Abstract:

The geological reserves of shale oil from the Jurassic Lianggaoshan Formation in the eastern Sichuan region are large，but challenges of the high inhomogeneity and the unclear identification of sweet spots，etc.，seriously limit the effective exploration and development of oil and gas. Based on data from core drilling，X-ray diffraction（XRD），scanning electron microscope（SEM），and two-dimensional nuclear magnetic resonance（2D NMR），the shale oil lithofacies in the Jurassic Lianggaoshan Formation in the east‐ern Sichuan region were finely divided，and the storage properties，oil content，and mobility characteristics of shale oil reservoirs of different lithofacies were in-depth analyzed. Then，the dominant lithofacies and the main controlling factors of oil and gas enrichment were clarified. The results show that shale oil reservoirs of the Jurassic Lianggaoshan Formation in the eastern Sichuan region develop five types of lithofacies：massive sandstone，siltstone，interlayered sand-mudstone，massive shale，and laminated shale. Among them，massive sandstone，siltstone，and interlayered sand-mudstone are ineffective reservoirs，which mainly play the role of cap rock，while massive shale and laminated shale are the dominant lithofacies in the eastern Sichuan region，belonging to typical selfgeneration，self-storage and micro-migration shale oil reservoirs，with high total organic carbon（TOC），high pyrolytic hydrocarbon content，high porosity，high oil saturation，and high mobile oil saturation. The strong enrichment and high production of shale oil and gas from massive shale and laminated shale are mainly controlled by the following factors：① The organic-rich shale is the material basis for shale oil and gas enrichment and storage in the deep-water environment of the foreland depression. ② The high vitrinite re‐flectance and hydrophilicity are the key factors of shale oil and gas migration and production. ③ The bedding fractures controlled by the high stratigraphic pressure are an essential guarantee for the stable and high production of shale oil and gas. The massive shale and laminated shale are the key shale oil exploration targets of the Jurassic Lianggaoshan Formation in the eastern Sichuan region.

Abstract:

The diagenesis and evolution of organic-rich shale have an important influence on the characteristics of shale reservoirs，but the relationship between diagenesis and reservoir characteristics of organic-rich shale in the Second Member of Kongdian Formation in Cangdong Sag of Huanghua Depression is not clear，which restricts the exploration and development of shale oil and gas. By means of X-ray diffraction（XRD），petrographic thin section，scanning electron microscope，and other experimental measurements，the diagenesis types and controlling factors of organic-rich shale in the Second Member of Kongdian Formation in Cangdong Sag were studied systematically，and its diagenetic evolution stage was defined. The influence of diagenesis on the micro-pore structure of shale was also discussed. The results showed that the organic-rich shale in the Second Member of Kongdian Formation in Cangdong Sag has many diagenetic types，such as compaction，metasomatism，dissolution，cementation，and thermal evolution of organic matter，and the main body is in the middle diagenetic A2 stage. The sedimentary environment and diagenetic fluid jointly control the diagenesis，which respectively determines the material composition of the rock and the formation and evolution of the secondary pores in the later stage. Dissolution and thermal evolution of organic matter belong to constructive diagenesis. Organic acids induced by hydrocarbon generation are of great significance to the dissolution transformation and optimization of reservoirs，which are beneficial to the formation of high-quality shale reservoirs. Compaction and cementation belong to destructive diagenesis. The diagenetic difference of different lithofacies has a significant influence on the pore structure，in which feldspathic shale facies has good mechanical brittleness and reservoir capacity，which is conducive to the formation of effective reservoirs，and the dissolution of mixed shale facies is weak as a whole. Destructive diagenesis causes pore reduction，which is not conducive to the formation of effective reservoirs. Carbonate shale facies has widely developed dissolution pores，but their mineral cementation limits porosity and pore connectivity and is not conducive to the formation of effective reservoirs.

