Abstract:

The condensate gas reservoirs with fault-controlled fracture-cavity structures in Shunbei area represent a significant breakthrough in oil and gas exploration within Tarim Basin in recent years. Its efficient development holds great importance for formulating the oil and gas resource strategy in western China. The second block of Shunbei Oil and Gas Field provides the primary production of oil and gas in this area， characterized by thick and plate-like reservoir spaces. Both field production and laboratory experiments confirmed that gravitational differentiation significantly influences the vertical distribution of fluids， thereby affecting the formulation of effective development policies. However， there is less research on quantifying gravitational differentiation. The No. 4 fault zone in the second block of Shunbei Oil and Gas Field was taken as the research objective in this paper， and high-temperature and high-pressure fluid phase experiments were conducted on production wells within this study area， along with visual phase experiments to achieve quantitative characterization of gravitational differentiation. Additionally， a component gradient theoretical model was constructed based on thermodynamics and molecular dynamics principles. Exhaustion and gas injection experiments revealed that gravity sedimentation exacerbates reverse condensation phenomena while demonstrating clear evidence of gravity overlap between dry and wet gases during injection processes. By utilizing both theoretical models derived from component gradients and experimental results， the paper successfully quantified a gravitational differentiation index and determined that the theoretical model of non-isothermal component gradients was more suitable for quantitatively characterizing the gravitational differentiation index within the study area. The results show that the influence of gravitational differentiation on light components and heavy components is more significant， but its impact on intermediate components is relatively small. With the increase in depth， the proportion of heavy components increases gradually，and condensate gas reservoirs change into volatile reservoirs. The influence of gravity on the density of condensate gas reservoirs with high molar content of heavy components is more significant. The gas injection experiment results show that the gravity overlap between dry and wet gases is obvious， and the condensate gas and dry gas show an obvious gas-gas interface. The top gas injection is dominated by gravity displacement and supplemented by diffusion mixing， while the bottom gas injection is the opposite.

Abstract:

The southwestern part of Ordos Basin is rich in oil and gas resources， and in recent years， a series of lithologic-structural reservoirs with small oil-bearing areas and high reserve abundance have been discovered in the Jurassic Yan’an Formation of the area. The reservoirs are small in scale， and their main controlling factors are unclear. To reveal the formation mechanism and main controlling factors of the Jurassic Yan’an Formation reservoirs in the Ordos Basin， this paper analyzed the characteristics of the reservoirs in the study area in terms of oil source conditions， paleo-geomorphology， structure， and reservoir and summarized the hydrocarbon accumulation modes in the southwestern part of the Ordos Basin under the control of the paleo-geomorphology by means of 3D seismic， microscopic observation， spectral test， and well logging data. At the same time， the main controlling factors of the Jurassic Yan’an Formation reservoir were discussed， including the aspects of oil source filling， unconformity and connected sands，paleo-geomorphology， structures， and reservoirs. The results showed that the source rocks of Chang 7 Member of Yanchang Formation in Ordos Basin generate hydrocarbon and discharge oil and gas. Under the effect of the residual pressure difference， the oil and gas migrate along the faults， fractures， and high-permeability sand bodies laterally and longitudinally， continuously move towards reservoirs in the overlying Jurassic Yan’an Formation， and accumulate at the high-structure position and under conditions of overlying and lateral mudstone occlusion. The Jurassic Yan’an Formation reservoirs in the southwestern Ordos Basin are characterized by late mature to high mature oil source charging， and they are lithological-structural reservoirs dominated by paleo-geomorphology and controlled by faults， fractures， and sedimentary reservoirs. The hydrocarbon accumulation modes are “paleo-river control，sandbody transport， and enrichment at high points，” and the reservoirs are horizontally distributed like a string of beads. The paper proposed a three-dimensional transport network system based on the unconformity， fractures， and high-permeability river sand bodies in the Jurassic Yan’an Formation reservoirs in the Ordos Basin， which provides a theoretical basis for the large-scale exploration and development of the Jurassic reservoirs in the Ordos Basin.

