Abstract:The turbidite fans of Miocene Meishan Formation in Qiongdongnan Basin are important targets for natural gas exploration in the northern South China Sea， and the types of turbidite fan is closely related to reservoir development. The turbidite fans of Meishan Formation in Qiongdongnan Basin can be divided into shelf fans， slope fans， and basin floor fans according to the factors of sea level change， submarine topography， and syndepositional faults. The shelf fans at the shelf or shelf edge and the slope fans at the slope zone are mainly deposited in the highstand system and the late lowstand system respectively. The basin floor fans deposited in the early lowstand system can be further divided into six types： fault-terrace basin floor fan， final-terrace basin floor fan of faultcontrolled gentle slopes， basin floor fan of fault-controlled steep slope roots， lobate basin floor fan， basin floor fan cut by canyons，and confined basin floor fan. The turbidite fan type and provenance system are important controlling factors affecting reservoirs’physical properties. The reservoirs of fault-terrace basin floor fans， basin floor fans cut by canyon， and lobate basin floor fans are developed and are important exploration targets. Due to poor sedimentary differentiation and high mud content， the exploration risks are relatively large in the basin floor fans of fault-controlled steep slope roots， shelf fans， and slope fans. Final-terrace basin floor fans of fault-controlled gentle slopes and confined basin floor fans have fine grain and high mud content， which should be avoided in exploration. The various fan reservoirs are developed due to the sufficient provenance supply of Ledong-Lingshui area in the western part of Qiongdongnan Basin； however the excellent and high-quality reservoirs are underdeveloped due to the fine detrital particles and high mud content， and the lack provenance supply of Baodao area and Changchang area in the middle part of Qiongdongnan Basin， which are far away from the provenance area.

Abstract:Precise and fast acquisition of shale porosity is important for the prediction of the spatial distribution of shale oil and the exploration target. To address the problem of low accuracy of porosity prediction using logging response equation， a porosity prediction model based on random forest algorithm is established， and the prediction accuracy is compared with those of BP neural network，support vector machine， and XGBoost algorithm， and the importance and influence range of logging parameters are analyzed by SHAP method. The results show that the random forest algorithm can better predict shale porosity， and the prediction effect is better than BP neural network， support vector machine， and XGBoost algorithm； the application of shale porosity prediction based on random forest algorithm in a depression in Bohai Bay Basin finds that the top three most important logging parameters for model prediction of porosity are compensation neutron， natural gamma， and ordinary apparent resistivity； the shale porosity prediction model based on random forest algorithm can quickly identify the porosity of a single well， which can not only compensate for the difficulty of obtaining the complete porosity distribution characteristics due to the inability of continuous coring but also significantly improve the efficiency and accuracy of porosity prediction.

Abstract:Offshore low-permeability reservoirs have a low percentage of producing reserves and thus are of great development potential.However，the strong heterogeneity of pore structures in low-permeability reservoirs has resulted in complex fluid mobility and oil -water occurrence characteristics，which makes it difficult to tap the remaining oil potential in low-permeability sandstone reservoirs at the development stage. The full-aperture pore size distribution characteristics of low-permeability sandstones and their influence on fluid mobility and occurrence characteristics of remaining oil were investigated by using nuclear magnetic resonance displacement experiments supplemented by high-pressure mercury injection，micron CT displacement experiments，and flow numerical simulation. The results show that the multi-scale pore sizes in low-permeability sandstones are featured by bimodal distribution.The movable fluids mainly occur in large pores（0.1 -10 μm），while the irreducible water mainly occurs in micropores（< 0.1 μm）. When the crude oil enters the low-permeability sandstone，it preferentially occurs in the large pores，and the sandstone with favorable physical properties shows a more significant differential occurrence of crude oil. For the sandstone with relatively favorable physical properties，the microscopic remaining oil mainly occurs in the large pores in the form of pore filling. For the sandstone with worse physical properties，the microscopic remaining oil mainly occurs in the micropores. The pore-filling remaining oil is formed by the weak sweep of relatively large pores due to the dominant flow channel generated by the heterogeneous pore structures during water flooding，which is the key target of potential tapping. By reducing the oil-water interfacial tension and increasing the displacement speed，the dominant flow channels can be effectively reduced，and the percentage of producing remaining oil in lowpermeability sandstones can be improved.