Abstract:

The differential evaluation of fracturing fluid and its additives is an important link in the integrated development process of shale reservoir engineering geology，and clay stabilizer is a crucial additive. Therefore，the rapid screening of clay stabilizers plays an important role in protecting shale reservoirs and ensuring fracturing effects. By introducing the detection method of capillary suction time（CST）and combining it with the mineral composition of core samples obtained by X-ray diffraction，the calculated CST of core samples from shale reservoirs was obtained by weighting. The correlation between the detected and calculated CST of core samples and the calculated and detected cation exchange capacity（CEC）obtained by the traditional clay stabilizer evaluation method was established，respectively. It was found that they all had the same changing trend as the detected CEC. By introducing the proportional coefficient，the detected and calculated CST was fitted with the calculated CEC，and the corresponding fitted detection value of CEC was obtained. The relative errors between them and detected CEC were analyzed，respectively，and it was found that the average relative errors were all less than 5%. The experimental results show that both the detected CST of core samples and the calculated CST based on X-ray diffraction and standard mineral CST detection value can be used to evaluate and screen clay stabilizers. Compared with the traditional CEC evaluation method，the CST detection method is rapid and accurate and is suitable for the complex clay mineral composition and strong heterogeneity of shale reservoirs.

Abstract:

The precise determination of shale oil sources is of great significance for the evaluation of sweet spots and resource potential in shale oil. Exploration practice indicates significant differences in the biomarker fingerprint characteristics of shale oil of the Upper Submember of the 4^th Member of the Eocene Shahejie Formation（Es₄^U）from some wells in Niuzhuang Subsag in Dongying Sag，reflecting that shale oil accumulation might not be the traditional understanding of“self-generation and self-storage.”In order to meet the needs of fine exploration，it is urgent to explore the differences in hydrocarbon generation in each layer series and the main hydrocarbon supply layer series. Geochemical testing techniques，such as light hydrocarbon and gas chromatography-mass spectrometry，etc.，were comprehensively used，and a systematic study was conducted on the organic geochemical characteristics of hydrocarbon source rocks and shale oil from key wells in the Upper Submember of the 4^th Member of the Eocene Shahejie Formation（Es₄^UC）in Niuxie 55 Block of Dongying Sag. Then，the oil sources were finely determined. The results indicate that the organic matter development characteristics of each layer series of Es4UC in Niuxie 55 Block have heterogeneity，reflecting vertical changes in organic matter sources and thermal evolution. At the same time，the distinct differences in hydrocarbon generation characteristics of each layer series are caused by periodic changes in factors，such as organic matter sources and sedimentary environments，etc. A fine oil source correlation shows that the shale oil from Well NY1-AHF and Well NY1-BHF in this block，respectively，come from the shale of the third and fourth layer series of Es₄^UC，reflecting the source control characteristics of differential shale oil aggregation. Comprehensive analysis suggests that fine exploration and deployment of shale oil should pay attention to the main hydrocarbon supply layer series and consider certain macroscopic structural backgrounds. Exploring high-quality reservoir space，especially effective fault transport areas，is an essential sweet spot element for achieving the efficient development of shale oil in advantageous source rock development areas.

Abstract:

The exploration of shale oil and gas in Jiyang Depression has made breakthroughs since 2020. It is urgent to report the scale of shale oil reserves accurately. The accurate acquisition of effective porosity in the laboratory and the fine logging characterization are key factors restricting the reporting of shale oil reserves. The analysis and characterization of effective porosity in shale reser‐voirs were carried out based on core experiments，nuclear magnetic resonance（NMR）logging，and conventional logging data to solve the problem of evaluating the effective porosity of shale reservoirs. In the core experiment，the experimental procedures of the liquid measurement method and two-dimensional（2D）NMR method were optimized，and many methods were compared and selected. In the logging characterization，the 2D NMR logging frequency and temperature were calibrated based on the core calibrating logging concept，and the sensitivity was analyzed to establish a conventional logging evaluation model of effective porosity. Based on the above research，the experimental measurement and the fine logging characterization of effective porosity were carried out in the shale reservoir in the Upper Chunhuazhen Submember of the 4^th Member of the Econe Shahejie Formation（Es₄^UC））in Boxing Subsag，and the experimental test method was determined，which is mainly liquid measurement method and supplemented by the 2D NMR method. The effective porosity T₂ cutoff value was clarified in the 2D NMR experiment，and the NMR logging-based effective porosity characterization method was innovatively formed based on the frequency and temperature correction. Two conventional logging evaluation models were established，containing lithology indicators（natural Gamma）and physical property indicators（interval transit time and neutron porosity）. The calculation results have high accuracy，and the relative errors are all below ±12%，which meets the requirements of reserve estimation regulation，achieving accurate characterization of effective porosity of shale reservoirs，and the models were successfully applied in reserve reporting.

