoirs for Enhanced Oil Recovery, which is of profound significance in reducing greenhouse gas emissions considerably. Water Alternating Gas (WAG) flooding is the primary method to restrict gas channeling. Still, the WAG flooding with the constant water-gas ratio and slug size of water cannot match the variety of interwell permeability. A method is developed to design dynamically varying water-gas ratios and slug sizes in WAG flooding, which is expected to improve the effectiveness of CO2 drive field applications significantly.Aiming at these problems, the phase behaviors of light oil–CO2 systems were firstly tested, and two types of CO2 injection experiments-constant and dynamic WAG flooding -were conducted in core plugs. Second, based on fluid phase fit-ting, history-matching studies on experimental results were completed. Third, a WAG scheme with varying water-gas ratios and slug sizes were simulated using the numerical model. A set of dynamic WAG drive design templates with different interwell permeability was developed using recovery and CO2 utilization as evaluation metrics. Finally, the vibrant WAG drive scheme is prepared and applied in the field block.The results of laboratory experiments show that compared with constant WAG drives. Dynamic WAG drives significantly reduce the gas-oil ratio in mid-late production and increase the ultimate recovery by five percentage points. The main control factor of the water-gas ratio and segment plug size of the dynamic WAG drive is internal gas saturation. The key parameters are the initial water-gas ratio and the adjustment range of the water-gas ratio. The larger the permeability differential, the more suitable dynamic WAG drive is. Timely adjusting the water-gas ratio and slug size can effectively control fluid mobility within the reservoir.This paper proposes analyzes the optimal water-gas ratio and slug size for dynamic WAG drive under different permeability differentials. Using laboratory experiments and numerical modeling, which can effectively improve CO2 development and facilitate the long-term efficient operation of CO2 drive projects.

As the continuation of conventional reservoir development, deep low permeability reservoir has the characteristics of large reserves, deep burial and low permeability. In the process of development, the initial production is high and the production decline is fast. Conventional water flooding is difficult to form an effective displacement relationship, and new measures to enhance oil recovery are urgently needed. By comprehensive comparison of various technologies, it is feasible to carry out natural gas flooding in well group B 16–17 of Dagang Oilfield, but the minimum miscible pressure and injection pressure to achieve beneficial development are still unclear. In this paper, the minimum miscible pressure prediction model was established by using CMG Winpro phase software on the basis of fine tube experiment and empirical formula, and the minimum miscible pressure of natural gas flooding in target block was predicted to be 40.75 MPa, which greatly improved the prediction accuracy and reduced the prediction cost. On the basis of the original injection pressure prediction model, the permeability revision chart is improved, and the reason why the wellhead pressure is much higher than the stable pressure is explained that the gas phase permeability is lower than the absolute permeability in the oil-gas water three-phase flow near the well. The natural gas flooding effect of well group B 16–17 is remarkable, and the formation energy is effectively supplemented. By the end of 2022, a total of 4.297 MCM of natural gas had been injected, 5,439.61 tons of accumulated oil had been produced, and 4,281.5 tons of controlled decline had been added. Oil stability, water control and swelling and viscosity reduction are the main stimulation mechanisms of natural gas flooding, which have application potential in the 450 million ton reservoir of Dagang Oilfield.

Fluid mobility analyses during imbibition process and investigation of pressure changes synergetically associated with imbibition in tight oil formations are important due to the limited flow ability of matrix-fluid systems without manufacturing fractures. Imbibition is an important mechanism of oil recovery in rock matrix whilst many previous experiment studies were employed on spontaneous imbibition at ambient pressure. Influence factors of oil recovery need to be ascertained over imbibition interacted with cyclic fluid huff-n-puff and continuous displacement for EOR and energy replenishment. This research provides an experimental analysis method of fluid mobility within different sized pores in the combined processes of huff-n-puff imbibition and displacement in tight sandstone cores. Additionally, the experimental study on analyzing pore fluid mobility and identifying reasonable imbibition time are performed by transformation from huff-n-puff imbibition to displacement tests with different imbibition time. Furthermore, the influence factors on matrix oil recovery of several conditions are analyzed and their extent of effect on recovery of huff-n-puff imbibition and displacement are compared, including direction of displacement, time of transformation from huff-n-puff imbibition to displacement, pressure of displacement and existence of fracture. Experimental results show that: At the stage of huff-n-puff imbibition, the macropore was used as primary channel seepage for oil arising from mesopore and micropore which made major contributions to imbibition recovery, respectively, by 44.62% and 32.19%. The factors in orders of influence on oil recovery are as follows: direction of displacement, time of transformation from huff-n-puff imbibition to displacement, existence of fracture, pressure of displacement. This study suggests that displacement is in the same direction as imbibition, and the reasonable time for imbibition before displacement is 96 h. The research results provide important reference for the study of enhanced oil recovery in tight sandstone reservoirs.

In the late stage of oil development, water channeling is a severe issue with viscosity-reducer flooding in deep heavy oil reservoirs, making it challenging to have a viscosity-reducing impact. The foaming viscosity reducer compound flooding uses the selective plugging characteristic of foam to block the water channeling and greatly reduce the viscosity of heavy oil at the same time. The basic mechanisms of the foaming viscosity reducer compound flooding were summarized based on the laboratory experiments, and the parameters required for the numerical simulation were also obtained. The geological model of a target deep oil reservoir with different mechanisms of action was established, and the influence of the injection parameters of foaming viscosity reducer compound flooding on the oil recovery factor was systematically studied by numerical simulation after production in history well matched. The results show that foaming and viscosity reducer compound flooding can solve the problems of weak flow capacity and water channeling of heavy oil. After considering the economic cost and oil recovery efficiency, the optimal foaming viscosity reducer concentration is chosen to be 0.5wt%, the injection volume is 0.07 PV, the gas-liquid ratio is 1.5:1, the injection rate is 70 m3/d, and the final oil recovery is 14.36% higher than that of water flooding. This study achieves the optimal development of the target reservoir and provides certain reference significance for the efficient development of deep heavy oil reservoirs where water channeling occurs.

Aiming at the problem of poor effect of waterflooding in ultra-low permeability reservoirs in Ordos Basin, a study on enhanced oil recovery (EOR) technology by natural gas drive is conducted with the Zhenbei C8 reservoirs as the research object. In view of the problem of unclear understanding of the microscopic dynamic process and oil displacement mechanism of natural gas drive in ultra-low permeability reservoirs, oil displacement tests with water-drive, gas-drive, and gas-foam-drive are carried out respectively by using the microscopic visualized oil displacement device based on simulation model of glass etching, so as to study the remaining oil type and the law of producing remaining oil after starting water-drive with different media (natural gas, natural gas foam). At the same time, the diameter limits of pores-throats with water-drive and gas-drive producing reserves in ultra-low permeability reservoirs are clarified on the basis of the NMR technology. The research shows that the swept area of natural gas drive is smaller than that of water drive, but the oil displacement efficiency can be improved by dilating, reducing the viscosity and extracting the crude oil in the area where it flows (or percolates). Natural gas-foam flooding increases the injection pressure by means of foam, and can divert the gas, thus expanding the microscopic swept area and slowing down the gas channeling at the same time. The radius of minimum pore-throats with water-drive producing reserves in ultra-low permeability reservoirs is 0.1 μm. The radius of available pores-throats with gas-drive reserves is two orders of magnitude smaller than that with water drive, and the radius of those with gas-foam drive is one order of magnitude smaller than that with water drive. The research results provide a new way for further enhancing oil recovery of related reservoirs.

Comparing to sandstone gas reservoir, the low-permeability carbonate gas reservoir with has higher natural gas storage capacity and more economic benefits. It is an important area for exploration and development for tapping potential and maintaining stability. Taking M gas field, a large low-permeability carbonate gas reservoir in Ordos Basin, as an example, due to the gas reservoir enters the later stage of stable production, it faced serious problems of high reserves utilization (95%) and low gas recovery (25%). At this stage, the well pattern infilling adjustment is very urgent for the stable production and enhance gas recovery of the gas field. However, due to the widespread development of erosive trenches in M Gas Field with extremely strong heterogeneity, and after more than 20 years of development, it is very difficult to accurately describe and effectively utilize the remaining reserves scattered around the edges of the trenches and between wells. Therefore, this article focuses on two potential tapping areas, which are the edge of the trenches with low well control degree and between wells with high well control degree. First of all, it proposes a new method for describing the two remaining reserves by paleogeomorphic restoration based on paleogeomorphic characterization, and inter well formation pressure evaluation for low-permeability lithologic gas reservoirs. On this basis, it subdivides regional physical properties and development stage differences, with introducing effective permeability, infill timing, and economic benefit evaluation to establish identification curves for rapid deployment of infilled gas wells.Then key technologies for infilling and adjustment in the middle and late stages of development of large heterogeneous gas reservoirs have been established, which is clarified fundamental issues of “where, when, and how to add” for the gas field at this stage for the first time. The application results show that:1. The new palaeogeomorphic restoration method has improved the evaluation accuracy of the traditional trench potential tapping area from 76.3% to 88.3%, expanded the gas-bearing area of 540 km2, and fully implemented the trench potential tapping area; 2. The inter-well field pressure evaluation overcomes the problems of neglecting the pressure unbalance by the discharge radius method and long time consuming by the numerical simulation method. Besides, it successfully exploits the potential of two high energy value of inter-well in typical block which previous considering without infilling space; 3. Based on the key technology of infilling wells, 117 gas wells deployed in the trench area and 14 deployed in inter well area. It indicates good effect with 1.9 × 104 m3/d stable production in the initial period, which are predicted cumulative gas production increase is 85.2 × 108 m3 and increase gas recovery by 2.1%.

Water flooding was the key method for oil recovery in China, so far the technology of downhole water injection had been updated to the fourth generation, enhancing the efficacy of this measurement significantly. While the period of water injection usually last at least 2–3 years, the downhole environmental was harsh, posing serious threat to the integrity of downhole injector, particularly to the intelligent type which integrated mechanical and electrical devices in a compacted area.In this paper, the plan aimed at trialing the intelligent injector was developed based on its actual working conditions, assessment method was constructed to ensure the long term effectiveness of this tool, and finally relevant standards were dratted based on previous work.The results indicated that there were three key modules, the motor, the nozzle and the electric circuit respectively, relevant tests included the properties of motor and nozzle, aging of the electric circuit. As for the whole system, it had to pass the test of sealing and vibration, as for the field operation, assembly procedures and rational ratings were required to make sure zero accidents over 3 years operation. All the targets were quantified in the paper based on the feedback information of field trials.The paper prescribed the failure cause of downhole intelligent injector, the trial strategy based the prescription was summarized, the assembly standard was also drafted, efforts were made form a holistic view and the outcome did prove its value in ensuing the integrity of intelligent injector, making it a paradigm for downhole tool quality control tactics.

The front facies deposition in T oilfield is the main one, and the development target layer is oil layer I, which belongs to medium porosity and medium permeability oilfield. Narrow strip and branch distributary channel sand bodies are developed in Block A. After the main sand body oil layer is flooded, the water content rises rapidly. At present, the comprehensive water content has reached 84.8%, while the recovery rate is only 20.3%. The contradiction between inefficient and ineffective water injection cycle is prominent. Innovatively implement LHW nano-micron microsphere deep profile control and flooding in the narrow strip development block with serious water flooding in the main sand body reservoir in the north of T oilfield, re-quantize the remaining oil distribution according to the numerical simulation results, design multiple slugs and multiple rounds of injection, optimize the swabbing parameters, and take timely measures to lead the effect [1, 2]. The remaining oil in this block is scattered, the control degree of water drive is 82.8% (the ratio of two-way and multidirectional connection is 53.4%), and the effective thickness ratio of water absorption is 92.2%. The effect of conventional water injection adjustment is not obvious. Therefore, the deep profile control and flooding work is carried out to improve the water utilization rate of injection and improve the development effect of the block.

With the continuous improvement of the exploitation degree of oil fields, most of the domestic oil fields have entered the tertiary production stage. As a relatively mature oil production technology in the tertiary oil production stage, enhanced foam flooding technology is widely used in all oil fields. At the end of 2014, a combined station of an oil field began to carry out the production test of nitrogen foam drive. With the increase of the number of measure wells and the implementation of strengthening nitrogen bubble foam drive, the emulsion strength of the produced fluid entering the combined station gradually changed, and the difficulty of dehydration increased. Specifically, the water content at the outlet of the two-phase separator fluctuates seriously, the crude oil dehydration temperature rises, and the energy consumption increases; Due to the high degree of emulsification of the produced liquid, it is more difficult to dewater the crude oil, and the demulsifier needs to be adjusted repeatedly; The water content of crude oil is difficult to meet the standard, and it has occupied the storage capacity of the combined station for a long time, so the overall operation efficiency of the combined station is low. This paper takes the produced liquid of an oil field combined station as the research object, analyzes the physical properties of the produced liquid of foam flooding, explores the effects of different water content, foaming agent concentration and polymer concentration on the physical properties of crude oil, and then carries out experimental research on adding foaming agent and polymer respectively at different mixing speeds, simulates the mixing state of crude oil, foaming agent and polymer, and analyzes the influence of mixing speed on the dehydration effect of the produced liquid of binary composite flooding crude oil, It provides a technical direction for the research of demulsification and dehydration technology of produced fluid from enhanced nitrogen foam flooding in this oilfield.