Abstract:The interlaced underwater distributary channel sand bodies are developed in Chang 4+5 reservoir group in Jiyuan area，and their internal contact relationships are complex， which seriously affects the reservoir distribution law and water flooding development effect in this area. It is beneficial to the sustained and stable production and efficient development of Chang 4+5 reservoir in Jiyuan area by the fine study of identification and division of single sand body interface， analyzing the contact modes of sand bodes and their influence on water flooding effect in Chang 4+5 reservoir. Based on the identification and division of the single sand body interface， the core， logging， and dynamic production data are comprehensively applied to delineate the internal contact relationships of sand bodies， and then clarify the influence of transverse cross and vertical superposition relationships of sand bodies on water flooding effect. The results show that there are three vertical superposition relationships of sand bodies in Chang 4+5 reservoir in Jiyuan area， namely cut-stacked， superimposed， and separated. Among them， the cut-stacked sand bodies are more homogeneous，with high oil content and percentage of producing reserves under water flooding， followed by the superimposed sand body. The lateral contact modes of single sand bodies can be divided into three types： isolated mode， docking mode， and side-cut mode. Different contact modes reflect the difference in interwell connectivity of channel sand bodies， which in turn affects the effective time of water injection in oil wells. The effective time of water injection in oil wells corresponding to the side cut mode is short，followed by the docking mode， and the effect of water injection in oil wells corresponding to the isolated sand body is not obvious.

Abstract:It is a major difficulty to accurately characterize the inner fault-controlled bodies in the exploration and development of fault-controlled oil and gas reservoirs because the fault-controlled bodies are diverse in reservoir space， complicated in structure，and highly heterogeneous in reservoir space， which affects the exploration and development of the oil and gas reservoirs. The seismic，logging， and other data are integrated and the inner breccia zones and intercluster fracture zones of caverns-like were finely characterized in this paper. The grid structure models of the fault-controlled bodies caverns-like were established and their contours were described with seismic multiple attributes； the image analysis was fully combined with mathematical statistics by a selfcompiled program and the core and wing regions of the caverns-like were defined by the parameters such as the location and width of the breccia and intercluster fracture zones； the development scales of the breccia zones and intercluster fracture zones in different parts of caverns-like were determined. The results show that the cluster-filled grid structures of caverns-like are composed of the breccia zones， intercluster fracture zones， and intergrid matrix， and the reservoir properties of breccia zones is better than those of intercluster fracture zones， and they are better than those of the intergrid matrix. The breccia zones and intercluster fracture zones control the reservoir properties of caverns-like， and the multi-cluster grid structures determine the separateness and strong heterogeneity of the reservoirs. Compared with the translation sections， the grid strike bodies in the extrusion sections are counterclockwise offset by 10°， and those in the pull sections are counterclockwise offset by 16°. The spatial distribution models of fault-controlled bodies in this area are established by combining the strike-slip fault caverns-like contours and the inner caverns-like description，which provides a geological basis for efficient exploration and development of other fault-controlled oil and gas reservoirs.

Abstract:There are multiple mutation points in the acoustic emission （AE） cumulative curve in the Kaiser experiments of reservoir cores， causing the routine Kaiser effect point discriminant method to be inaccurate， and there is even a problem that the Kaiser point cannot be read. To solve this problem， an optimized Kaiser effect point discriminant method combining AE energy spectrum and cumulative AE curve is proposed in this paper and applied to the prediction of reservoir in-situ stress in Block X of an Oilfield.The experimental results of core uniaxial loading show that at the initial period of core loading， the core is in the compression stage， with a large number of AE and a wide fluctuation range of AE energy values. In the middle period of loading，the core is in the elastic deformation stage. The amount of AE is small， and the AE energy value is low. The range of change is uniform. At the late loading period， the stress reaches the fracture pressure of the reservoir core， and the core ruptures. The number of AE increases sharply， and the AE energy value reaches a peak. In the middle period of loading， the core suddenly releases a large amount of energy，and the AE number and energy value have a sudden increase， followed by a rapid decrease when the axial stress reaches the historical maximum stress of the reservoir core. This phenomenon is in accordance with that of Kaiser. Therefore， the Kaiser effect point can be determined by combining the AE energy spectrum and cumulative AE curve. By using the optimized Kaiser effect point discriminant method， the in-situ stress distribution in Block X of an Oilfield is analyzed， and the results are in good agreement with the field test results.