Abstract:

Subtle lithologic traps are essential fields for oil and gas exploration in deep clastic rocks of Tarim Basin. The geological distribution pattern of favorable reservoirs in clastic rocks is a key challenge restricting efficient exploration and development.At present，breakthroughs in oil and gas exploration have been made in the deep reservoirs of the Lower Cretaceous Yageliemu Formation in Xinhe area of the northern Tarim Basin. In view of the limitation of wells，the distribution pattern of reservoirs in Yageliemu Formation urgently needs to be further clarified. This study took the plaeo uplift in Xinhe area of the northern Tarim Basin and the northern fault slope zone as examples and used prediction methods such as core analysis，seismic reflection identification，paleogeomorphology restoration，channel characterization，and seismic inversion constraint. Based on the theory of the source-sink system，the distribution characteristics of the source area，sediment transport channel，and fan delta in Yageliemu Formation on the plane and profile were analyzed. The research results indicated that fan delta sediments are developed in Yageliemu Formation in Xinhe area of the northern Tarim Basin. The sediment source of the fan delta in Xinhe area comes from the plaeo uplift in Xinhe area，and the development of multi-tributary incised valleys provides effective transportation channels for the fan delta sediments. The upstream area of Well W1 region in the southwest is characterized by shallow，narrow，straight，and small watershed area valleys. The small-sized fan delta sediments are developed in the incised valleys and feature late development. Well W2 region in the northeast has a wide，deep，multi-tributary，and large watershed area valley system in the upstream，with large-sized fan delta sediments developed，featuring large-scale early development，late regressive development，and early and late fan superposition.

Abstract:

Gentle and steep slope platform-margin reefs are well-developed in the Changxing Formation in the Kaijiang-Liangping Trough in the northeast Sichuan Basin. At present，there is less research on the sedimentary structure and evolution model of steep slope platform-margin reefs. The exploration and development of oil and gas reservoirs in the area are restricted. Based on seismic，logging，and drilling data，the internal structure，external profile，and planar distribution characteristics of the steep slope platform-margin reefs of the Changxing Formation were systematically compared. The evolution models and influencing factors of these steep slope platform-margin reefs were discussed. The results show that the steep slope platform-margin reefs of the Kaijiang-Liangping Trough can be divided into fault-controlled steep slope type and sedimentary steep slope type. The external contour of the fault-controlled steep slope platform-margin reef shows a significant symmetry. The deposition thickness is approximately 100-200 m，and there is no lateral migration phenomenon. Moreover，it is mainly distributed in discontinuous and strip-like patterns on the plane. The width of the slope zone at the platform-margin is approximately 1.3-1.9 km. The external contour of the sedimentary steep slope platform-margin reef is asymmetrical. The deposition thickness is approximately 40-120 m，and lateral migration can be observed. It is distributed discontinuously and star-like on the plane. The width of the slope zone at the platform margin is approximately 2.0-2.5 km. The fault-controlled steep slope platform margin reefs have significant differences from the sedimentary steep slope platform-margin reefs in terms of sea level change，paleogeomorphic features，and paleoenvironmental conditions due to the occurrence of synsedimentary fault activities. It leads to obvious differences between the two in terms of external contours，structure，and distribution. Through comprehensive analysis of stratigraphy，paleogeomorphology，and sedimentary facies of the steep slope platform-margin reefs of the Changxing Formation in the Kaijiang-Liangping Trough，the differential evolution models of the three stages of the reef have been established. The adjustment period of Longtan Formation：with the rise of sea level，the environmental conditions are changed，which paves the way for the growth and development of the reef；stable growth period of Changxing Formation：at this time，there are the best environmental conditions for the survival of reef-building organisms，and the reefs develop rapidly；decline period of Changxing Formation：The reef continues to grow and begin to expose the water surface，leading to dolomitization and decline.

Abstract:

The fractures often alter the acid dissolution patterns and affect the acid treatment effectiveness during acid treatments in fractured carbonate reservoirs. Based on the two-scale continuum model，scholars have conducted numerous studies on the acid dissolution mechanisms in porous and fractured carbonate reservoirs using numerical simulation methods. However，relatively few studies focused on the differences in how fractures influence the acid dissolution mechanisms in fractured dolomite and limestone reservoirs. The two-scale continuum model was extended，and an acid dissolution model suitable for simulating acid treatment in carbonate reservoirs with varying calcite and dolomite contents was developed. Then，the related research was conducted in conjunction with a pseudo-fracture model. Acid dissolution simulation results for dolomite and limestone reservoirs were obtained by changing the positions，lengths，and dip angles of fractures. The acid treatment effectiveness was evaluated using the acid dissolution patterns and breakthrough volumes，clarifying the influence of fractures on the acid dissolution mechanisms in dolomite and limestone reservoirs. This provided a theoretical foundation for the design and optimization of acid treatments in fractured dolomite and limestone reservoirs. The results indicate that the optimal acid pump rates for limestone reservoirs are higher than those for dolomite reservoirs. When the pump rates are lower than the optimal ones for dolomite reservoirs，the breakthrough volumes of the two reservoirs are similar. However，when the pump rates exceed the optimal ones for dolomite reservoirs，the breakthrough volumes in dolomite reservoirs remain consistently higher than in limestone reservoirs. The primary factor influencing breakthrough volume is fracture length，while the secondary factor is fracture dip angle. As fracture length increases and dip angle decreases，the breakthrough volumes decrease in dolomite and limestone reservoirs，whereas fracture position has little effect on breakthrough volume. Short fractures have a greater impact on dolomite reservoirs than on limestone reservoirs，but as fracture length increases，their influence on both reservoir types becomes more similar. In dolomite and limestone reservoirs，fractures at different positions，with various lengths and dip angles，attract acid flow，and wormholes consistently connect the fractures.Compared to acid-etched wormholes，the amounts of acid dissolution on the fracture walls are minimal. The influence of fracture dip angles on acid dissolution patterns is mainly reflected in the directions of the main wormholes. Fractures facilitate rapid acid breakthrough；few branches develop on the fracture walls when the fracture dip angles are small. However，fractures hinder rapid acid breakthrough，and numerous branches develop along the fracture walls as the fracture dip angle increases to 75° in dolomite reservoirs and 60° in limestone reservoirs.

Abstract:

Low-permeability sandstone reservoirs are more susceptible to form blockage during the oil development process due to their smaller pore throat. Microemulsion acids（MEAs）with nano-level droplets and great deformability have better injection ability and adaptability for low-permeability reservoirs. However，research is still lacking on the relationship between the phase state of MEAs and the plugging removal effect. Therefore，in view of the conditions of a certain low-permeability sandstone reservoir in the Bohai Sea，the pseudo-ternary phase diagram method was adopted to prepare homogeneous and heterogeneous MEAs composed of the same chemical agent but with different phase states，and its plugging removal and corrosion effects were evaluated through laboratory experiments and field applications. In addition，the influence mechanism of the MEA phase on the effect was analyzed through chemical property evaluation，microscopic morphology，and adsorption experiments. The results show that by adjusting the volume of water and oil phases，MEA can be smoothly transformed from the double continuous type to the oil-in-water（O/W）type and the oil-in-water（W/O）type，thereby constructing a homogeneous and heterogeneous MEA system. The MEA system has a good dissolution effect on the mixed blockage. Among them，the plugging removal effect of the O/W type MEA system is 10% higher than that of the traditional acid solution，and it can increase the daily oil production by 53.44% in the field experiment.However，the W/O type MEA system shows lower corrosiveness，with a corrosion rate of only 47.78% of that of pure acid. The results of the mechanism study show that the strong plugging removal property of the O/W MEA system stems from its strong oil-carrying capacity，which can more efficiently strip and carry the crude oil around the blockage，thereby enabling the acid solution to contact the solid blockage effectively. In the W/O type MEA system，the encapsulation property of oil relative to acid solution and the synergistic effect produced by the mixed adsorption of emulsifier and light oil on the surface of the steel sheet make it have low corrosiveness.

Abstract:

In view of the low flowback rate and poor gas well productivity in tight sandstone reservoirs of Shahezi Formation in theJS-LS gas field，Songliao Basin，the mechanism of fracturing fluid damage and water lock release of supercritical carbon dioxide （SC-CO₂）in tight feldspathic sandstone reservoirs were analyzed based on the results of core displacement experiment，mineral composition analysis，wettability test，and microscopic analysis. The results showed that the reservoir lithology of Shahezi Formation in the study area is a typical tight feldspathic sandstone，whose smaller pore size and strong hydrophilicity lead to the obvious retention of fracturing fluid after invasion. The average irreducible water saturation is 60.51%，corresponding to an average liquid film thickness of 373.31 nm. The irreducible water and liquid film occupy a lot of pore space. The water lock damage rate accounts for 55.54% of the total damage rate of permeability. This results in fracturing fluid damage，mainly in the form of a water lock.SC-CO₂ is significantly different from conventional pre-liquid N₂ in terms of removing the water lock due to the strong diffusivity，penetrating ability，and high solubility in water. Moreover，SC-CO₂ dissolves into water under high pressure and forms carbonic acid. It dissolves reservoir minerals by extraction，then improving reservoir permeability. In addition，it forms a miscible phase with water and eliminates interfacial tension. Compared with N₂ and natural gas，SC-CO₂ significantly reduces capillary force in the process of displacement，expands the irreducible water volume in the core，destroys the liquid film，and reduces the irreducible water saturation and the liquid film thickness. It reduces the average irreducible water saturation to 26.754% and the average liquid film thickness to 179.35 nm. Moreover，SC-CO₂can enter almost any pore throat larger than the diameter of CO₂ molecules in the reservoir，further enhancing its ability to release water lock.