The low permeability reservoir in Jiyuan area of Ordos basin is rich in resources, but the reservoir pore structure is complex, the water injection pressure is high, the underinjection is frequent, and the pressure level is low, with an average of 70%. Therefore, the pilot test of air-thermal miscible flooding in C46 reservoir is of great significance to realize long-term stable production and improve ultimate oil recovery of ultra-low permeability reservoir in Changqing oilfield. Taking Y08-28 well group of C46 reservoir as an example, the development effect of 2 gas injection and 7 production is adopted in numerical simulation, and the key technical parameters such as daily gas injection in the process of gas injection are determined. The results show that hot air miscible flooding can effectively improve the degree of recovery compared with conventional water flooding.

Due to the complex nature of Calcium carbonate scaling mechanisms in oilfields, different experiments have yielded conflicting results. This paper aims to elucidate the molecular-level mechanism of Calcium carbonate scaling in oilfields by investigating the effects of temperature, tubing, and asphaltene. The findings of the molecular dynamics study indicate that Calcium carbonate formation tends to occur at a critical temperature. Additionally, asphaltene present in oilfields tends to enhance Calcium carbonate formation. Furthermore, the degree of Calcium carbonate scaling decreases on Fe (110) and Ni (111) surfaces, offering theoretical insights into addressing Calcium carbonate scaling in complex oilfield environments.

Due to high viscosity, strong heterogeneity and wide development of interbeds, the development of super heavy oil category III reservoir is very difficult. The main development technology SAGD is affected by interlayer and process conditions, some well groups have some problems, such as low production level of horizontal section, uneven development of steam chamber and slow lateral expansion. SAGD technology of vertical well auxiliary is to improve SAGD development effect by making use of SAGD adjacent vertical well, forming thermal connection between vertical well steam huff and puff and SAGD well group, continuous steam injection of vertical well and expansion of steam chamber scale. Vertical well assisted SAGD can improve the development of steam chamber and increase oil production rate. The selection conditions of auxiliary vertical wells are demonstrated by numerical simulation technology, and the perforation parameters, steam huff puff stage and steam drive stage of vertical wells are optimized considering the interlayer distribution. Finally, it is verified in the actual model. With the aid of vertical wells, the average daily oil production of single well group is increased by 5 t/d, the oil steam ratio is increased by 0.021, and the recovery factor is increased by 6.3%, which effectively improves the development effect. The research results provide technical support for SAGD efficient development assisted by vertical wells in class III super heavy oil reservoirs.

At present, there are many shale pyrolysis experiments based on thermogravimetric analyzers at home and abroad, which control the heating rate of pyrolysis experiments by programmed heating, but they cannot simulate the high temperature and high pressure environment of subsurface in situ transformation, so they cannot reflect the real situation of subsurface in situ pyrolysis, and there are few studies on the reaction kinetics of shale pyrolysis under water medium condition at home and abroad. In this paper, shale pyrolysis experiments under water medium condition were carried out by using a self-designed high-temperature and high-pressure reactor, comparing shale pyrolysis experiments under thermogravimetric analysis drying conditions, analyzing the characteristics and laws of shale pyrolysis under different conditions, calculating the kinetic parameters of shale pyrolysis in Longkou area by using Friedman, FWO and KAS methods, and analyzing the efficiency of shale pyrolysis under water medium condition. The activation energies of shale pyrolysis under water medium conditions were obtained by the Friedman, FWO and KAS methods with small differences of 95.68 kJ·min−1, 90.83 kJ·min−1 and 84.00 kJ·min−1, respectively; the activation energy under thermogravimetric conditions obtained by the Friedman method was 189.67 kJ·min−1, and the frequency factor was 4.54 × 1012 s−1, and the shale pyrolysis time was solved by the pyrolysis rate equation at different constant temperatures under aqueous medium conditions. The study shows that the presence of water can significantly reduce the activation energy and frequency factor of shale pyrolysis, shorten the shale pyrolysis time, effectively promote shale pyrolysis, and provide an important theoretical basis for the subsurface in situ transformation of shale.

Supercritical water (SCW) has emerged as a promising thermal agent for enhancing heavy oil recovery, yet its recovery mechanisms have not been fully understood, thereby limiting its practical application. To address this knowledge gap, this study conducted pyrolysis and sand pack flooding experiments to study the feasibility and mechanisms of SCW flooding. Subsequently, a novel simulation model dedicated to SCW flooding was developed and its accuracy was validated through fitting the experimental results. Furthermore, sensitivity studies were performed using the developed model to explore the impact of various factors on SCW flooding. The findings revealed that in SCW, the heavy oil upgrading was found to effectively reduce oil viscosity, thereby playing a pivotal role in enhancing oil recovery. Compared to steam flooding, SCW flooding led to a remarkable 14% increase in oil recovery, demonstrating its technical viability for deep heavy oil recovery. The developed numerical model, incorporating experimental data and history matching techniques, demonstrated a high level of accuracy in simulating SCW flooding. The simulation outcomes highlighted that SCW flooding induced heavy oil upgrading, consequently improving oil mobility. Additionally, it was observed that higher SCW pressures and temperatures positively impacted its production performance. However, it is important to note that excessive temperature elevation could result in significant coke deposition, potentially causing damage to the reservoir formation.

The large-dip-angle (>10º) region accounts for a large proportion of the steam flooding test area in Qi40 block of Liaohe oilfield. As this area has entered the late stage of development, the production continues to decline and production cost continues to rise. Optimization study on the steam flooding follow-up development scheme in the typical high dip angle well group in Qi40 block was carried out. Four typical well groups in Qi40 block were chosen as the research target, the 3-D geologic model was constructed by Petrel and the numerical analysis model was built by CMG-STARS. Simulation results indicate that the producing degree of Lian I oil layer is high; while the producing degree of Lian II is low, with a remaining oil saturation of over 0.6, and there is little distribution difference in the high and low structural parts. Based on the characteristics of remaining oil saturation distribution in Lian I and Lian II oil layers, the stratified steam injection technology can be considered at the late production stage. Simulation result indicates the oil recovery can be enhanced by 4% with this method. In addition, the optimization on steam flooding follow-up development technologies in large dip reservoir indicate that the oil recovery can be enhanced by 5.2%, the maximum degree, with the intermittent steam flooding; secondly 4.6% with continuous steam flooding; and a relative small range with hot water flooding or steam and air compound flooding. The intermittent steam flooding has a higher Lian I producing degree than the continuous steam flooding, and a higher oil-steam ratio than the steam air compound flooding and the steam-water alternate flooding. Comprehensively, the intermittent steam flooding technology is recommended as the follow-up process to produce the large dip reservoir after steam flooding.

Productivity prediction and fracturing impact evaluation are problematic by traditional methods because of the huge differential productivity and the number of horizontal fracturing sections in shale oil wells. The path to effective shale reservoir development is to build a reliable and efficient intelligent productivity prediction method using machine learning. The geological data, fracturing data, and production database of 91 production wells in the Jimsar shale reservoir were used as data sources in this study. The vector-based feature recursive elimination method is used to screen and reduce the dimension and cross-validation of the data, and determine 5 optimal main control factors covering geological factors and construction factors from 15 characteristic parameters. Root mean square error was used to assess the model performance. The learning decision trees, random forests, and gradient boosting models (GBDT) of three tree regression methods—were utilized to predict productivity. The results show that the single storage coefficient, cluster spacing, reconstruction volume, sand volume, and fracturing section length are the primary governing elements impacting the productivity of fractured horizontal wells. In the three regression machine learning models, the random forest algorithm using self-sampling solves the over-fitting problem of other tree models, which is superior to the decision tree model and GBDT model in the tree model. It has the best prediction effect, with a test set root mean square error of 0.934.

The huff-n-puff gas injection is more advantageous than water flooding in the development of shale oil reservoirs with micro-nano pores. In particular, the phase state of fluid components confined by nanopores cannot be ignored. In this paper, we built a single well mechanism model in the study area, it combined with the geological and fluid parameters of the Jimsar Sag shale oil reservoirs. In this model, we introduced a modified Peng-Robinson equation of state in nanopores. Through component numerical simulation, we studied the effects of some parameters on enhanced oil recovery by the huff-n-puff gas injection, including reservoir parameters (reservoir thickness, pore radius, matrix permeability), and hydraulic fracturing parameters (fracture number, fracture half length, fracture conductivity). And we carried out parameter sensitivity analysis. The results show that the crude oil phase diagram studied by the modified phase equation shows obvious shrinkage, which is due to the influence of nanopores. The corresponding minimum miscibility pressure of huff-n-puff gas injection is smaller, and it is easier to miscibility than huff-n-puff gas injection in conventional reservoirs. The sensitivity of recovery after huff-n-puff gas injection is analyzed by compositional numerical simulation. The results show that the sensitivity of fracture conductivity is strong. The second is reservoir thickness, matrix permeability, pore radius, fracture half length, and fracture number. The recovery is positively correlated with pore radius, matrix permeability, fracture number, and fracture half length. And it is negatively correlated with reservoir thickness.

In the development of heavy oil reservoirs employing vertical-horizontal well steam driving (VHSD), there are various issues like a significant reservoir deficit and a poor oil-steam ratio. A novel 3D physical experimental model was developed to carry out the entire process simulation experiment of nitrogen-assisted VHSD to better understand the characteristics and mechanism of nitrogen-assisted VHSD. The production characteristics, oil displacement efficiency, and steam chamber evolution of nitrogen-assisted VHSD were analyzed. The findings indicate that the vertical and horizontal wells' oil recovery declines as the number of cycles rises and that steam sweep efficiency is low. Based on the liquid production dynamics and the propagation of the steam chamber, the nitrogen-assisted VHSD process is divided into three stages: expansion laterally, downward expansion after fusion, and steam chamber breakthrough. In the first stage, the injected nitrogen and steam accumulated at the top of the reservoir and expanded laterally, with a stage recovery of 27.53%. The steam chamber gradually merged and grew downward in the second stage. At this stage, the oil production rate was stable, and the stage recovery was 24.68%. When the steam chamber entered the horizontal well in the third stage, the rate of oil production gradually declined, and the stage recovery was only 2.11%. The research provides important references for nitrogen-assisted VHSD field tests in heavy oil reservoirs.

In the early stage of general water injection and high-speed development of overseas sandstone oil fields, when the water cut is 98.5% and the degree of geological reserve recovery reached 52%, the degree of vertical utilization of oil fields is only about 60%. Through the profile adjustment of water injection wells, it has become an inevitable choice to improve the degree of longitudinal utilization of oil fields. In order to select profile control agents suitable for oil fields, profile control experiments on polymers, emulsions, self-assembled microspheres and gels are carried out. During the injection of the polymer profile regulating agent, the recovery rate has hardly increased, indicating that the polymer solution is transported in the raw water flooding site (or channel) with low saturation of the residual oil, and rarely contacts and repels the residual oil; because the gel formation is very sensitive to temperature and is limited by the underground glue formation time, the gel profile control system is difficult to apply on site; the dispersion system (emulsion and microspheres) profile control agent can partially enter the micro- and macroscopic local crude oil enrichment areas, which play a role in repelling the residual oil and the remaining oil, and the profile control effect is good. This shows that compared with other profile control agents, dispersion systems such as microspheres and emulsions are more suitable for deep profile control of reservoirs where residual oil and residual oil are highly dispersed.

The abundant natural fractures in shale gas reservoirs are not only beneficial to improve the productivity of gas wells, but also increase the probability of frac hits between infill wells and parent wells, Which reduces gas well production and restricts the efficient development of shale gas. Aiming at the problem of frac hits existing in fractured shale gas reservoirs in WY area, this paper firstly introduces the common shale frac hits channel identification method. Based on the study of block production dynamics and fracture development, maximum likelihood chart method is used as the primary method for qualitative identification of fracture channeling, and the criterion for the type of frac hits channel is established. Combined with five correlation analysis methods, the main geological engineering key factors of fracture - dominated frac hits channel are determined, so as to explore the corresponding feasible frac hit prevention countermeasures. The research shows that the distribution and development of natural fractures are very important to the production after frac hits. Among them, the approach angle, the fracture linear density on the frac hits path and the horizontal in-situ stress difference are the main factors of natural fracture - dominated frac hits. The net pressure in fracture, horizontal stress difference and liquid strength are the main influencing factors of hydraulic fracture - dominated frac hits. By changing the amplitude of the corresponding key parameters, it is found that the activation difficulty coefficient of natural fractures fluctuates from −35.1% to 47.6%. The length of the hydraulic fracture fluctuates from −43.5% to 25.29%. Based on the two types of frac hits, the corresponding frac hits prevention countermeasures are proposed from different directions such as fracture risk assessment and path planning, production well pressurization and stress steering, and infill well fracturing parameter optimization. This paper not only provides a reference for exploring the formation mechanism of inter-well pressure channeling in fractured shale gas reservoirs, but also provides a theoretical basis for frac hits prevention countermeasures.

With the deepening of the understanding of polymer flooding development, the injection allocation design of single well polymer flooding is very important. At present, there are few studies on the rational injection allocation method in the early stage of various reservoir polymer flooding, and the calculation method of injection allocation during water flooding development is still used. Field application shows that the method only considers geological factors, and does not consider the influence of inaccessible pore volume, system resistance coefficient and injection velocity on expanding swept volume and improving oil displacement efficiency. Therefore, the design results have little guiding significance for the development of polymer flooding stage, and a series of problems such as plane, interlayer and intra layer contradictions and injection-production imbalance are soon exposed. In this paper, the inadaptability of the previous injection method is analyzed, and the influence of geological conditions, resistance coefficient of injection system, inaccessible pore volume and injection velocity on injection in single well of rational polymer flooding is studied. Through the study of theory and practice, the injection distribution method suitable for the polymer flooding in Lamadian oilfield is determined to improve the expanded swept volume and oil displacement efficiency of various reservoir polymer flooding, so as to enhance the recovery efficiency.