Abstract:

Zeolite is one of the essential diagenetic minerals in volcanic and feldspar-rich clastic rocks， which is of great significance in the development of clastic rock reservoirs. There have been many studies on the distribution characteristics， genesis， and reservoir control mechanisms of zeolite minerals in major basins of China， but a unified understanding has not yet been formed. According to the previous research， combined with the latest drilling data in the hinterland of Junggar Basin， this paper systematically summarized and analyzed the distribution of zeolite minerals in major basins in China and studied their genesis and reservoir control mechanisms. The distribution of zeolite minerals is mainly controlled by components such as volcanic debris and feldspar， strong hydrodynamic conditions， the composition of diagenetic fluids， temperatures and pressures， and other comprehensive conditions. They are commonly found in various waterway systems in deltas. The genesis of zeolites is complex， with volcanic material alteration，plagioclase albitization， and hydrothermalism being the leading causes. Currently， the former two are the most common in various basins. Zeolite minerals have a positive effect on the development of clastic rock reservoirs. Zeolites effectively improve the reservoir's anti-compaction ability with high hardness in the early stages， and zeolite minerals remove intergranular water and release pore space during the diagenetic period. In addition， zeolite minerals are prone to transformations under the influence of temperature，and the density difference between minerals before and after transformation increases pore space. The pore enlargement resulting from the acidic fluid dissolution is also one of the most important storage control mechanisms of zeolites.

Abstract:

The discovery of LF14 oil-bearing structure in Pearl River Mouth Basin suggests that Wenchang Formation in Lufeng Sag has significant potential for oil and gas exploration. However， exploration practice reveals that the physical properties of sand bodies in the same sedimentary facies belt vary greatly. The influence of diagenesis on the physical properties of reservoirs is not clear， which restricts the prediction of high-quality reservoirs in the study area. In order to predict the favorable zones in lowpermeability reservoirs， the diagenetic facies of sandstone reservoirs of Wenchang Formation in Lufeng Sag was studied based on thin section identification， scanning electron microscopy， X-ray diffraction， and physical property testing， along with drilling data.The favorable zones in low-permeability reservoirs in the study area were predicted by diagenetic facies delineation. The results show that reservoirs of Wenchang Formation primarily consist of quartz sandstone， which has a high degree of maturity in composition and structure. The reservoir space is characterized by interparticle dissolution pores. Four distinct diagenetic facies are identified in the study area， including moderate compaction-weak cementation-strong dissolution， strong compaction-moderate cementationmoderate dissolution， moderate compaction-strong cementation-weak dissolution， and strong compaction-moderate cementationweak dissolution. Among these facies， the moderate compaction-weak cementation-strong dissolution is the most favorable facies in the study area， with the majority of the facies occurring in the underwater distributary channels. The strong compaction-moderate cementation-moderate dissolution has the second most favorable physical properties and is mainly developed in the mouth bars. The moderate compaction-strong cementation-weak dissolution and the strong compaction-moderate cementation-weak dissolution are unfavorable diagenetic facies. Vertically， the diagenetic facies types of the reservoirs are comprehensively identified based on well logging data by utilizing petrophysical parameters and physical properties. Laterally， through the analysis of the correlation among diagenetic facies， seismic acoustic impedance， and Poisson’s ratio， it was found that the moderate compaction-weak cementationstrong dissolution and the strong compaction-moderate cementation-moderate dissolution have relatively low Poisson’s ratios，while unfavorable diagenetic facies have relatively high Poisson’s ratios. On this basis， Poisson’s ratio inversion results are used to predict the favorable zones in low-permeability reservoirs in the study area.