Abstract:

The CO₂ captured from the flue gas of coal-fired power plants usually contains other gases such as nitrogen oxides，sulfur oxides，and O₂. These gases may threaten safe CO₂ sequestration after they are injected with CO₂ into formation. However，there are still some gaps in Chinese and overseas research on the influence of CO₂ with impurities on the dissolution law of sandstone.Therefore，this paper took a sandstone reservoir in an oilfield as the research object and conducted an experimental study on the reaction of CO₂ containing different concentrations of NO₂，SO₂，and NO₂ + SO₂ with formation water and reservoir rock under dif‐ferent reaction times，temperatures，and pressures. Atmospheric-pressure and high-pressure tests were carried out，respectively. The dissolution rate，micro-morphology，composition，and mechanical properties of the core before and after the reaction，as well as the cation concentration in the solution after the reaction，were analyzed. The results show that during the reaction among other gas，CO₂，formation water，and reservoir rock，feldspar，dolomite，chlorite，and other minerals in the core are dissolved，and core dissolution mainly occurs in feldspar；quartz is slightly dissolved when the reaction time reaches 21 days. The core dissolution rate increases as the reaction time increases. The core dissolution rate also increases when the pressure changes from atmospheric pressure to 10 MPa，indicating that the reaction time and pressure have a noteworthy influence on the core dissolution rate. For the same impurity concentration，SO₂ is more likely to dissolve sandstone than NO₂，and the core dissolution rate is higher when SO₂ and NO₂ are injected simultaneously. The injection of NO₂ decreases the tensile strength and Poisson’s ratio of sandstone and increases the elastic modulus. The SO₂ injection increases the tensile strength and elastic modulus of the core and decreases the Poisson’s ratio of the core.

Abstract:

The complex heterogeneity inside heavy oil reservoirs makes obtaining excellent development results difficult through conventional fire flooding technology. In view of this issue，this paper proposed that chemical ignition could be carried out by adding catalysts in heterogeneous reservoirs and compared the development characteristics with that of fire flooding in homogeneous reservoirs to reveal the improvement of fire flooding development effect by this technology. The fire flooding experiments with or without physical barriers were carried out through the three-dimensional（3D）physical model，and the development of the temperature field，as well as the formation and expansion law of coke zones were explored. The development characteristics of fire flooding under two reservoir conditions were further revealed through the analysis of the production effect and the distribution of remaining oil after fire flooding. The results showed that reservoir heterogeneity affects the advance of the combustion front，and local high temperatures appear due to shielding action，especially at physical barriers. Relay ignition can break through physical barriers in cooperation with the combustion front after adding catalysts，and the temperature cavity continues to expand，with the highest temperature reaching 583.2 °C. Different from homogeneous reservoirs，the coke zones formed in heterogeneous reservoirs are discontinuous. However，stress fracture occurs in physical barriers after relay ignition，and the combustion front continues to advance to the production well through the fracture zones. Then，combustion chambers expand rapidly. In the process of fire flooding in homogeneous reservoirs，high oil production is maintained in the stable combustion stage，and the ultimate recovery is 53.27%. After relay ignition in heterogeneous reservoirs，stable oil production begins and enters the main oil production period. A large amount of crude oil is displaced，and only a small amount of crude oil exists in the non-flow field，with the ultimate recovery being 51.46%. The distribution of remaining oil in the two reservoirs tends to zero in the high-temperature area. The oil saturation in the area affected by physical barriers is higher in heterogeneous reservoirs before relay ignition，but the oil saturation in the whole area is significantly reduced after relay ignition. The oil saturation in the lower part of the two reservoirs is the lowest because of the most intense combustion.