According to the characteristics of Low and extra-low permeability reservoirs in an oilfield, the crude oil in the oilfield was used as the experimental oil, and the deionized water was used as the experimental simulated water. The oil displacement performance of VES (viscoelastic) surfactant oil displacement agent and nano-sized oil displacement agent was evaluated by indoor core simulation oil displacement experiment. The results show that the two oil displacement agents have good oil displacement under low permeability conditions, and the recovery rate is higher than 8.97%. At the same concentration, in the agent displacement stage, the VES oil displacement agent has better oil displacement effect. The reason is that the ultra-low interfacial tension of betaine and the solubilization of micelles to oil can improve the oil displacement efficiency to a certain extent. In the imbibition stage, the nano-sized oil displacement agent has better oil displacement effect. The reason is that the nanoparticles optimize the viscoelasticity of betaine, further reduce the oil-water interfacial tension, enhance the deformation ability of oil droplets, and make the capillary imbibition and oil discharge stronger. Considering various factors, VES surfactant oil displacement agent has better oil displacement effect in the displacement stage, while nano-sized oil displacement agent has better oil displacement effect in the imbibition stage. The research in this paper provides technical support for the optimization of imbibition oil displacement agent in the development of Low and extra-low permeability reservoirs.

The K Oilfield has been in development for 30 years, and at present, the Oilfield has entered the stage of ultra-high water cut stage. In view of the unclear understanding of the residual oil distribution and the difficulty of relying only on conventional adjustment of potential mining methods to improve the development effect, through the in-depth analysis of the well network status, flooding status and existing problems of K oilfield, it is confirmed that although high water cut at the well, but the characteristics of longitudinal use and surplus oil enrichment between wells. Combined with numerical simulation the feasibility of stratigraphic interchange is demonstrated. Through the research of interchanging well pattern, changing the direction of fluid flow, increasing the ripple volume, and the direction of fluid flow is changed through stratigraphic well network interchange, it is found that the oil recovery speed can be more than doubled by carrying out interchanging well pattern, and the effect of no plugging in the original layer is better than the effect of plugging. The average daily oil production of a single well increased by 3.5 t after the layer-system swap in the ploy test, and the technology has been promoted on a large scale in K oilfield.

Reservoir wettability is an important factor affecting the degree of crude oil recovery, and achieving wetting inversion on the rock wall is beneficial for subsequent water drive to improve recovery. In this paper, the ability of five cationic surfactants to change the reservoir wettability was evaluated for the specific reservoir physical conditions in the Shengli oilfield, and the optimal wettability reversal system from hydrophilic to oleophilic was constructed using the oil-water-solid three-phase contact angle as an indicator. On this basis, the influence of the wetting inversion system on the recovery enhancement of the subsequent water drive was quantitatively described by sand-filling physical simulation experiments. The experimental results show that the subsequent water drive again shows a significant pressure peak, and the pressure drop rate after the injection water breakthrough is significantly smaller than that of the primary water drive. In addition, the recovery rate of the secondary water drive increased by 24.6%, which had a significant oil enhancement effect. The study provides theoretical guidance for the effective development of sandstone reservoirs and similar types of reservoirs in Shengli Oilfield.

A fault block in Gaoshangpu of Jidong Oilfield is a heavy oil reservoir with edge and bottom water. The water body has sufficient energy, and the whole is in the stage of ultra-high water cut development. After several rounds of CO2 huff and puff, the remaining oil is highly dispersed, and it is difficult to tap the potential by conventional technical means. By analyzing the implementation effect of CO2 huff and puff in the fault block, it is clear that the injection volume of CO2 huff and puff and the average remaining oil saturation in the production well control well area are the main controlling factors affecting the huff and puff effect, and the CO2 differential huff and puff technology under different remaining oil saturation conditions in heavy oil reservoirs is proposed. Through laboratory experiments, this technology clarifies the four mechanisms of viscosity reduction, expansion, dissolved gas flooding and extraction of CO2 injection to improve heavy oil recovery. Through the numerical simulation method, four differential design charts of throughput injection volume, round-by-round increase ratio of gas injection volume, throughput rounds and liquid production speed under different saturation conditions were optimized. During the implementation of the field, through the analysis of oil well production characteristics and numerical simulation calculation, the remaining oil saturation of different well areas in the reservoir is clarified. Using the differential design chart, the injection and production parameters of huff and puff wells under different remaining oil saturation conditions are calculated. The design of 88 wells of CO2 differential huff and puff in the heavy oil reservoir of the fault block is guided. The average daily oil production of single well is 6.0 tons, and the cumulative oil production is 45,000 tons, which effectively guides the same type of reservoir to further improve the huff and puff effect.

In response to the complex seepage mechanism of unconventional oil and gas reservoirs, large-scale volume fracturing of multi-segment and multi-cluster horizontal wells, and differences in oil and gas pressure and saturation properties, which result in uneven distribution of eigenvalues, large value of conditions, and slow solving speed of nonlinear equation matrix, a multi-stage decoupling preconditioning solution technology was carried out on the Jacobian coefficient matrix of the oil and gas numerical discrete equation based on the implicit pressure explicit saturation method (IMPES) processing idea. Multi-grid method (AMG) + block based incomplete LU decomposition method (BILU0) are used to preprocess the Jacobian coefficient matrix in multiple stages, and the block based generalized minimum residual method (BGMRES) is used to solve the preconditioned nonlinear algebraic equations. The calculation result proves that compared with other single processing methods, this method effectively reduces the number of iterations for solving discrete equations while ensuring calculation accuracy, improves calculation speed, and has important application value for rapid formulation and decision-making optimization of oil and gas field development plans.

The rapid development of the economy has resulted in an increase in our demand for petroleum resources. Organic-rich shale has received extensive attention both at home and abroad due to its enormous development potential. This article used a high-temperature and high-pressure reactor to conduct 2 h pyrolysis experiments on Longkou organic rich shale core samples in N2 atmosphere at temperatures of 385 ℃, 405 ℃, 425 ℃, and 450 ℃, respectively, to study the characteristics of oil and gas products from organic-rich shale pyrolysis at different temperatures. The results show that the CH4 and C2–C5 alkanes in pyrolysis gas increase with the increase of pyrolysis temperature, which is conducive to the pyrolysis transformation of organic matter in organic-rich shale. As the pyrolysis temperature increases, the relative content of CO2 increased first and then decreased, and the relative content of H2 increased gradually. With the increase of pyrolysis temperature, the content of heavy components in shale oil decreases, while the content of light components increases, and the quality of shale oil becomes lighter. Controlling appropriate pyrolysis temperature can effectively change the composition of shale oil products and the distribution of hydrocarbon components, so as to achieve the goal of controlling the output of target products. By analyzing the pyrolysis products of shale at different temperatures, the distribution of pyrolysis products of organic-rich shale under N2 condition is clear, which is of great significance to guide the in-situ development of organic-rich shale.

Polymer gels are commonly used as profile control and water shutoff agents in oil fields to enhance oil recovery. In this study, two sets of medium-temperature and high-salinity gels were prepared with partially hydrolyzed polyacrylamide (HPAM) as the gel-forming agent, melamine resin (MR) or water-soluble phenolic resin (WSPR) as the crosslinker and nano-silica as the stabilizer, and their gelation time, strength and thermal stability were comprehensively evaluated under 90 ℃ and 41529 mg/L synthetic formation brine. The results showed that the gelation time of HPAM-MR gel and HPAM-WSPR gel was in the range of 3–118 h and 12–25 h, respectively. The two gels were in the high-strength gel class (storage modulus over 10 Pa). The thermal stability of the two gels differed considerably. The HPAM-MR gel showed a dehydration rate of 4% when aged for 45 days. While over half of the HPAM-MR gel exhibited severe syneresis after 90 days of aging, especially for the formulations with low polymer dosage and/or low crosslinker loading, the dehydration rate of which was up to 90%. In contrast, the HPAM-WSPR gel exhibited extremely excellent thermal stability, with a 3% dehydration rate after 90 days of aging and more than half of the formulations showed no water extruded when aged for 210 days. This study can provide exceptional gel-plugging agents for medium-temperature and high-salinity reservoirs and guidance for the screening of crosslinkers for gel-plugging agents.

The efficiency of different CO2 injection methods on oil recovery in tight oil reservoirs exhibits substantial variation. This investigation focuses on the Chang 6 Member of the Yanchang Formation, situated in the Ordos Basin, as the research subject. Two injection techniques, namely continuous CO2 flooding and CO2 huff-n-puff after flooding, were employed to scrutinize the microscopic production traits of oil. Five tight sandstones with comparable physical characteristics were selected for the study. A physical simulation flooding system was utilized to perform continuous CO2 flooding and CO2 huff-n-puff after flooding experiments at five pressures ranging from 4 MPa to 20 MPa. The NMR technology was employed to analyze the T2 spectrum of the cores before and after the experiment to quantify the micro production traits of oil at different pore scales. The experimental findings revealed that the oil recovery of the total pore increased progressively with flooding pressure during the flooding process. The highest recovery rate of 75.29% was observed during 20 MPa CO2 flooding. While the utilization degree of oil with large pores remained the highest, the contribution of oil decreased gradually. During the CO2 huff-n-puff after flooding under immiscible conditions, the increase in CO2 huff-n-puff recovery in macropores was the highest, up to 10.35%. The highest increase in oil utilization of small pores was 15.26% after miscibility, suggesting that oil in large pores was the primary contributor during the immiscible phases. After miscibility, oil in the small pores became the primary contributor. This investigation analyzes the influence of CO2 flooding and CO2 huff-n-puff after flooding injection methods on the micro pore oil production traits of tight sandstone reservoirs. The findings provide novel theoretical support for future field tests of CO2 flooding and CO2 huff-n-puff after flooding.

Biopolymer flooding is one of the most recently developed technologies to enhance oil recovery (EOR). A novel exopolysaccharide named WL is produced by members of the genus Sphingomonas sp. WG. WL was mixed with a nonionic surfactant (BE1). The FTIR measurements of the mixture were systematically investigated. Moreover, the rheological properties of WL-BE1 were observed to be maintained under high temperature and high salinity conditions. This paper compared the enhanced oil recovery with WL and WL-BE1. The test showed: the two inflection points on the surface tension curve indicated intermolecular interactions between WL and BE1. The combination of WL and BE1 resulted in the formation of networks in the solution through electrostatic and hydrogen bonding interactions. Additionally, the mixture maintains stable rheological properties even under high-temperature and high-salinity conditions. The mixtures of WL-BE1 system could enhance the oil displacement efficiencies by 24.73%, respectively. It has been proven that the combination of exopolysaccharides with surfactants can enhance the process of oil recovery through their synergistic effects.

Profile control is the main measurement to solve water channeling in fractured reservoir development. Facing the difficulties in evaluating and optimizing of profile control in fractured reservoir and from the perspective of fine reservoir simulation and effectiveness evaluation, a series of research was carried out. The problems of the water channeling and profile controlling of an offshore fractured reservoir were figured out. Experimental research on gel sealing of fractures was conducted, and a dual medium reservoir dynamic model for profile control was established based on the lab results and the seepage mechanism of the gel sealing formation. The comprehensive reservoir model was used to simulate and evaluate the profile control effect of the plugging agent on both reservoir formation and production performance, as well as to optimize the profile control parameters. Then, the results indicate that the plugging agent mainly acts on the fractures, significantly increasing the residual resistance coefficient through adsorption and plugging. Also, the matrix has a viscous effect on the plugging agent. The water absorption profile and water drive path are improved via plugging agent effect on matrix and fractures, gradually from protruding along fractures to uniformly flooding along the matrix and fractures, ultimately increasing the water injection sweep efficiency. Meanwhile, the production improvement is reflected on the above reservoir change by plugging. During the validity period, the water breakthrough time delays, with the dropped water cut, increased oil production and matrix reserves output, and the weakened fracture characteristics. After the validity, the effect may deteriorate, which is a guidance for multiple rounds of profile control. Finally, three key parameters for profile control are optimized. It is recommended to place the slug within a distance of 0.3 times of the well spacing. The amount of plugging agent should be considered economically, taking into account of both cumulative oil increment and oil increment per unit plugging agent. The timing of profile control to seal high permeability fractures is recommended to be as early as possible. The study establishes the relationship of plugging agents with both fractured reservoir formation and production performance with a dual medium reservoir model based on experiments and theories of profile control, which is of certain significance for scientific and comprehensive evaluation of the profile control effect in a fractured reservoir, and also provides guidance for parameters optimization such as slug position, plugging agent dosage, and the timing.

During the development process of carbonate rock bottom water gas reservoirs, bottom water is prone to water channeling along the high permeability channels of fractures and caves, resulting in relatively high water production after water breakthrough in gas wells. However, traditional methods for calculating the critical liquid carrying capacity of gas wells have limitations in calculating the liquid carrying capacity of gas wells and the unsteady flow of gas-water two-phase flow when the water production is high. The calculation results have significant errors, making it difficult to guide the formulation of waterproof and water control measures for carbonate bottom water gas reservoirs. Therefore, by introducing computational fluid dynamics (CFD) simulation technology, this paper has realized the numerical simulation calculation of gas water two-phase unsteady flow in directional wells (horizontal wells and highly deviated wells) under different formation inflow boundary strips, visualized and quantitatively analyzed the change law of gas water two-phase flow pattern in directional wells under different production conditions and the liquid carrying production capacity of gas wells, and mastered the inhibitory effect of gas well water production on gas production, Solved the suitability of directional well waterproofing and water control, as well as the optimization design of well trajectory, providing a new technical means for water control and development of carbonate rock bottom water gas reservoirs.