Abstract:The low-permeability reservoirs in Shengli Oilfield are rich in resources，with produced geological reserves of 9.4×10⁸t，recovery of 13.3%， and unproduced reserves of 2.1×10⁸t. Enhanced oil recovery and benefit development face many challenges，such as injection failure， displacement failure，and poor swept volume. In order to improve the development effect of lowpermeability reservoirs，Shengli Oilfield has innovated the pressure drive technology to tackle these problems. A series of technologies have been developed， including the evaluation criteria for the adaptability of pressure drive technology，the laboratory experimental technology system， and the optimization design method for reservoir engineering schemes by comprehensively applying theories and methods of geology， fluid flow mechanics in porous medium， and reservoir engineering as well as combining physical and numerical simulation. These technologies are supported by zonal pressure drive，combined network volume fracturing，and profile control and drive processes. Field tests showed that pressure drive can quickly replenish formation energy and dramatically improve oil well productivity and recovery. Since March 2020，450 well groups have been implemented in low-permeability reservoirs，with a cumulative injection of 1 384×10⁴m³and a cumulative oil increase of 55.7×10⁴t. Pressure drive development technology is gradually becoming a new leading development technology for low-permeability reservoirs.

Abstract:The low-permeability reservoir is one of the important oil production positions in Shengli Oilfield， and its reserves accounts for more than 20% of the total oilfield reserves. The low-permeability reservoir always presents characteristics such as a narrow pore throat and strong heterogeneity， which results in high injection pressure and difficult injection during water flooding. At present， the main measures to improve the development effect include active agents for reducing pressure and increasing injection，water injection under high pressure， and narrowing the distance of drainage wells. However， there are still some production problems，such as short effective time， low well injection per well， low liquid production per well， and small swept volume. Therefore，it is urgent to develop new and efficient development methods. Since the“ 13th Five-Year Plan in 2016-2020”， the synergistic development modes have been implemented， such as replenishing energy injection enhancement in injectors， increasing production by imbibition in producers， and increasing swept volume by displacement between injectors and producers， which can enhance displacement pressure gradient， water displacement， and recovery. The synergistic development mode has been applied in Chunhua Oilfield. The injection pressure of the well in 62 Block of Chunhua Oilfield has been reduced by 20%； the water injection has been increased by 25%， and the daily oil production of the single production well has increased from 0.45 t/d to 5.08 t/d， with obvious yield increase benefit. The overall recovery has increased by more than 8%.

Abstract:The CO₂-water-rock interaction is the core issue of CO₂ geological sequestration. The injection of CO₂ disrupts the chemical balance of rock-formation water， and the changes in the chemical properties of formation water， primary mineral dissolution，and secondary mineral precipitation will lead to changes in the physical properties of reservoir and caprock，such as porosity，wettability，and mechanical properties and thus directly affect the CO₂ injection capacity， sequestration efficiency，and sequestration security and stability. Based on the mechanism of CO₂-water-rock interaction，this paper systematically expounds on the research progress of the effects of CO₂-water-rock interaction on porosity，permeability， wettability， and mechanical properties of formation rocks. The results show that the change in rock porosity and permeability caused by CO₂-water-rock interaction is closely related to its initial porosity and permeability characteristics and mineral composition， and the change of rock porosity and permeability characteristics directly affects the injection capacity and sequestration potential of the reservoir and the sealing capacity of the caprock.The change in wettability is related to the initial hydrophilic and oil-philic characteristics. The CO₂-water-rock interaction usually weakens the water wettability of the hydrophilic rocks and enhances that of the oil-philic rocks， thus affecting the microscopic distribution and seepage characteristics of the multiphase fluids in the pores of the rocks. Due to the dissolution of cement and the formation of dissolution holes，the CO₂-water-rock interaction will cause rock damage， and the mechanical parameters such as compressive strength， tensile strength，and elastic modulus will decrease. To a certain extent， the security of sequestration is affected. Under the setting of carbon neutrality，the CO₂-water-rock interaction and rock physical property response under the scenarios of micronano-scale pore，deep microbial mediation，impure CO₂ or industrial tail gas injection， and full sequestration cycle still need to be further studied.