Abstract:

Extra-heavy oil reservoirs generally have high oil viscosity and poor mobility，resulting in unsatisfactory performance of the conventional cyclic steam stimulation（CSS）development. Compared to CSS，vertical-horizontal well steam drive（VHSD） development can increase the recovery by more than 10%. An extra-heavy oil block in the eastern Shengli Oilfield was taken as an example，and a laboratory-scale model established based on similarity principles was combined with numerical methods to investigate the VHSD development mechanism，thereby determining the steam chamber expansion process and key factors influencing development. The research results indicate that ① the steam chamber first expands independently and then connects in a “concave”shape during the VHSD process. The steam chamber increases with the increase in steam injection volume after the thermal connection is realized. The oil production decreases，and the final recovery of the experiment is 55.42% when the steam chamber expands to the horizontal well. ② In the preheating stage of huff and puff，the amount of steam injected in a single cycle is not more than 1 600 m³，and the oil production time is not more than 150 d；the well shut-in lasts for 5-10 d，and the effective preheating of the reservoir can be realized after 3-4 cycles. ③ The steam injection rate in the VHSD stage does not exceed 60 m³/d，and the production-injection ratio does not exceed 1.1. Among the influencing factors，the steam injection rate and steam dryness of VHSD have the greatest influence on the expansion and development of the steam chamber.

Abstract:

During the development of heavy oil reservoirs in the eastern South China Sea，asphaltene precipitation can cause block‐ages in reservoir throats，wellbores，and pipelines，leading to a decrease in the productivity of oil wells. This article took nine typi‐cal heavy oil reservoirs in PY Oilfield as an example，selected nine natural core samples with high，medium，and low content of as‐phaltene，and conducted critical pressure experiments for asphaltene precipitation by using viscosity and light transmission methods.The quantitative relationships between different samples and permeability loss of reservoirs were analyzed，and numerical simula‐tion methods were used to simulate and calculate the influence of different reservoir permeability models and asphaltene damage conditions on the production of oil wells. The research results show that thicker heavy oil in PY Oilfield indicates a higher asphal‐tene content and a smaller precipitation pressure difference. During the production process，asphaltene is more easily precipitated and deposited. The differences between the reservoir formation pressures and the precipitation pressures of asphaltene（precipitation pressure difference）are 1.55-6.25 MPa. The asphaltene molecules in crude oil precipitate through the cores if the formation pres‐sures drop below the precipitation pressures of asphaltene. They first block small pores and throats and then block large throats and medium-large pores. A higher asphaltene content indicates a greater reservoir permeability loss. The permeability loss of 3 000 mD samples ranges from 20% to 60%，and that of 5 000 mD samples ranges from 20% to 40%. When the formation permeability is higher，asphaltene would quickly pass through large throats and pores after precipitation，and most of them would not precipitate in throats and pores，causing less damage to the reservoir permeability under the same conditions. The precipitation pressures of as‐phaltene should be kept lower than the formation pressures during the process of heavy oil production，which can effectively avoid the occurrence of asphaltene precipitation damage to the reservoir near the wellbore due to pressure drop and reduce the impact on the production capacity of oil wells.

Abstract:

The emulsifying ability of oil displacement agents plays a crucial role in the chemical flooding process，but the quantita‐tive characterization of emulsifying ability remains unsolved. In response to this challenge，this paper presented a new method for quantitatively characterizing the emulsifying ability through emulsification of oil displacement agent-crude oil systems induced by rotating fluid. The method determined the experimental parameters（emulsification coefficient）characterizing the emulsifying ability of oil displacement agents by plotting the dynamic curve of emulsification oil rate at different rotational speeds. The emulsification coefficient fully characterized the initial rotational speed of emulsification，initial emulsification oil rate，and emulsification speed of oil displacement agents with crude oil and accurately distinguished and compared the differences in emulsifying ability caused by changes in the mass fraction of the oil displacement agent，type of oil displacement agent，and properties of the crude oil. By comparing the emulsification coefficients，it was found that AEO9 had the highest emulsification coefficient（1.184），while SDS had the lowest emulsification coefficient（0.320）. The emulsifying ability of the oil displacement agents for CQ crude oil in descending order was as follows：AEO9＞SDBS＞SCS＞Na₂CO₃＞AEO5＞SDS. As the mass fraction of the oil displacement agent increased，the emulsification coefficient increased，indicating an enhanced emulsifying ability. The emulsifying ability of the oil displacement agents was also influenced by the properties of the crude oil. Due to the higher content of active components in SL crude oil，the emulsifying ability of the oil displacement agents is greater for SL crude oil than for CQ crude oil. In addition，the results of co-injection experiments involving surfactants and crude oil in porous media，as well as surfactant flooding experiments，indicate that oil displacement agents with higher emulsification coefficients exhibit stronger in-situ emulsifying ability in porous media. Therefore，using the emulsification coefficient as a parameter to characterize and evaluate the emulsifying ability of oil displacement agents is reasonable.