Fluvial-facies reservoirs in Bohai Oilfield are widely distributed, and the proportion of positive rhythm reservoirs with strong reservoir heterogeneity is high. To address the problems of poor quality at the top of the positive rhythm formation and low recovery rate due to water flooding at the bottom, this paper uses numerical simulation to establish a mechanistic model to compare different schemes of horizontal well deployment in a single layer of positive rhythm reservoir. Also it compares the advantages and disadvantages of different deployment schemes, optimizes the deployment limits of horizontal wells in positive rhythm sandstone reservoirs, and verifies the results using the existing field horizontal wells. The optimal longitudinal deployment location of horizontal wells during the high water cut development stage of the fluvial-facies reservoir is obtained.

During the development process of oil and gas fields, drilling, completion, and production operations can pollute and block the oil and gas channels of formation, reducing the production capacity of production wells; Low permeability reservoirs developed by water injection have the phenomenon of insufficient injection due to poor permeability. On the basis of traditional liquid electric effect and metal wire electric explosion unblocking technology, assisted by energetic materials, a repeated shaped energy shock wave technology is formed, which combines high-power electric pulse with discharge plasma to convert electrical and chemical energy into shock wave mechanical energy. Through repeated operation of the pulse power source, repeated shock waves are generated in the wellbore, the action times and peak pressure of which can be designed according to the reservoir permeability and plugging degree, chiving reservoir permeability enhancement and unblocking while ensuring wellbore integrity. This article introduces the generation mechanism, influencing factors, indoor and on-site tests of shaped charge shock waves. Through indoor experiments, it has been proven that shock waves have effectively unblocked the perforation hole with cement sealing without damage to the simulated casing and cement sheath. Through on-site experiments, the feasibility of increasing permeability and unblocking technology has been verified by comparing water injection volume and production well liquid rate before and after unblocking. The results show that the combination of electric explosion plasma and energetic materials can produce stronger controllable shock waves and improve the permeability increasing and plugging removal effect, which is of great significance in oil development.

Temporary plugging fracturing technology is an effective method to improve the extent of the fracture stimulation of horizontal wells, which could effectively improve the degree of inter-fracture mobility in low permeability reservoirs. At present, research on temporary plug frac for horizontal wells mainly focuses on the development of fractures, lacking optimization analysis for different parameters. Based on the reservoir parameters of the Chenghai block, this paper established a numerical model for temporary plugging fracturing of horizontal wells, which considered the non-uniformity of natural fractures and reservoir permeabilities. The model simulated the developing behavior of temporary plugging for inter-fractures and intra-fractures. A “fracture coverage area” concept was introduced to investigate the influence of parameters such as two-way stress difference, discharge, and cluster spacing. A generally used simulation method for temporary plugging fracturing of horizontal wells in heterogeneous reservoirs was formed. The conditions for implementing temporary plug frac were clarified and the key parameters were optimized. The study results showed that when the two-way stress difference is less than 4 MPa, temporary plugging of the opened natural fractures can be implemented to promote the expansion of the main fractures; and when the two-way stress difference is greater than or equal to 4 MPa, the main fractures can be temporarily plugged after the main fractures have expanded, promoting the initiation of natural fractures and guiding the main fractures to change direction. Therefore, 4 MPa is recommended as the critical two-way stress difference for implementing temporary plugging fracturing. As the discharge rate increases, the length and width of the fractures gradually increase, and the fracture coverage area reaches its maximum value when the discharge rate is 5–8 m3/min. When the inter-cluster spacing is less than or equal to 12 m, temporary plugging can significantly extend the fractures that have not been effectively expanded. The fracture coverage area is the largest when the inter-fracture spacing is 5–8 m. This numerical simulation method for temporary plugging fracturing of horizontal wells can provide guidance for optimizing construction parameters on site and effectively improve the effect of temporary plugging fracturing.

The injection and production characteristics during the construction and operation of underground gas storage are periodic injection of gas into sealed geological bodies, followed by regular extraction. Underground gas storage has injection production characteristics and displacement mechanisms such as advanced energy replenishment, periodic injection production, gravity displacement, oil gas mixing, large PV displacement, and nano dispersion. The injection production characteristics and displacement mechanism advantages of underground gas storage help to improve oil displacement efficiency, expand sweep coefficient, and increase diversion capacity.Self drive development to improve oil recovery is a one well self drive development mode that can supplement energy, strengthen activation, make full use of the spontaneous displacement force of underground rock fluid, and achieve the integration of injection and production of Injection well and production well. According to the dominant factors of different spontaneous displacement forces, self drive can be divided into two types: fracturing type inter fracture self drive and throughput type dredging self drive. The underground gas storage is a self driving drainage system with a throughput type.Both underground gas storage and self driving development to improve oil recovery require geological body sealing evaluation. This article first addresses the challenges of evaluating geological body gas tightness and its dynamic sealing, inventing a fault dynamic sealing evaluation method, and innovating the four-dimensional geomechanical modeling technology for cover layer tensile failure and shear deformation, enhancing the scientific nature of dynamic sealing evaluation of faults and cover layers. Quantitatively determining the risk index of caprock, fault, and wellbore under alternating load stress conditions has achieved quantitative evaluation of the dynamic sealing performance of the “three in one” gas storage. Secondly, in response to the complex mechanism of natural gas oil displacement collaborative reservoir construction and the low efficiency of underground gas storage space expansion, through indoor experimental research and field experiments, the multi-scale collaborative displacement mechanism of “nanometer to kilometer level” has been revealed. A new method for efficient oil displacement collaborative reservoir expansion has been invented, and a three-stage collaborative reservoir construction model of “gas injection extraction+throughput expansion+capacity and production” has been established.The collaborative method of underground gas storage and self driving for enhanced oil recovery has supported the industrial testing of new gas storage reservoirs such as Tarim Donghe 1 and Jidongdongbao 1–29. The Liaohe Shuang-6 gas storage reservoirs have significant drainage and expansion effects during the gas injection period, forming three major oil reservoir type gas storage groups in Northeast, North China, and Northwest China, with a storage capacity of 10.1 billion cubic meters and a central well group crude oil recovery rate of over 70%.

Underground rocks and their fluids contain various spontaneous displacement forces under high-temperature and high-pressure conditions, such as elastic forces, capillary forces, buoyancy and sinking forces, viscous forces, etc. The mechanism of spontaneous displacement force is very beautiful, and in different application scenarios or conditions, it is sometimes resistance, sometimes power, sometimes side force, and sometimes positive force. Revealing the mechanism of spontaneous displacement force, evaluating the magnitude of these spontaneous displacement forces, and constructing application scenario models that can exert the positive effect of spontaneous displacement force based on their respective mechanisms are of great significance for the construction of oil and gas reservoir engineering. The author conducted a systematic evaluation of the spontaneous displacement forces such as elastic force, capillary force, buoyancy and subsidence force, and viscous force caused by the coupling between rocks and oil, gas, and water fluids in oil and gas reservoirs and saline water layers through reservoir engineering methods and indoor experimental testing methods. The author established a single well self drive development method that achieves the integration of injection and production wells through energy replenishment, enhanced activation, and full utilization of the spontaneous displacement force of underground rock fluids, And two methods, namely fracturing type inter fracture self drive and throughput type dredging self drive, were proposed under the dominance of different spontaneous displacement forces. These two methods are effective methods to solve intra layer contradictions and realize intra layer separate injection. Good field results have been achieved in tapping remaining oil in highly heterogeneous reservoirs in low permeability tight reservoirs, high fault ridge reservoirs, micro structural reservoirs, fracture cavity reservoirs, etc. On site verification shows that self driving technology can significantly increase production and recovery efficiency, and reduce the number of injection wells, injection volume, and carbon emissions.

During the production of shale oil and gas, the interaction between carbon dioxide and shale will have a significant impact on the rock properties. Using brazilian splitting experiments and uniaxial compression experiments, the mechanical properties of shale samples subjected to supercritical carbon dioxide (SC-CO2) at different temperatures were investigated in this study. The results of this study indicate that the tensile and compressive strengths of shale decrease gradually after exposure to SC-CO2, and the higher the temperature at which SC-CO2 acts, the greater the decline in strength. The mode of shale failure has shifted from a single tension failure to a mixed tension shear failure. Shale samples have a critical damage threshold temperature of 350 ℃, and the SC-CO2 effect significantly reduces shale strength. This is related to the alteration of the rock internal structure during the high temperature shale formation process, and it is also the underlying cause of the deterioration of the shale mechanical properties. The failure mechanism and fracture mode of the rock are largely determined by its mechanical properties. The study findings have significant theoretical value and a number of practical applications in the area of shale oil and gas reservoir engineering.

Aiming at the problems of low proppant-carrying capacity and low fracture conductivity of slick water fracturing fluid, a novel fracturing fluid based on Pickering emulsion was fabricated, which was expected to stabilize and support fractures through the interaction between particles in the emulsion and shale wall surface, so as to improve the fracture conductivity. The rheological, anti-swelling, and filtration properties of the Pickering emulsion as the fracturing fluid were examined. The ability of Pickering emulsion to generate fractures and support them was investigated using the rock mechanics triaxial experimental apparatus. The findings demonstrated that Pickering emulsion had high stability and temperature resistance. The filtration rate of Pickering emulsion is much lower than that of slick water fracturing fluid and guar gum fracturing fluid. The Jamin effect made it difficult for emulsion droplets to through the pore throat, and the pressure-induced formation of filter cakes on the core surface further decreased the rate of filtration. Pickering emulsion had some anti-swelling properties and 20–40% slower expansion rate than slick water fracturing fluid. Pickering emulsion fracturing fluid, on the other hand, has a greater capacity for producing fractures. The shale wall can hold and adsorb the solid particles in the emulsion, which to some extent improved the conductivity of fractures. Pickering emulsion fracturing fluid solves the low viscosity and fracture support issues of slick water fracturing fluid, making it a good candidate for use in hydraulic fracturing for shale gas.

Horizontal well is one of the main well types for oil production. Multi-stage fracturing of horizontal well has become the most effective means of exploiting tight oil reservoirs. How to further improve the stimulation effect of horizontal well fracturing has become the main challenge in oil and gas engineering. In this paper, the 21st tight oil Block of Ordos Basin Oilfield is taken as the research object to solve this problem, carries out the investigation of the geological conditions and seepage characteristics of the study area, a single well numerical model of multi-stage fractured horizontal well is established, and the effects of permeability, fracture length, conductivity, fracture spacing and distribution on oil well productivity are analyzed. The average reservoir thickness in the well area is 12 m, the average porosity is 0.22, the wellbore radius is 11.4 cm, and the effective average permeability is 0.083 mD. The reservoir is a typical reservoir with low porosity and permeability, with strong heterogeneity and sensitivity, and there are natural fractures in the reservoir; using the Eclipse numerical simulation software and the five-point method, the fracture seepage is divided into four stages: fracture linear flow stage, vertical radial flow stage, composite linear flow stage and quasi-radial flow stage. In the stage of staged fracturing of horizontal wells, with the increase of permeability, the production growth rate first rises and then decreases; with the increase of the fracture half-length, the production capacity of horizontal well staged fracturing showed a uniform increase, but the increase in production capacity basically remained unchanged; In the stage of staged fracturing of horizontal wells, with the increase of permeability, the production growth rate first rises and then decreases; when the total half-length of fractures is constant, The main fractures of the horizontal well gradually increase, and the total output of the staged fracturing of the horizontal well will gradually increase. The larger the value, the greater the contribution to the fracturing productivity of the horizontal well. The research results provide theoretical data support for improving the recovery of tight oil reservoirs.

Refracturing is affected by the reorientation and change of the in-situ stress field caused by pre-existing hydraulic fractures and well production. However, the comprehensive influence of primary fracturing, water injection, and well production in vertical wells on the redistribution of the in-situ stress field is not well understood. To investigate the above problems, an integrated simulation procedure with a 4D geomechanical model is conducted to accurately describe pressure distribution and to update stress states, which couples the primary fracturing, well production, refracturing, and post-production. This work analyzes the changes in the in-situ stresses induced by hydraulic fracturing, reservoir depletion, water injection, and soaking. The results show that the variation of the in-situ stresses is different concerning the location of fractures. Hydraulic fracturing increases the three-dimensional principal stress in the fracture area, while the minimum horizontal principal stress increases more and the horizontal stress difference decreases. In contrast, the stress in the matrix region farther from the fracture decreases, the minimum horizontal principal stress decreases more, and the horizontal stress difference increases. The refracturing of vertical wells needs mainly considering the stress change in the fracture area. However, the increase in fluid injection volume does not necessarily improve fracturing efficiency. The horizontal principal stresses increase with liquid injection. Simultaneously, the stress contrast increases at the initial fracture location, and stress reversal occurs in the vertical fracture direction after first fracturing. The refracturing fracture may propagate to the stress redistribution area by changing the orientation of the perforation. Through the integrated simulation, the effects of different water injection rates, primary hydraulic fracturing, and well production on the change of the in-situ stress are clarified, which provides insights for the design and evaluation of refracturing for vertical wells in tight oil reservoirs.