Abstract:Cores from shale reservoirs in Subei Oilfield were taken as sample to study the effects of surfactants on the oil displacement efficiency and the main controlling factors of imbibition in shale reservoirs. The TOC analysis and scanning microscope technique （SEM） were used to characterize the pore structure of the core samples. Imbibition experiments under the influence of multiple factors were conducted using nuclear magnetic resonance （NMR） technology. Then the effects of factors were evaluated such as wettability， fractures， porosities， permeability， surfactant concentrations， and types on the imbibition efficiency of shale oil reservoirs，and the distribution characteristics and producing conditions of the oil in different pores were clarified during the imbibition process. The results showed that shale imbibition could be divided into three stages： early stage， middle stage， and late stage. The imbibition rate was high in the early stage， and the imbibition efficiency increased rapidly. The middle stage accounted for the longest period， and the imbibition rate slowed down in the late stage， with the imbibition efficiency tending to be stable. By comparing the effects of different factors on imbibition， it was found that a wetter core indicated more fractures and higher imbibition rate and efficiency. Moreover， a higher porosity and lower permeability led to higher imbibition efficiency. The imbibition efficiency showed an increasing trend with the concentration of surfactants decreasing. The NMR experimental results demonstrated that in the process of shale imbibition，the produced oil of micro-pores was more than that of macro-pores，and changing the imbibition conditions could improve the producing percentage of oil in various pores.

Abstract:The application scale of chemical viscosity reduction and cold recovery technology for heavy oil in Shengli Oilfield is increasing year by year. However，the influence of viscosity reducers on the physicochemical characteristics of heavy oil is not clear.By collecting heavy oil samples from typical blocks，the four-component analysis，relative molecular mass test，interfacial rheological property evaluation，and microscopic morphology characterization of heavy oil before and after viscosity reduction were carried out. The results show that the asphaltene content is the main factor affecting the viscosity of heavy oil. Viscosity reducer molecules weaken the interaction between resin and asphaltene aggregates through diffusion，penetration，and adsorption，resulting in a decrease in relative molecular mass. The double adsorption process of the oil-water phase under the action of viscosity reducer molecules causes a decrease in interfacial film strength and increases the deformability of oil droplets. After the viscosity reducer treatment，the cluster-like aggregate structure in the heavy oil sample is destroyed. The dispersed phase of resin and asphaltene changed to the liquid phase of saturated and aromatic phenol，and the crude oil fluidity is significantly improved.