Abstract:

Conventional oil displacement polymers are partially hydrolyzed polyacrylamide（HPAM）. When the temperature is above 80 °C，the hydrolysis rate of acid amide accelerates，and the carboxylic acid produced after hydrolysis is prone to complex with calcium and magnesium ions to form precipitation，which significantly reduces the performance of HPAM. To improve the temperature and salt resistance of the polymer，The polymerization of acrylamide（AM）monomer with three anti-hydrolytic monomers N-vinylpyrrolidone（NVP），dimethylacrylamide（DMAA），and 2-acrylamide-2-methylpropanesulfonic acid（AMPS） is often carried out in binary，ternary or quaternary copolymerization，but the influence of each monomer on the properties of polymers has not been deeply studied. So，three kinds of hydrolysis resistant binary copolymers P（AM-AMPS），P（AM-DMAA），and P（AM-NVP）were synthesized by copolymerization of three kinds of monomers with AM respectively. The effects of the introduction of three monomers on polymer properties were investigated. The results show that the introduction of 20% NVP，DMAA，and AMPS on the HPAM main chain leads the viscosity-average molecular weight of the polymer to reduce from 3 050×10⁴ to 720×10⁴，1 500×10⁴ and 2 800×10⁴，respectively. The average hydrodynamics diameters decrease by 39.5%，27.7%，and increase by 12.4%，respectively. The effect of the introduction of AMPS on the molecular weight of HPAM was significantly smaller than that of NVP and DMAA. Due to the lack of complexation between the sulfonic acid anion in AMPS and calcium and magnesium ions，the strong intermolecular repulsion allows molecular chains to be more stretched in aqueous solutions，which significantly improves the viscosity，viscoelasticity，and thermal stability of the polymer. The results of laboratory and field experiments show that P（AM-AMPS）can significantly improve the oil displacement performance of the polymer under high temperature and high salt reservoir conditions，indicating a broad application prospect.

Abstract:

Rhamnolipids are biodegradable and environmentally friendly surfactants with low toxicity，high stability，and other advantages. In the oil and gas development field，they have broad application value and prospects. This paper reviewed the progress in the application of rhamnolipids in oil and gas development，discussed its production methods，characteristics，and current status，and provided new ideas for the green and sustainable development of oil and gas development. The paper first introduced the two production methods of rhamnolipids：enzymatic and fermentation. Then，the authors elaborated in detail on the characteristics of rhamnolipids in reducing surface tension，emulsification and demulsification，solubilization，and coiling，as well as the suitable conditions. In addition，the new anti-aggregation characteristics discovered by recent scholars were clarified. The paper focused on summarizing the five main application directions of rhamnolipids in oil and gas development：in terms of reducing viscosity of heavy oil，rhamnolipids can effectively reduce the viscosity of heavy oil and enhance oil recovery；in terms of treating oil-contaminated soil and water，rhamnolipids show excellent emulsification performance and can separate oil from soil and form easy-to-treat emulsion；in terms of promoting hydrate generation，rhamnolipids can reduce the induction time of hydrates and improve the generation rate and stability of hydrates；in terms of oil and gas pipeline transportation，the anti-aggregation characteristics of rhamnolipids can help solve the problem of pipeline blockage；the authors finally proposed the following research suggestions for the future：in terms of production method，it is necessary to increase the research and application of local extraction strains；in terms of characteristic research，it is necessary to explore the other functional characteristics of rhamnolipids besides the existing ones and expand its application scopes in oil and gas development；in terms of application，it is important to study the recyclable use of rhamnolipids and the synergistic application of multiple technologies to solve problems such as high development costs in super-heavy oil production. At present，the application research of rhamnolipids in the frontier oil and gas fields such as hydrates is not complete，and further in-depth exploration is needed.