The large volume of injected water flowed along the high permeability zone, which led to serious problems in the middle and late stages of flood development in ultra-low permeability fractured reservoirs. In this paper, we developed a novel gel-foam plug by using silica gel as a liquid phase dispersing medium for foam, evaluated and optimized the foaming and gelation performance of the gel-reinforced foam system. The gas-to-liquid ratio, injection volume, injection concentration, injection speed, and injection mode of the plugging agent were optimized by core-flooding experiments, and oilfield tests were conducted in oil fields. The plugging agent was formulated as follows: 5% sodium silicate +0.15% activator +0.2% delayed activator +0.6% foaming agent. The strength of the gel-reinforced foam system was 21702 mPa·s and the gelation time was 40 h, with the foaming volume of 869 mL and a foaming half-life of 960 s. The laboratory test results showed that the optimal gas-liquid ratio was 3:1, injection volume was 0.2 PV, injection concentration was 900 mg/L, injection speed was 0.04 PV/a, and injection method was four-slug injection in ultra-low permeability fractured reservoir. The water cut was reduced by 12.69%, the valid period was more than 8 months, and the cumulative oil increase volume was 173.98 t. The novel gel-foam developed in this paper was a new option for water treatment in this type of reservoir.

Jurassic reservoirs in Ordos are typical low permeability reservoirs. After years of waterflooding development, most of them have entered the middle and high water cut stage, and the comprehensive water cut has reached more than 66%, but the recovery degree is less than 30%. Compared with other compound flooding test areas of petrochina, it is difficult to carry out alkali-free compound flooding in Jurassic low permeability reservoirs in Changqing because of low permeability, strong heterogeneity, and higher salinity of formation water and injection water. Therefore, it is necessary to carry out injection experiments of polymer with different molecular weights to establish an injection chart suitable for Changqing oilfield. By using numerical simulation method, the main controlling factors that affect the combined flooding effect are injection/production ratio and polymer adsorption capacity. Field tests show that the effective laws of chemical flooding in low permeability reservoirs are different from those in medium and high permeability reservoirs. The analysis shows that the key factors to enhance oil recovery by chemical flooding in low permeability reservoirs are to keep the chemical injection continuously, to adjust the injection well and to maintain the reasonable formation pressure.

In order to explore the change of pore structure during the development of matrix and laminated reservoirs and to determine the factors affecting the reservoir physical properties on the recovery factor. On the basis of the pore pressure rise experiment and the pore pressure drop experiment, the core porosity change was quantitatively characterized by the nuclear magnetic resonance T2 spectrum testing technology, and the dynamic change process of shale pore structure and the influencing factors of shale oil elastic recovery were studied. The results show that when the pore pressure increases from 4 MPa to 20 MPa, the porosity increases to 127% –154% of that of 4 MPa, and when the pore pressure decreases from 20 MPa to 4 MPa, the porosity decreases to 62% –84% of that of 20 MPa, indicating that the reservoir stress sensitivity is strong. In the process of reservoir development, fluid flows in shale pores are complicated, and there are mutual flows between large pores, small pores and small pores. When pore pressure decreases from 20 MPa to 8 MPa, the elastic recovery factor of core is 11.55%  –22.04%. For the laminated core, the boundary constraint on the fluid is reduced due to the existence of fractures, and the seepage capacity of the core is enhanced, which is manifested as low starting pressure gradient, high permeability, strong seepage capacity and high elastic recovery. This study reveals the dynamic changes of pores in the shale development process, which helps decision-makers to understand the influence factors of permeability and starting pressure gradient on the elastic recovery factor, and provides a reference for the formulation of reasonable development technology.

The organic-inorganic composite cross-linking technology can effectively improve the temperature resistance of polyacrylamide gel systems. However, the effect of adding montmorillonite to the system and its impact on performance has not been studied. By using visual code method, differential scanning calorimetry (DSC), and other methods, the effects of montmorillonite on the temperature resistance, gelation properties, and microstructure of the organic-inorganic composite cross-linking polyacrylamide gel system were investigated. The microstructure of the gel system was analyzed by infrared spectroscopy and scanning electron microscopy (SEM). The results showed that the organic-inorganic composite cross-linking gel with different mass fractions of montmorillonite can effectively form a gel, which covers the three-dimensional network structure and does not damage the original spherical-tree structure. By changing the dosage of montmorillonite, it is found that the strength of the gel system is not only related to the density of the three-dimensional network structure, but also related to the composition of the network structure. The gelation time is approximately 21.0–22.0 h, with strength ranging from H to F level. The gel does not break down after high-temperature aging at 140 ℃ for 120 days, indicating good long-term thermal stability. The peak temperature of the differential scanning calorimetry increases with the increase of montmorillonite mass fraction. When the montmorillonite mass fraction is 2.5%, the peak temperature can reach 181 ℃. Adding montmorillonite can improve the performance of the organic-inorganic composite cross-linking polyacrylamide gel system, and can be used to prepare medium-strength gel systems for high-temperature oil and gas field profile control and water shut-off to further enhance the recovery rate.

There are great differences in geological conditions and reservoir characteristics between Shunbei ultradeep fault-controlled fracture-cave type condensate gas reservoir and other developed condensate gas reservoir, which make it difficult to exploit and lack of development countermeasures for reference. In order to explore the development method suitable for the characteristics of this new type of gas reservoir, based on the actual parameters of the gas reservoir, the quantitative modeling-simulation integration method is adopted to study the depleted development characteristics and pressure maintenance strategies of the fault-controlled fracture-cavity condensate gas reservoir. The results show that some development parameters such as stable production time, gas-oil ratio and connected reserves are deeply affected by retrograde condensate and stress sensitivity simultaneously, which makes the depletion development effect worse. For gas injection, methane injection has better miscibility and is easy to form gravity overburden gas cap flooding, which has the best oil increasement effect. For water injection, the development is greatly affected by relative permeability. The stronger water permeability in fracture is, the easier it is to cause fracture waterflooding in production, and the worse the development effect is. The premature injection timing will compress the production space of oil components in the depletion stage, and late injection timing will cause oil loss due to the retrograde condensation. So, there is an optimal injection timing above the dew point. The faster the injection-producing rate is, the worse the oil increasement is, however the impaction is limited. Meanwhile, the cumulative oil production value becomes bigger with the longer injection time, it’s worth mentioning that the growth rate becomes slower as injection time increase. Besides, for the well group that can form injection-production pattern, the scheme which adopt continuous injection and production mode first, and then switch to pulse injection and continuous production mode before gas channeling is the best strategy in a production full-cycle. For the isolated well, the gas huff-n-puff method can achieve a good effect of pressure supplement and oil increasement. Further, the optimal injection location is related to the factors such as reservoir distribution, reservoir connectivity, and location of produced well. It is necessary to ensure that there is sufficient distance between the injection and production wells, which can increase the swept volume and prevent gas channeling. Finally, the research results have provided effective support for the efficient development of fault-controlled fracture-cave condensate gas reservoirs in Shunbei No. 4 fault zone, and can also provide relevant reference for the development of the same type reservoirs.

In order to reveal the injection mechanism of fracturing-flooding and deepen the understanding of the initiation and propagation of cracks during fracturing-flooding, the formation breakdown pressure, the characteristics of fracture distribution and propagation under different conditions were studied based on physical simulation device for fracturing-flooding, tri-axial stress fluid-structure coupling experimental device, micro-CT and scanning electron microscopy. The experiment results show that the formation breakdown pressure and crack morphology are affected by injected fluid viscosity and injection displacement. The lower injection speed and viscosity of the injected fluid, the more favorable to form the complex fracture network. The morphology of fracture network is determined by the principal fracture and the micro-cracks. The micro-crack is attached to the principal fracture, the principal fracture controls the direction of fracture development, and the micro-fracture determines the spatial distribution of the fracture network. After fracturing-flooding, the permeability of core increases by 10–100 times, and the permeability change area accounts for more than 30% of the plat model.

The optimized parameters suitable for general wet steam huff and puff and steam flooding will not apply to superheated steam because its quality equals to 1. In order to optimize the parameters of superheated steam huff and puff and superheated steam flooding with horizontal well, the numerical model was established based on formation and fluid data of K oilfield. Then, the optimal horizontal well length, cycle steam injection intensity, injection rate, the degree of superheat, soak time and production rate were selected. Meanwhile, the well pattern, the timing for flooding and injection rate were optimized. Finally, the optimal injection-production parameter combination of superheated steam huff and superheated steam flooding is obtained. The results show that the optimal length of horizontal well with superheated steam huff and puff in K oil field is 200–300 m, cycle steam injection intensity is 10 t/m, injection rate is 200 t/d, the degree of superheat is 40 ℃, soak time is 5 d, and production rate is 60 t/d. The optimal well pattern in the superheated steam flooding with horizontal well is staggered well pattern, the optimal timing for drive is after 6 cycles of huff and puff, the injection rate is 80 t/d and production-injection ratio of 1.2. The optimal injection-production parameters provide theoretical guidance for the development of superheated steam huff and puff and superheated steam flooding with horizontal wells in heavy oil reservoirs.

Concerns about global warming have urged the researchers to carry out various carbon capture utilization and storage attempts, among which low salinity carbonated water (LSCW) injection have attract much attention recently. Carbonated water and low salinity water both affect the wettability of crude oil on rock surface, which is crucial to ultimate oil recovery. However, it is still unclear how the wettability will change when combining low salinity water and carbonated water together. Accordingly, to assess and quantify the degree of possible wettability alteration initiated by LSCW, a series of contact angle experiment using the axisymmetric drop shape analysis (ADSA) technique for the captive bubble case under real reservoir pressure (16.0 MPa) and temperature (80℃) is conducted. The effect of brine salinity, CO2 dissolution level and aging time is also well considered for the crude oil-brine-reservoir rock system. Based on analysis of oil adhesion on rocks and rock surface dissolution by LSCW, geochemical modeling is conducted to investigate the mechanism of wettability alteration by LSCW. Results indicate that both brine salinity and CO2 dissolution level have significant effect on the wettability. A reduction in contact angle by carbonated water is observed as compared with formation brine. A decrease in the salinity of carbonated water further enhanced the water wetness of the reservoir rock. Surface complexation modelling results show that the interaction of LSCW with kaolinite dominated sandstone surface reduces the zeta potential of the rock surface as compared with formation brine and carbonated water alone. Meanwhile, an expansion of electric double layer from about 0.373 nm to 2.056 nm occurs. The cation exchange phenomenon during low salinity water injection is also triggered by LSCW. We believe these changes are the dominant mechanisms that make the rock submerged in LSCW become more water wet. Such wettability alteration will favorably affect oil recovery and CO2 storage when LSCW is injected into an oil reservoir at high pressures. This work may offer an experimental and theoretical basis to water-chemistry design for the implementation of pilot projects of LSCW flooding in low permeability reservoirs in Ordos Basin.

In order to solve the problem of poor water flooding development effect of extra-low permeability reservoir in Dagang Oilfield, N fault block is selected to carry out continuous gas injection and intermittent gas injection test. Before the test, in order to optimize the test parameters, experiments are conducted on the oxygen concentration of injected air, injection pressure, and enhanced oil recovery. The design is to inject deoxygenated air with oxygen concentration of 8%, and the injection pressure is 35 MPa. The test results show that the injection capacity of the deoxygenated air is prominent and the effect of increasing production is obvious. In the continuous gas injection stage, the oil production is high, but the gas breakthrough is fast, and the production of well group decreases greatly. The production of intermittent gas injection stage is slightly low, but the production decline of well group is small. At the same gas injection rate, the cumulative oil production of intermittent gas injection well group is higher than that of continuous gas injection well group. Field tests indicate a recovery of 14.2%, which improves recovery by 9.5 percentage points. The experimental results show that the technology of deoxygenated air flooding is feasible for improving oil recovery in extra-low permeability reservoirs, and it has great significance for popularization.

As we grapple with the imminent depletion of conventional oil and gas resources, the focus is progressively shifting towards harnessing unconventional resources, characterized by their substantial reserves and exceptional developmental potential. This paper specifically addresses the application of Steam Assisted Gravity Drainage (SAGD), a widely adopted technique for the exploitation of oil sands, pertinent to certain burial depth ranges. In the SAGD production process, the maintenance of uniformity at the steam-liquid interface is paramount, as it significantly impacts the conformance and productivity of a well pair. This is, however, a formidable challenge due to inherent reservoir heterogeneity and the stringent precision required in horizontal well drilling. In an endeavor to maximize the production capacity of a SAGD well pair, this study explores the implementation of well trajectory adjustment technology, piloted in the MRCP Phase I at the Mackay River Block. This involves a comprehensive analysis of the production performance, supported by a theoretical examination of the technology. The investigation recommends the adoption of SAGD injector re-drill technology to navigate reservoir conditions presenting mud lamination and a bottom transition zone. This innovative approach involves drilling a new horizontal injector above the original well pair, thus establishing a SAGD well pair positioned more optimally within the reservoir. In the wake of the elevation, a reduction in the steam-oil-ratio and pressure differential is evident, leading to the inference that mud lamination and the bottom transition zone cease to be limiting factors. This remarkable enhancement in performance validates the efficacy of injector re-drill technology in alleviating the adverse effects of reservoir heterogeneity, particularly in the lower vertical section. This paper’s findings offer valuable insights for the future application of well trajectory adjustment technology and the strategic deployment of SAGD well pairs, laying the groundwork for further exploration in the field of SAGD development.