Abstract:The development effects of heavy oil reservoirs after water flooding become poor due to the serious emulsification of produced liquid and reduction of formation fluidity in Block Jin17 of Shengli Oilfield. Therefore， the emulsification characteristics of heavy oil and water were studied through emulsification state analysis， viscosity， and rheology testing， oil-water interfacial tension （IFT） testing， etc.， and the flow characteristics of emulsified heavy oil were analyzed. Then， the re-emulsification characteristics of emulsified heavy oil were studied by analyzing the emulsification state， droplet size， viscosity， and viscoelasticity of emulsions formed by emulsification oil flooding agent and W/O emulsion. Finally， the re-emulsification mechanisms of emulsified heavy oil were analyzed， and the idea of emulsification oil flooding method was provided. The results show that emulsification has a serious effect on the viscosity of heavy oil emulsions. Under the reservoir temperature of 60 °C， the viscosity， viscosity modulus， and IFT of W/O emulsions with water content of 60% are 11.9，13.49，and 2.49 times that of dehydrated heavy oil， respectively. Moreover，the fluidity of W/O emulsions in the porous media is seriously restricted due to its stronger non-Newtonian characteristics， the viscosity increased exponentially， the viscous modulus increased significantly， and IFT increased rapidly when the water content is higher than 40%. W/O/W multiple emulsions are formed when emulsified heavy oil and emulsification oil flooding agents are reemulsified.Moreover， the droplet size， viscosity， and viscoelasticity of the emulsions increase with the increment of initial water content in W/O emulsion. When the initial water content of W/O emulsion is 60%，the droplet sizes of emulsions formed by emulsification oil flooding agents LPA， HPF， and SDS and W/O emulsion are 91.3，40.6， and 27.5 μm， respectively. Compared with the emulsions formed with dehydrated heavy oil， the droplet sizes are 7.9， 4.0， and 2.2 times， respectively. This indicates that the emulsification of formation water/injection water and heavy oil has a great influence on enhanced oil recovery of heavy oil by emulsification oil flooding agents. Therefore， strengthening the ability of emulsification oil flooding systems to penetrate oil film and replace the adsorption of active substances in heavy oil on the oil-water interface is the focus of subsequent research and development of emulsification oil flooding systems and construction method design.

Abstract:The effect of the thermal composite fluid remaining in the reservoirs on the rheological properties of the plugging agent particle solution is still unclear at the late thermal composite development stage of the heavy oil reservoirs. Therefore， it limits the application of particle solutions in this stage. For this， based on the rheological theoretical model and viscosity-concentration formula，a viscosity-concentration relationship that can accurately describe the SiO₂ + polymer dispersion system was preferably selected by combining the viscosity-concentration change of particle solutions. The effects of different factors on the rheological properties of the SiO₂ + polymer dispersion system and the mechanism were investigated by using a rheometer，a Zeta potential analyzer，and a scanning electron microscope. The results show that the viscosity-concentration relationship of the SiO₂ + polymer dispersion system is in accordance with the Krieger and Dougherty viscosity-concentration models. The viscosity of the SiO₂ + polymer dispersion system decreases with increasing temperature or mineralization. The viscosity of the SiO₂ + polymer dispersion system in-creases with increasing particle concentration or pH. The difference in viscosity between SiO₂ + polymer dispersion systems with anionic and nonionic surfactants is not significant，while the viscosity of SiO₂ + polymer dispersion system with cationic surfactants is significantly greater than that of the remaining two solutions. The viscosity of the particle solutions with different types of surfactants decreases as the pH decreases. Therefore，it is important to select a suitable particle solution to provide a theoretical basis for the application of SiO₂ + polymer dispersion system in the late thermal composite development stage of thick oil reservoirs.

Abstract:The annual production capacity of more than one million tons has been realized because Mahu conglomerate reservoirs are rich in oil and gas resources and a series of development technologies featuring“large well cluster，multi-layer system，small well spacing，long well section，staggered type，dense cutting，zippered type，and industrialization”have been formed under the guidance of the idea of geological engineering integration. However，the drilling and completion engineering and stable production are significantly affected due to the different degrees of inter-well interference in the process of three-dimensional development of horizontal wells with small well spacing and volume fracturing of horizontal wells. Therefore，theoretical research and numerical simulation are combined to study the fracturing interference mechanism and analyze the main control factors. The results show that ①according to the connection modes and characteristics of inter-well interference in horizontal well fracturing，the inter-well interference in horizontal well fracturing in Mahu conglomerate reservoirs can be divided into three types：fracturing interference caused by the development of natural weak structure，interference caused by fracture communication，and adjacent well interference induced by the connectivity of the pressure/stress interference zones due to the fracturing interference；②the horizontal well spacing is the key factor affecting the inter-well interference and the inter-well interference degree in horizontal well fracturing，the the prob‐ability of inter-well interference in the study area increases greatly when the spacing between horizontal wells is less than 300 m.Therefore，it is necessary to comprehensively consider the positive effect of fracturing interference on reservoir production and the adverse impact of fracturing interference on the drilling and completion engineering / the oil production and reasonably optimize the design of horizontal well spacing，which are of positive significance to the safe and efficient development of conglomerate reservoirs.