Abstract:

Glutenite bodies in the faulted basin exhibit a complex genetic type， resulting in highly heterogeneous reservoirs and presenting significant challenges for reservoir prediction. This study systematically investigated the lithofacies types and reservoir characteristics of glutenite bodies in the Lower Submember of the 3^rd Member of the Eocene Shahejie Formation（Es₃ ^L）of Yidong Fault Zone by comprehensively utilizing data from cores， cast thin sections， well logging， and log. It also identified favorable reservoir control factors and proposed a“ ternary control reservoir” model suitable for the glutenite reservoirs in the study area. The results show that the formation and development of favorable reservoirs of glutenite bodies in Es₃ ^L of Yidong Fault Zone are mainly controlled by the combination of sedimentary microfacies， carbonate cementation， and organic acid dissolution. Sedimentary microfacies control the macroscopic distribution of reservoirs； diagenetic cementation exacerbates reservoir heterogeneity， and acid fluid dissolution in the late stage improves reservoir quality. Tectonic activity and the continuous fluctuation of the lake level control the transformation of the sedimentary environment. There is a transition from the low-angle retrogradation type of nearshore underwater fan sedimentation to the high-angle progradation type of fan delta from bottom to top. The grain sizes of the fan delta reservoirs are moderate， and the reservoirs are well sorted， with low mud content. Original physical properties of the underwater distributary channel in the medium-thick layer are good. The differential cementation of calcite in the early diagenetic stage enhances the heterogeneity inside the reservoir， resulting in the densification of the reservoir at the bottom of some river sand bodies. In addition， oil and gas charge in the late stage has a strong effect on the dissolution and transformation of weakly cemented reservoirs in the early stage， resulting in better physical properties in the middle of single-stage river sand reservoirs. In summary， it is believed that overlapping development areas of multi-stage distributary channels on the oil and gas migration paths are favorable exploration areas.

Abstract:

Nandan-Liuzhou area of Guangxi Province is located in Guizhong Depression. The platform basin facies with the primary lithology of siliceous mudstone and the platform shelf facies with the primary lithology of calcareous mudstone are widely distributed in the area， which together constitute a set of the Devonian dark shale series. Based on the analysis of typical field profiles and geochemical data， it is concluded that the Middle Devonian source rocks mainly dominated by dark muddy shale of Luofu Formation of the Middle Devonian Series have superior shale gas accumulation conditions. The maximum thickness of the source rock can reach 600 m； the TOC value is 0.61%-3.60%； the R_o value is 2.55%-3.63%， and it is in the high to over-mature stage and has great hydrocarbon generation potential. The porosity is 1.7%-2%， and the average permeability is 0.11 mD， indicating an extremely low porosity and low permeability reservoir. Its average clay mineral content is 41.6%， and its average brittle mineral content is 59%，belonging to a high-quality shale gas reservoir. The cap rock and roof-to-floor conditions of the study area are good， and the local structural deformation is weak， offering great preservation conditions. The comprehensive study shows that the west of Huanjiang-Yizhou area is a favorable area for Devonian shale gas exploration in the study area.

Abstract:

The Rio Del Rey Basin in Cameroon develops mudstone diapirs. Due to the control of mudstone diapirs， oil and gas reservoirs of fault blocks and fault anticlines are developed in the shallow strata of the basin and enter into the middle and late stages of development. The success rate of exploratory wells in middle-deep layer S5 is low， and resource replacement is facing challenges due to poor previous research and insufficient understanding of oil and gas accumulation law. The regional sedimentation， structures，and hydrocarbon accumulation characteristics， especially the balanced profile of regional tectonic evolution， were researched，and it was found that mudstone diapirs in the Rio Del Rey Basin were derived from the thick Akata mudstones of the Paleocene series in the deep part， and their activity time began from the end of Eocene to present. It locally controlled the deposition ranges of the sand body in the front of the S5 delta in the early Miocene. Sand bodies， mudstone diapers， and associated faults were easy to form structural-lithological and fault-block traps， which were formed earlier than the oil-generating period of Akata mudstone.Mudstone diapirs and faults provided channels for oil and gas migration， and the combination of source-reservoirtransportation-accumulation was conducive to hydrocarbon accumulation around mudstone diapirs in S5. However， the reasons for the drilling failure of S5 were analyzed in the basin， and there were differences in oil and gas accumulation characteristics around mudstone diapirs. Oil and gas easily escaped upward along the activity channel of mudstone diapirs due to the long-term activity of mudstone diapirs and its penetration into S5， resulting in poor preservation conditions for the first row of structural-lithological traps directly contacting mudstone diapirs and thus making hydrocarbon accumulation difficult. Previous drilling in multiple exploratory wells on the first row of structural-lithological traps also failed. The second row of structural traps （two-step structural belt） controlled by mudstone diapirs could be trapped by updip faults， which were not affected by the later activity of mudstone diapir， and they became favorable places for oil and gas enrichment in S5. On this basis， Sinopec successively deployed two exploratory wells in the second row of structural belts from 2018 to 2023， and oil discovery reached a commercial level， which further confirmed the control effect of mudstone diapirs on middle-deep hydrocarbon accumulation in the Rio Del Rey Basin， and it proved that the twostep structural belts under the control of mudstone diapirs were favorable exploration belts in the future.