Anionic surfactants, such as petroleum sulfonates and heavy alkyl benzene sulfonates, are commonly used as oil displacement agents for tertiary oil recovery in domestic oilfields. However, these surfactants are derived from petroleum products and contain aromatic ring structures that are difficult to biodegrade. This presents significant challenges for environmental governance. To address the issues, the team synthesized sulfonate oil displacement agent EOSA through the sulfonation reaction of waste edible oil ester with oleum. The synthesis process was optimized via laboratory experiments, and the team determined the optimal reaction conditions to be a reactant ratio of 1:2, a reaction time of 4 h, and a reaction temperature of 65℃.In this study, it was discovered that the bio oil sulfonate oil displacement agent, EOSA, effectively decreased the interfacial tension between oil and water. The interfacial tension value was observed to reach 10–3 mN/m, while the agent exhibited temperature resistance of up to 200℃. Additionally, EOSA demonstrated strong salinity resistance, and laboratory experiments revealed that adding just 0.5% of the agent can improve oil displacement efficiency by over 18%.

Caofeidian oilfield group is a typical natural water drive reservoir in the Bohai Sea. At present, it has entered the middle and late stage of ultra-high water cut development. Large scale fluid extraction and infill adjustment are the main development means of the oilfield at present. However, due to the strong plane heterogeneity of the oilfield, with the large scale fluid extraction of the oilfield, it will be difficult to tap the potential of the remaining oil in the low permeability section and difficult to control water and stabilize oil production in the oilfield. It is urgent to explore the feasibility study of water control and plugging measures for development. Through three-dimensional large-scale horizontal well water breakthrough and water control experiments, simulate the physical simulation experiments of bottom water reservoirs under different permeability levels, permeability levels, and crude oil viscosity, as well as the physical simulation experiments of water breakthrough measures taken after water breakthrough in horizontal wells. Analyze the water body sweep law and remaining oil distribution law under different development stages and coupling effects of different main control factors, Summarize the water breakthrough patterns, water control and plugging effects, and production characteristics under different conditions. Guide the improvement of oilfield development effectiveness in the later stage of ultra-high water cut stage, and achieve efficient oilfield development.

Using the physical simulation technology of fire flooding combustion pipe, the feasibility of wet combustion was studied on high viscosity oil (μ ≥ 40000 mPa·s) in the Hong Qian 1 well area of Xinjiang Oilfield; The influence of water injection on the combustion effect is determined by calculating the combustion area and the propulsion speed of the fire line; The key parameters such as water injection time and water/air ratio of wet combustion are further optimized, and the optimal water injection water for the implementation of wet burning scheme on site is determined by combining theoretical calculation. The results showed that the minimum spontaneous ignition temperature of high viscosity oil was 220 °C, the maximum combustion temperature was 650– 700 °C; The low-temperature oxidation reaction occurred at 220–400 °C, and the high-temperature oxidation reaction occurred above 400 °C; During the dry combustion process, the dimensionless standard deviation of pressure and gas injection σ were greater than 15%, indicating that the combustion stability was poor and the blockage was easy to occur when the live wire advanced near the middle of the model (x = 42 cm); The dry firing line propel velocity vD and the wet firing line propulsion velocity vW are negatively and linearly correlated with the axial position; After water injection, vW increases rapidly and then decreases linearly along the axial position; TW > TD in the range of 20–40 cm of the combustion leading edge, and at the back of the model (x ≥ 42 cm) Tw,max > TD,max, indicating that wet combustion can effectively expand the combustion wave area and reduce viscous resistance; The maximum value of the water/air ratio wmax = 8748 L/104 m3; The best time for water injection in wet combustion is to advance the firing line to 24 cm, and the optimal water/air injection ratio is 3000 L /104 m3.

Horizontal wells are an important method to enhance oil recovery in bottom-water heavy oil reservoirs, but the contact area between horizontal Wells and reservoirs is large, and the water cone is usually larger than that of vertical Wells in late development, which increases the difficulty of management. In view of this, the flexible water control system with nitrogen and viscosity reducer is studied in this paper. Through a series of two-dimensional quantitative experiments and visualization experiments, the optimal combination and dosage of the composite system were determined, and the mechanism of water control was revealed. The results show that the optimal design is to inject VR first and then N2. The optimal dosage of VR and N2 is 0.1 PV and 0.3 PV of the water cone pore volume. As a solvent, VR enters the reservoir through osmosis to reduce viscosity of heavy oil and eliminate water cone. N2 strengthens this osmosis. This technology has achieved a good effect on water control and oil increase in field application. This study provides theoretical guidance for the efficient development of horizontal Wells in the same type of heavy oil reservoirs.

As the exploration and development of oil and gas resources continue to develop into ultra-deep and high-temperature reservoirs, the demand for high-temperature resistant fracturing fluids is increasing. Guar gum fracturing fluids is one of the most commonly used types of water-based fracturing fluids, and increasing the size of the crosslinker and the number of crosslinking sites can enhance the performance of the fracturing fluid. In this study, the surface amination modified of hydroxylated carbon nanotubes with KH550, and a nano-crosslinker (CNC) with larger sizes and more crosslinking sites were prepared by combining them with organoboron crosslinkers. The B-N characteristic peak in the FTIR and XPS test curve proved the successful synthesis of the nano-crosslinker. Meanwhile, the thermogravimetric analysis showed that both the modified carbon nanotubes and the nano-crosslinker had good thermal stability. The fracturing fluid formed by crosslinking carbon nanotube crosslinker with 0.3 wt.% hydroxypropyl guar gum (HPG) showed good temperature and shear resistance. The residual viscosity is higher than 50 mPa·s after shearing 120 min at 130 °C and 170 s−1 shear rate. During the formation of a gel by CNC and HPG base solution, the guar molecules form a continuous membrane structure from the original linear structure, thus forming a macroscopic gel that can be picked up. In addition, the presence of carbon nanotubes enhances the strength of the guar gum continuum membrane structure and the tightness between membranes in the fracturing fluid. Therefore, the CNC crosslinked guar gum fracturing fluid has stronger water retention capacity and temperature and shear resistance. This research simplifies the synthesis method of nano-crosslinkers, and the prepared colloidal carbon nanotube crosslinkers can reduce the dosage of guar gum, which has good prospects for application.

At present, some low permeability reservoirs in offshore oil fields have small pores and complex structures. When the fluid flows through them, it is strongly affected by the phase interface, resulting in high water injection pressure, low oil recovery and poor development effects. In this paper, the laboratory research of bio-nano oil displacement system that is suitable for low permeability reservoirs is carried out. The results show that the bio-nano oil displacement system can transform the oil wetting of rock interface into the water wetting, and effectively reduce the oil-water interfacial tension to 10–3 mN/m. The bio-nano oil displacement system, liquid wax and kerosene system can form stable emulsion with an emulsification index of about 0.5. Oil washing efficiency of the bio-nano system can reach 70%, and the viscosity reduction rate of heavy oil can reach more than 90%. Compared with conventional water driving, bio-nano driving has no obvious pressure rise and good injection performance. Oil recovery of cores with different permeability is significantly improved after treatment with bio-nano system. Composite biological nano oil displacement system has obvious effects on improving oil recovery, which is 9.35% higher than that of single active nano oil displacement agent. The biological nano oil displacement effect of well S17 is good. By the end of June 2022, the injection pressure of well S17 is 9.0 MPa, its comprehensive water content is reduced from 84% to 79%, the accumulated oil production is 18081 m3 with its effective period of 215 days. This study will provide a set of environmentally friendly bio-nano oil displacement solution for solving the problems of poor physical properties, low sweep efficiency, and prominent plane conflicts in low permeability reservoirs.

The scheme of numerical simulation grid directly affects computational accuracy, speed and convergence. For massive bottom water reservoir, there is no stable restraining barrier inside, so gravity differentiation is fully played, so fluid flow vertically in a predominate way. A completely horizontal grid proposed in this paper has two advantages over the conventional bedding grid: (1) It can achieve almost absolute grid uniformity, greatly improve the quality of simulation grid, simulation accuracy of interface and computational speed. (2) Different grid sizes can be set in the longitudinal direction as needed to achieve fine grid in the two-phase flow area and the coarse grid in the bottom water area, so the number of effective grids can be obviously reduced without accuracy lost, and the computational time is shortened by 44% to 67% over the conventional grid system. This study provides a reference for the numerical simulation of similar reservoirs.

After years of deep development, the water drive in Sazhong Development Zone of Daqing Oilfield has continuously increased the comprehensive water cut, the casing damage situation is becoming more and more serious, the potential of measures is decreasing year by year, and the difficulty of stabilizing production is increasing. Without the support of large-scale production capacity construction, we need to focus on tapping the existing resource potential, strive to solve various development and adjustment problems, and achieve the goal of controlling water cut and decline. Without the support of large-scale production capacity construction, we need to focus on tapping the existing resource potential, strive to solve various development and adjustment problems, and achieve the goal of controlling the rising rate of water cut and controlling the decline of production. Based on the analysis and understanding of the overall development situation of water drive, this paper defines the working idea of “controlling the rising rate of water cut and controlling the decline of production”, adheres to paying equal attention to controlling the rising rate of water cut and tapping the production potential of oil reservoir, carrying out adjustment and treatment at the same time. Innovates the well condition repair, fracturing integration and pressure drilling technology, and improves the degree of reserve production. Innovate big data analysis and decision-making technology to optimize water injection scheme design. Innovate coiled tubing fracturing and fracturing oil displacement technology, and broaden the potential space of measures. Innovative tracer flow simulation technology accurately identifies invalid cycles. With the support of a series of technologies, the development and adjustment mode of “four optimizations” in the later stage of ultra-high water cut has been formed. A total of 17 technical measures in four aspects have been fully popularized and applied in Sazhong Development Zone, which has played a key supporting role in the long-term and stable development of water drive.

Amphiphilic polymer has excellent thickening ability and shear resistance properties compared with conventional polymer for enhanced oil recovery (EOR) process. However, its viscosity would be rapidly decreased in high-temperature and high-salinity reservoirs. Herein, a novel amphiphilic polymer (PAMN) for oil displacement was optimized and synthesized by introducing adamantane groups through micelle polymerization method, to improve the temperature and salinity resistance of amphiphilic polymer. Use Fourier transform infrared spectroscopy (FT-IR) and nuclear magnetic resonance H spectrometer (1H-NMR) to characterize the chemical structures of the developed temperature and salt resistant amphiphilic polymer (PAMN). Moreover, the rheological properties of PAMN were studied by MCR rheometer under the high-temperature and high-salinity conditions in Shengli Oilfield. The research results indicate that the critical association concentration (CAC) of PAMN is about 2700 mg/L, and the viscosity can reach to 40 mPa·s at CAC. A dense three-dimensional network structure is formed in the polymer solution, which significantly increases the hydrodynamic radius of polymer molecules and significantly increases the solution viscosity. The introduction of rigid groups of adamantane improves the temperature and salt resistance of amphiphilic polymers in aqueous solutions to 90 ℃ and 20 × 104 mg/L, respectively. At 85 ℃, PAMN solution still exhibits good viscoelastic properties, which is beneficial for improving the swept volume and oil displacement efficiency in high-temperature and high-salinity reservoirs. Therefore, this polymer has good EOR application prospects in high-temperature and high-salinity reservoirs.

The ultra-low permeability reservoir in the Jiyuan Oil field exhibits intricate injection-production relationships following multiple cycles of water flooding, limited efficacy of conventional water flooding treatment, uncertain water control, accumulation of residual oil between wells, and suboptimal efficiency of water flooding recovery. In order to achieve the goal of enhancing water flooding treatment effect and improving reservoir recovery, a polymer surfactant composite system displacement test and on-site practical effect evaluation were carried out. The comprehensive indoor experimental results and on-site practical dynamic response research indicate that: ① Surface active agents exhibit significant interfacial activity and emulsifying properties within oil displacement systems, leading to pronounced oil washing effects. Polymer micro-spheres primarily serve the purpose of deep profile control and flooding, thereby extending the scope of water flooding and augmenting the sealing efficacy; ② Polymer microspheres and surfactants are introduced in alternating cycles through the utilization of slugs, leading to a heightened stability in the treatment effect of water flooding; ③ The high water content well group primarily serves to diminish water content and enhance oil production in the primary direction of water drive, albeit with a relatively short validity period of less than six months. Conversely, the medium water content well group predominantly focuses on augmenting oil production in the lateral direction of water drive, with a duration exceeding six months; ④ The main types of wells in the well pattern are water cut reduction and effective reduction (56.5%), while the lateral wells in the well pattern are mainly effective in increasing oil production (43.5%). This study presents the inaugural polymer surfactant composite flooding experiment conducted in the G271 ultra-low permeability reservoir. Through rigorous experimental analysis, it has been elucidated that the interfacial activity and emulsification performance of the composite flooding system significantly enhance oil recovery. These findings shed light on the synergistic mechanism underlying the interfacial activity and emulsification performance in improving oil recovery, thus elucidating the mechanism of composite flooding in ultra-low permeability reservoirs and assessing its practical applicability and effectiveness.