Abstract:Acid-fracturing technologies have become conventional measures to increase production in the field of petroleum engineering，and they are widely used in carbonate rock， tight sandstone， and volcanic rock reservoirs. However， relevant research mainly focuses on specific blocks， and there is a lack of a systematic and comprehensive summary of relevant research progress.This paper comprehensively investigated the latest progress of acid-fracturing technologies in China and abroad， systematically concluded the research achievements including the hot acid-fracturing technologies， difficulties and measures of acid-fracturing simulation in different reservoirs， acid-fracturing mechanism， and factors affecting acid-fracturing， and pointed out the development trend and existing problems of acid-fracturing technologies. Differentiated multi-staged acid-fracturing technology， volume acidfracturing technology， and fracture height control acid-fracturing technology are hot acid-fracturing technologies in recent years.There are certain differences in the difficulties of acid-fracturing simulation in different reservoirs. Therefore， it is necessary to formulate corresponding acid-fracturing technology policies according to reservoir characteristics. The acid-fracturing mechanism can be analyzed through theoretical calculation and experiments. Theoretical calculation is the basis of acid-fracturing technology re‐search，and experiments can provide important guidance for the research on acid-fracturing mechanisms and the determination of process parameters. Acid-fracturing technologies are affected by both geological and engineering factors. Geological factors are the basis of acid-fracturing technology policies， and engineering factors are the key to improving acid-fracturing effects. At present，acid-fracturing technologies are developing in four directions：deep and ultra-deep acid-fracturing layers，accurate acid-fracturing objects， expanded acid-fracturing scope， and controllable acid-fracturing technologies. It is suggested to strengthen the research on acid-fracturing theories， continuously improve the process and equipment， and establish the implementation template of typical acid-fracturing technologies， so as to guide the implementation of acid-fracturing technologies.

Abstract:Shunbei fault-karst reservoir in Tarim Basin is a special type of carbonate reservoirs. The reservoir spaces are mainly formed by caves and fractures transformed by faulting. Due to reservoir spaces with complex structures， irregular shapes， and strong randomness of distribution， there are many uncertainties in the traditional delineation technology of fracture-cavity spaces based on static seismic data. The forward simulation method of numerical well testing is adopted to analyze the geological significance of different well test curves according to fracture-cavity space delineation results， and it is clear that the fault-karst reservoirs can be dynamically characterized based on well test analysis. A quantitative characterization method of reservoir spaces is proposed by correcting the threshold values of fracture-cavity delineation with dynamical numerical well test data. This method determines the shapes and reserve sizes of the reservoir spaces， and then selects a more accurate delineation models by combining well test interpretation，production characteristics analysis， and other research means and using the reservoir space knowledge with the dynamic correction to constrain the threshold values of the seismic attributes.

Abstract:Fengshen 1 condensate gas reservoir with low permeability has complex geological and phase characteristics such as low permeability，easy sand production，and extremely high content of condensate oil. Therefore，retrograde condensate pollution is inevitable during development. It is essential to clarify the retrograde condensate pollution characteristics and establish pollution relief measures. In this paper，experiments about retrograde condensate pollution characteristics and relief measures were conducted. The results show that the effective permeability of the gas phase in long cores is decreased by more than 90% under the maximum retrograde condensate pressure of 19 MPa. Fracturing can improve the effective permeability of the gas phase in long cores，but the degree of retrograde condensate pollution has not been significantly improved. For the single injection medium，CO₂ injection has a significantly better effect on relieving retrograde condensate pollution than methanol injection and associated gas injection. The mixed medium of methanol and CO₂ in equal proportion has a better effect on relieving retrograde condensate pollution than a single injection medium，and it is the optimal choice. As for the injection timing，the maximum permeability recovery rate of fractured long cores after injecting CO₂ at 19 MPa is 61.18%. Then the condensate oil recovery can reach 36.2% when the injection pressure reaches the abandoned pressure，which is 4.9% higher than that at 5 MPa and 7.8% higher than in the depletion process. As a result，it is the relatively optimal injection timing.