Jurassic low permeability reservoirs with permeability less than 50mD in Changqing oilfield have strong heterogeneity, Now it's the "double high" stage, so it is urgent to explore enhanced oil recovery technology. In this paper, polymer and binary flooding experiments were carried out in parallel with cores of 30mD, 120mD, 160mD and 300mD to study the adaptability of binary flooding for low permeability heterogeneous reservoirs. The experiments show that the selection of appropriate polymer molecular weight and proper viscosity for binary flooding in low permeability heterogeneous reservoirs can not only ensure injection, but also increase the injection pressure. Improve the diversion rate of higher and lower permeability reservoir, expand the sweep volume of lower reservoir, and improve the oil displacement efficiency of heterogeneous reservoir. If the permeability is less than 10mD, the dual system cannot be injected into the reservoir.The permeability level difference of the reservoir is more than 6. Before the dual flooding, it is necessary to carry out profile control and block large pore to ensure the dual flooding effect. After the polymer is produced in the higher permeability layer, the diversion rate of each small layer in parallel core basically returns to the water flooding value, and the subsequent water flooding effect is not obvious. Therefore, profile control should be carried out after the accumulation of dual flooding.

The main oilfields in China have generally entered the ultra-high water cut period. The number of wells using separate-layer injection-production strings is increasing, and it has become an important means to alleviate horizontal and vertical contradictions of water flooding. Traditionally, the control strategies of layered water injection wells and layered oil production wells are designed independently, without considering the linkage relationship between injection and production wells, resulting in insufficient technological potential. For this reason, the injection-production linkage coupling control technology is proposed, which fully considers the dynamic response relationship between injection-production wells in different layers, and realizes fine optimization of injection-production parameters in each layer. Divide the injection-production wells into different injection-production units on the plane, use the Buckley-Leverett oil-water two-phase flooding theory to calculate the water driving state in the unit, and build a proxy model. Combined with the intelligent optimization algorithm, the proxy model is corrected, and the corrected model is further invoked to predict and screen multiple sets of injection-production control schemes until the optimal stratified injection-production parameters are output. Compared with the reservoir numerical simulation, the data-driven model formed based on reservoir engineering has an index calculation coincidence rate of 95.3%, and the calculation speed can be increased by more than 5 times. Through the integration with the intelligent optimization algorithm, it can make full use of massive historical production data quickly and use the actual block data for trial calculation. The fitting degree of key indicators can reach more than 85%, and the distribution of remaining saturation can be output in time. With oil accumulation, NPV, balanced displacement, etc. as the target, layered injection-production parameters are the adjustment objects, and the revised data-driven model is used to quickly predict, analyze and compare massive measure schemes, further automatic iterative optimization, and the final output is the best plan. The research results have been applied to the injection-production control of several water flooding reservoirs in Shengli oilfield. After the application of the typical block B2, the daily oil increase reached 14.7%, the water cut decreased by 0.2%, the oil recovery rate increased by 0.25%, and the recovery rate increased by 0.7%. The development effect is improved significantly.

Hydraulic fracturing is an important method to enhance the tight sandstone reservoir oil recovery, and the fracturing fluid features oil displacement when entering the reservoir, and the oil displacement characteristics varies greatly in different types of tight reservoirs. In this study, the nuclear magnetic resonance (NMR) and microscopic visualization of fracturing fluid oil displacement measurements were launched on the Chang 8 Member of Yanchang Formation in Ordos Basin, the residual oil distribution characteristics and oil utilization degree of different types of reservoirs from microscopic scale were discussed, and the relationship between reservoir microstructure characteristics and oil mobilization characteristics is also analyzed. The results show that the reservoir could be divided into Type I and Type II, and the pore size of oil utilized in Type I reservoir is mainly pores with small pore apertures (<10 ms), forming a uniform replacement mainly due to the fracture, and the residual oil is mainly in the form of continuous piece. The displacement of oil in Type II reservoir mainly occurrences in the pores with larger pore apertures (>10 ms), forming a fracture-centered network replacement, and the residual oil is mainly in the form of clusters, patches and corners. The residual oil in both Type I and Type II reservoirs is mainly retained in small pore space. The factors influencing the effect of replacement oil utilization mainly include reservoir physical properties, pore structure and clay mineral content. The reservoir permeability is the main macroscopic control factor, pore structure is the main microscopic control factor, while clay mineral content leads to the change of pore structure.

Multiple circular extract techniques has been adopted in Daqing oil field for long time, resulting in many problems including high dispersion of remaining oil in sandstone reservoir, extensive development of preponderant seepage channels, ineffective circulation, and failing to enhance recovery efficiency. According to the structural characteristics of the high permeability sandstone reservoir after multiple circular polymer flooding, a new superfine cement plugging system was developed with superfine cement and auxiliary agents. The injection capacity, the injection mode, the injection parameter and the simulation of the plugging performance were studied. As a result, the initial setting time (60–120 h) and the final setting time (120–240 h) of the plugging system could be controlled. The injection viscosity was less than 50 mPa·s. The suspension of the system was stable, and the sedimentation rate decreased with increasing of time. In the first 12 h, the sedimentation rate dropped from 9.9 cm/h to 1 cm/h, and after 25 h, the system sedimentation rate was less than 0.5 cm/h. The compressive strength was higher than 20 MPa after solidification. With the injection rate of 1 mL·min−1, and the slug combination of 0.2 PV polymer and 0.9 PV plugging system, the injection pressure of a 30 cm long core (Water permeability measurement 500–5000 mD) was less than 0.8 MPa, the plugging rate was greater than 90% (Maximum 95.96%). This research shows that the new superfine cement plugging system can realize the permanent plugging of the preferential seepage channels of the sandstone reservoir after the polymer flooding, reconstructing the reservoirs and remodeling the oil reservoirs, which provides technical support for exploiting the top of thick oil reservoirs and the residual oil in the medium-low permeable oil reservoirs efficiently, further enhancing the oil recovery rate.

There are more than 10000 chemical flooding injection wells in Daqing Oilfield. The viscosity of polymer solution is the key factor affecting the displacement effect. Reducing the viscosity loss in the injection process can effectively improve the displacement effect, save the amount of dry powder and reduce the development cost. In order to investigate the influence of various links in the process of polymer solution injection on the viscosity loss of polymer solution, the field simulation test of viscosity loss in the process of polymer solution injection is carried out [1]. Through the simulation test, we explore the viscosity loss of polymer solution flowing through each node and different specifications of blast holes, clarify the downhole viscosity loss in the process of polymer solution injection, and maximize the potential to reduce viscosity loss.The test results show that the viscosity loss rate in the process of polymer solution injection is about 20%, and the main nodes of polymer solution viscosity loss are downhole 1000 m injection string, downhole separate injection tools and perforating holes.The viscosity loss rate of polymer solution in the process section from the injection pump to the 1000 m downhole injection string is 10.30–12.29%, and the viscosity loss rate of polymer solution in the process section of downhole separate injection tools and perforating perforations is 7.23–9.33%. This result provides technical support for improving polymer injection process and improving polymer flooding effect.

After years of water drive development in H area of Changqing low permeability reservoir,the degree of geological recovery is high, and the rate of water cut rise is accelerated, it is urgent to study the law of remaining oil distribution to provide basis for reservoir development adjustment. Firstly, different methods were used to calculate the initial oil saturation and the current remaining oil saturation in H area, and the remaining oil distribution law after water flooding was clarified by comparison; Secondly, the factors that affect the distribution of remaining oil were analyzed: structure, sedimentary facies, interlayer and reservoir heterogeneity, the remaining oil potential of each layer in the test area was defined, and the favorable intervals of production Wells were proposed, which laid the foundation for the development and adjustment of the next reservoir, it lays a foundation for the development and adjustment of reservoir in the next step.

After polymer flooding in Daqing Oilfield, 50% of the remaining oil is still concentrated underground, which is a huge potential for “fourth oil recovery” to increase storage and production. However, it is difficult to exploit and still needs to be tackled. In order to further enhance oil recovery after chemical flooding, a large-scale fracturing enhanced oil recovery technology based on fine reservoir description and accurate residual oil identification is proposed. The effect of large-scale fracturing on enhancing oil recovery is simulated through indoor physical simulation experiments, and verified by field tests. The results show that the residual oil after chemical flooding is mainly distributed at the top of the oil layer and the abrupt part of the oil layer plane, and the main types are two typical features of the plane phase change shielding type and the lateral accumulation interlayer shielding type. Through the physical simulation of fracturing, the recovery rate of the phase-change shielding residual oil after fracturing is 11.5%, and the recovery rate of residual oil after fracturing with side deposition interlayer shielding type increased by 6.4%, and the recovery rate of the shielding residual oil after fracturing is better than that of the phase-change residual oil, confirming the feasibility of this technology. Through field tests, a total of 29 well tests have been carried out. The average daily oil increase of a single well after fracturing is 7.0t at the initial stage, and 2355t after fracturing, increasing the oil recovery by 3.5%. It is expected to achieve the effect of increasing the oil recovery by more than 4.0%. Through the implementation of large-scale fracturing and EOR technology after chemical flooding, the purpose of further economic exploitation of residual oil after chemical flooding has been realized, which has broad application prospects, and can also provide technical reference for the efficient development of other continental sandstone old oil fields.

After polymer flooding in the main reservoir of Daqing Oilfield, about 50% of the reserves remain underground, which is an important potential for oil field production replacement. Through the study of reservoir dynamic retention and oil displacement effect of polymer-surfactant agent, the adsorption and retention characteristics and oil displacement and washing characteristics of polymer-surfactant agent were defined. The research results show that: The hydrophobic groups in the molecular structure of polymer-surfactant agent will associate with each other in aqueous solution to form a 3D elastic network structure, which will give play to the characteristics of structural viscosity. Due to the characteristic of self-adaptive viscosity composed of the structure viscosity and bulk viscosity of the polymer-surfactant agent, it is possible to cut into the low-permeability layer of the throat with a smaller hole while plugging the high-permeability layer, so as to realize the self-adaptive displacement characteristic. The dynamic retention of polymer-surfactant agent is 1.5 times more than polymer, which can play a better role than polymer in the process of plugging adjustment and flooding, and save the amount of chemical while expanding the sweep volume. By comparing the results of microscopic oil displacement experiments, it is shown that the polymer-surfactant agent is better than the polymer in the application of medium and low permeability layer, and can effectively block the high permeability layer, so it is more suitable for the development after polymer flooding. The field test of EOR after polymer flooding further verified that the reservoir activation degree under the permeability condition of less than 300 × 10−3 μm2 in the whole process of polymer-surfactant agent flooding was better than that of the polymer flooding. The final total pay-gross thickness ratio of field test was 2% higher than that of polymer flooding, and the ultimate recovery was 2.0% higher than that of polymer flooding.

A set of high temperature and high pressure miscible and precipitation experimental device was designed, and a new judgment method of miscible flooding was proposed. By establishing a discrimination diagram of formation type changing with the proportion of injected CO2, it qualitatively judged whether the injected gas and stratum fluid were miscible, and characterized the change law of gum and asphaltene through the method of relative precipitation amount. The experiment shown that the mechanism of CO2 flooding in Donghe 6 reservoir was primary contact miscible; The relative precipitation of asphaltene increased rapidly and then decreased slowly with the increase of injection proportion, while the relative precipitation of gum decreased first and then increased with the increase of injection proportion; After gas injection, the reservoir was exploited by depletion. With the pressure decreasing, saturated hydrocarbons were preferentially recovered, and the asphaltene content of formation crude oil increased rapidly.

To clarify the behavior of foam generation and migration in the formation and to examine the basis of its application in oil and gas field development, microscopically etched glass models were used to investigate foam generation mechanism and deflecting ability in porous media by means of visualization experiments. The results show that the neck is easily snapped-off during displacement, anterior neck, and straight neck are easily snapped-off during sucking. When the gas-liquid injection is mixed with water saturation, the process of sucking and displacement will appear alternately, resulting in the change of foam generation mode. It is found that the diameter of foam generated by the anterior cervical blockage is slightly smaller than that of the pore throat of the generating bubble. The diameter of foam generated by straight neck snap-off is about twice that of the pore throat of the generating bubble. The diameter of foam generated by neck blockage is roughly equivalent to that of the pore body. The migration and deflecting ability of foam vary greatly in models with different permeability levels. Generally, the limit of the permeability level difference of foam injection in heterogeneous layers is 6:1, and it is difficult for foam injection alone to affect the low permeability area in models with high permeability levels. It is concluded that the results of the above study can provide some guidance for the application of foam in recovery enhancement.

Water injection is an important method to maintain and restore reservoir pressure and to improve the recovery rate and oil recovery in low permeability oil field. In view of the problems of high injection pressure in water wells, study of an on-the-fly acidification technology is carried out. In order to avoid injection pressure relief, tripping operation and under-pressure operation, an on-the-fly acidizing fluid is developed. The evaluation results show that the on-the-fly acidizing fluid has the advantages of strong chelating capacity, excellent inhibition of precipitation, extremely low corrosion and good retarding performance. With the mounted equipment equipped with acid-proof pump, water and the on-the-fly acidizing fluid can be injected directly after mixing. Eleven field tests prove that it realizes no trip operation, no flowback, non-interference between water injection and acid treatment, which shorten the job execution time and provide an effective stimulation method.

As the largest ultra deep sea facies sandstone reservoir in Tarim Oilfield, Donghe sandstone reservoir in Hudson Oilfield has entered the late stage of water drive. Compared to the eastern oilfield, the Donghe sandstone reservoir is deeply buried, with large injection production well spacing, strong reservoir heterogeneity, and sufficient edge and bottom water energy, resulting in complex distribution of remaining oil, making it difficult to implement stable oil and controlled decline technology. Limited by geological conditions and development factors, fluid extraction from Hudson Donghe sandstone reservoir is faced with problems such as how to select wells, how to determine the timing of fluid extraction, and how to calculate the amplitude of fluid extraction. In view of a series of difficulties faced by liquid extraction in the late stage of water drive in ultra deep sea facies sandstone reservoirs, explore the development characteristics of dominant percolation channels, clarify the microscopic residual oil distribution patterns, and propose a geological model for liquid extraction and oil increase. Using the split flow equation, the phase permeability curve of a single well and the dynamic parameters of dimensionless liquid production and oil production index are calculated, and a comprehensive evaluation method for the timing and volume of liquid extraction is established. This method has good field application effect and explores a new way to stabilize oil and water production for ultra deep sea facies sandstone.

Chemical methods of enhanced oil recovery in general and Surfactant Polymer (SP) flooding, in particular, are considered as a promising tertiary method of developing mature oil fields in Western Siberia, with the potential to increase oil recovery to 60–70% of the initial geological reserves [1, 2]. The selected SP compositions were tested at one of the oil fields of Western Siberia in December 2022-January 2023 using Single Well Chemical Tracer Test. A total of three SWCTTs were conducted on three wells.The residual oil saturation after waterflooding (Sorw) was determined at the first stage of SWCTT. Then the surfactant-polymer composition was injected into the well and pushed by water chase. After that the residual oil saturation after chemical flooding (Sorc) was determined. The effectiveness of surfactant-polymer flooding was defined as the difference between Sorw and Sorc. Initial analysis of SWCTT results showed low efficiency of surfactant-polymer flooding, because Sor is calculated using the well-known analytical formula [3], which is applicable for ideal conditions (radial flow of tracers to the well).As it was shown in [4] the shape of tracer production curves can be affected by the drift (displacement) of the fluid front due to the pressure gradient between the zones of fluid injection and withdrawal, which significantly complicates the interpretation and modeling of the results. The surrounding wells stock analysis showed that the target well was heavily influenced by neighboring injection and production wells, so fluid migration in the reservoir must be accounted for in order to correctly analyze the results.Considering the fluid drift in the reservoir during SWCTT modeling allowed us to correctly adapt the tracer production curves and correctly estimate the efficiency of surfactant-polymer flooding. Without taking drift into account, the difference between Sorw and Sorc was 0.07, which corresponds to an increment of oil residual factor (ΔRF) of 11% OOIP (original oil in place). SWCTT modeling considering drift showed that the real efficiency of surfactant-polymer flooding was: ΔSorc = 0.115, which corresponds to ΔRF of 17.4% OOIP. Thus, SWCTT modeling with consideration of drift showed that the applied surfactant-polymer composition is a highly effective oil displacing agent.

Flow enhancement by influencing the bottomhole zone (BHZ) makes a significant contribution to oil field development, especially in carbonate reservoirs. Improving the effectiveness of bottomhole zone treatments (BHT) is achieved by selecting effective compositions, improving the search for candidate wells and developing an optimal design. In this work we propose to consider a solution for modeling the acid treatment on the reservoir. The main idea is to improve the effectiveness of acid treatment by more accurate and comprehensive simulation of hydrodynamic and physical-chemical processes in the well and bottomhole zone, a full-fledged simulation of the properties, structure and composition of the reservoir.The software solution is a set of tools that are aimed at performing tasks related to modeling hydrodynamics during injection and production of fluid in the bottomhole zone and well, as well as modeling physical and chemical processes in the reservoir. The created tools provide simulation of non-isothermal flows of non-Newtonian fluids in the reservoir and wellbore, taking into account the heterogeneity of properties, mineralogical composition of BHZ, and distribution of contaminants in the reservoir and hydraulic fractures. The program implements a tool to correct uncertainties in the data by performing adaptation to the historical data of the well operation as well as determining the effective design when solving the optimization problem. Special attention is paid to simulation of fluid flow in tubing in order to design treatments for wells with complex design or coiled tubing (CT). The software package contains a digital database of minerals, chemical reactions, injected fluids, and includes a simulation tool for laboratory experiments.Using the developed software, the influence of geophysical and chemical model parameters on the effectiveness of the treatment, as well as the influence of secondary and tertiary reactions on the process of acid treatment in sandstone reservoirs was studied. The influence of the characteristics of formation damages on the effectiveness of the treatment, and the flow of non-Newtonian fluid (diverters, emulsion compositions, etc.) in the well and reservoir was studied. The analysis of acid treatments on several assets of oil companies was carried out. These examples show the main scenarios of work with the program: evaluation of additional production and economic effect, adaptation and adjustment of the model to the fact, selection of the optimal design.The simulator includes both a simplified 2D model and a complex 3D model with varying degrees of detail when setting initial parameters (mineralogy, geometry) and when calculating dynamic characteristics. An important addition is the user-friendly of the interface for different levels of users.

Due to the upsurge in global demand for oil and the current elevated oil prices, the recovery of heavy oil reserves has become a pivotal concern within the oil industry. Addressing the challenges and intricacies associated with the extraction of these reserves has been a primary focus in recent years. Substantial quantities of hydrocarbon resources remain untapped due to the high viscosity of the oil. Thermal recovery techniques offer a solution by reducing oil viscosity and increasing overall recovery rates through the application of heat to the underlying reservoirs.One such thermal recovery method is hot water injection, involving the introduction of heated water into hydrocarbon formations. This process effectively diminishes the viscosity of heavy oil, facilitating its movement towards production wells. This particular study centered on the implementation of hot water injection in an Azerbaijani reservoir that harbored significant quantities of residual heavy oil reserves. The initial conditions within the reservoir indicated an oil saturation of 75% and a viscosity of 500 cP. A series of experiments were conducted to investigate the displacement of two-phase fluid flows, with the primary aim of identifying the optimal design parameters for injection temperature and hot water slug size, ultimately enhancing performance. The study results showcase various design configurations, encompassing hot water floods with differing time intervals and slug sizes.In light of these findings, it is evident that hot water injection systems can be designed and implemented to effectively extract heavy oil from such reservoirs. Furthermore, these discoveries shed light on the specific design parameters that can significantly enhance recovery performance. Among the pivotal aspects of this process is the determination of the optimal hot water injection volume, as it plays a critical role in maximizing oil recovery from the reservoir.

This work investigates the effectiveness of nitrocellulose lacquer in the corrosion protection of medium carbon steel in different environments. Samples of the 0.27% carbon steel were coated with plasticized nitrocellulose lacquer and immersed in freshwater, seawater and air. Some of the samples were left exposed to air. Weight loss method and potentio-dynamic electrode method were used to investigate the corrosion of coated and uncoated samples of 0.27% carbon steel in the various mediums for a duration of 60days at 10 days interval. Weight loss data was recorded every 10 days for the 60-day periods. The Potentio-dynamic electrode method was used for corrosion tests of the steel in the different mediums. Silver/Silver Chloride (Ag/AgCl) and graphite were used as the reference and counter electrodes in a conventional three electrode polarization system. Results from the weight loss experiments showed that there were no significant changes in the weight of lacquer-coated samples in the various mediums after +60-days. However, weight loss in the uncoated samples were significant in all the mediums after 60-days. The potentio-dynamic electrode method revealed that the effect of coating of the coupons with a p-value of 0.0392(<0.05) is significant on the corrosion rate of the steel coupons while the effect of the different environment considered with a p-value of 0.2267(>0.05) is insignificant on the corrosion rate of the metal.

High-frequency oscillations have a good effect on the ability of geomaterials to pass fluid through themselves in the presence of paraffins in the filtered liquid. To assess the influence of high-frequency vibrations on changes in the permeability of rocks through which paraffin oil is filtered, it is necessary to create conditions and a scale similar to well conditions. According to these conditions, the influx of waxy oil coming from the formation into the production well must be modeled in conjunction with ultrasonic vibrations emanating from the well and propagating in the opposite direction to the fluid flow and passing through the rock matrix and fluid. To bridge the gap between small-scale studies and field observations, studies were performed on core samples of three different permeabilities. The laboratory bench is a modified core flooding system that allows you to create a fluid flow through the geomaterial (simulating the flow of oil from the reservoir to the well) in a field of high-frequency loads. The fluid outflow chamber has been improved. To generate high-frequency loading, a Langevin-type piezoelectric actuator is used. When the drive is turned on, the lid oscillates and loads the liquid in the chamber, resulting in a wave of compression and discharge through the cone. Ultrasonic vibration leads to displacement of pore cavities, deformation of paraffin wax and their movement towards the cavities. The force threshold of adhesion of deposits to the wall with the help of oscillatory acceleration, paraffin and asphaltene particles break off and are pushed further along the channel by the oil flow. The ultrasonic vibration on the rock, through which paraffinic oil is filtered, helps to restore the oil permeability coefficient for samples of medium and high permeability. The force threshold for the adhesion of paraffins to cavities is overcome by vibrations of the paraffin matrix and the deposits are pushed by the liquid in the direction of the well. The impact of high-frequency vibrations on the geomaterial through which formation fluid flows helps restore the oil permeability coefficient for geomaterials of medium and high permeability.

Now, first set of class II reservoirs of DaQing Oilfield development would be fully completed, the problem of sequence and mode selection in the upper or lower layer development need to settle. In order to determine on the class II reservoir development way, south-middle-east block of Lamadian oilfield was chosen as example to carry out research, used technical and economical method. In technology section, from the perspective of the blocks in static and dynamic data, using statistical methods to analyze, to carry out the potential fluctuation return series, determine the PII1~GI5 for the next step development zone. Economically, using the theory of big data, establishes the system model, established method of drill new wells or the use of old well pattern development, and mode development selection chart, determines the south Middle East areas development way. The research results show that when oil prices above $50/bbl and at present, the development of new drilling shall be used. The method is effective for oil blocks development technical support, the layered sandstone reservoir development has a certain guiding significance.

In the ultra-low permeability reservoir, with the extension of water injection time, the reservoir characteristics are also changing, and it is difficult to determine the reasonable unstable water injection parameters. For the optimization of unstable water injection parameters, three methods are indoor core experiment analysis, numerical simulation and mine experiment, among which core experiment analysis and numerical simulation cost more and require more accurate basic data; mine experiment requires rich experience to achieve good results. In this study, the main factors affecting the effect of unstable water injection in the study area and the weight of the influence of each influencing factor were analyzed to calculate the reasonable injection amount and water injection fluctuation range, and applied them to the actual typical well group to achieve good results. Through this study, it can provide a set of practical and easy to operate methods for the optimization of water injection parameters in long-term unstable water injection development fields.

Unstable water injection in reservoirs leads to continuous changes in reservoir physical properties, making it difficult to determine reasonable water injection parameters. Conventional core experimental analysis, numerical simulation, and field experimental methods have limitations such as high cost, insufficient experience, and lack of data in optimizing unstable water injection parameters. The multiphase flow numerical well testing model is established through numerical methods for well testing analysis, with comprehensive considerations and high reliability of interpretation results. However, the model is difficult to establish and requires a large amount of calculation, making it difficult to apply in practice. Moreover, the existing parameter characterization functions for time-varying reservoir properties have problems such as inconsistent functional forms, excessive fitting parameters, and limited applicability, making their practical application difficult. Therefore, in this study, a universal time-varying characteristic function of physical parameters is constructed, and a well testing analysis model for oil-water two-phase injection wells is established. The pressure solutions are obtained by numerical method for well testing analysis. The characteristics of typical well testing curves and the changes in well testing curves under different time-varying parameter conditions are studied and analyzed, and the interpreted permeability time-varying parameters are compared over time to guide the optimization direction of water injection parameters. Through calculation and analysis of field examples, the research results indicate that by considering the time-varying law of reservoir physical properties and based on cumulative inflow flux, a universal permeability time-varying function is constructed, which reduces fitting parameters and reduces the difficulty of function application. By comparing this parameter over time, it is found that in reservoirs with long-term water injection and high permeability channels (microfractures), the parameter increases, reflecting the further expansion of high permeability channels between oil and water wells due to excessive injection volume or short injection shutdown time. Therefore, the injection volume should be reduced or the injection shutdown time should be extended. The proposed method can provide a practical well testing analysis method for optimizing water injection parameters in long-term unstable water injection development oilfields.

As a representative of the country's ultra high water cut old oilfield, Daqing oilfield has been developed for more than 60 years, with water cut up to 95% and recoverable reserves up to 90%. Among them, Changyuan has entered the late stage of development of double extra high, the remaining oil distribution is scattered, the liquid-oil ratio increases sharply, and it is faced with some development problems, such as smaller scale construction and production potential, poor effect of conventional measures, and high number of casing damage Wells. The peripheral oilfield in Daqing is characterized by thin and narrow reservoir, poor physical property, small pore throat and high reservoir temperature, which makes it difficult to use reserves economically and effectively. Conventional measures, such as fracturing, profile control and water plugging, can only improve the percolation conditions in the near-wellbore area of the reservoir, but have certain limitations on the exploration potential of the remaining oil in the plane and the top of the thick reservoir. New methods of enhanced oil recovery are urgently needed. With the development of MWD measurement technology while drilling and the improvement of trajectory adjustment accuracy, ultra-short radius lateral drilling horizontal Wells can achieve accurate geological design to explore potential targets. In this paper, the application of measurement while drilling and precise control of ultra-short radius horizontal Wells in the excavation of residual oil at the edge of potential fault, the top of thick reservoir, the casing loss well, the treatment of long shut-off and low efficiency well, and the optimization and adjustment of well pattern are studied, which provides a new way for the effective excavation of scattered remaining oil in ultra-high water cut old oilfield.