Abstract:

With the continuous deepening of business activities such as acquisitions， mergers， and equity participation in overseas oil and gas assets， oil and gas reserves have become a key consideration for oil companies. Due to the varying evaluation standards adopted by resource countries， there are significant discrepancies in the estimated reserves. Acquisition activities may involve considerable risks without a precise understanding of these data. Following the strategic cooperation agreements signed between China and the Russian Federation in recent years， oil and gas cooperation projects have been increasingly expanded. It is especially important to refine and clarify the alignment of grading and classification standards for oil and gas reserves/resources between the two countries. This paper analyzed the evaluation， comparison， and result conversion of oil and gas reserves/resources in the context of China’s oil and gas mergers and acquisitions in the Russian Federation and other countries that still adhere to the Russian Federation’s reserves evaluation criteria. It provided a detailed discussion of grading and classification standards for oil and gas reserves/resources currently implemented in both the Russian Federation and China， compared the reserve classification calculation methods and management approaches of the two countries， and identified the similarities and differences between their classification systems.The paper further analyzed the impact of differences in standards on oilfield development， resource evaluation， and technology promotion， offering guidance for professionals to understand better and apply different reserve evaluation methods in practical operations.

Abstract:

The variable flowline modification technology has been formed in the development of reservoirs with medium-high permeability and high water cut in Shengli Oilfield， which can effectively control water consumption and reduce the decline in the field. However， it still faces issues， such as different increments of enhanced oil recovery （EOR）， different effect of a single well， and short validity periods. To improve the effect of flow field regulation development in reservoirs with medium-high permeability and high water cut， theories and methods of development geology， dynamic of fluids through porous media and reservoir engineering were comprehensively applied. Based on large-scale，and visual microphysical simulation experiments， reservoir numerical simulation， and development practice of flow field regulation， a new understanding of flow field regulation mechanism was proposed， and a deep development technology system featuring“ variable flowline +，” large pressure gradient injection-production optimization， and dynamic flow field regulation was formed. The results show that the flow field regulation of reservoirs with medium-high permeability and high water cut has the characteristics of“ inheritance， redundancy， and regeneration”， which affects the flow field regulation effect. Stronger reservoir heterogeneity indicates a more obvious inheritance， which can be effectively reduced by“ bridging” to construct flowlines， expanding the swept volume. Due to the redundancy， the starting pressure threshold of the remaining oil in pores within unswept zones is high， and the displacement pressure gradient should be increased to produce the remaining oil in pores within unswept zones to improve the displacement efficiency. Due to the regeneration of the extreme water-consuming zones， it is necessary to dynamically regulate the flow field to achieve a more balanced displacement after flow field regulation. Based on the new understanding of the flow field regulation mechanism and the practice of flow field regulation development in reservoirs with medium-high permeability and high water cut， the proposed deep development technology system through flow field regulation could provide critical technical support for the efficient and long-term development of reservoirs with medium-high permeability and high water cut.

Abstract:

The oil recovery of a field development unit under the current technical and economic conditions is an essential indicator for evaluating development effects and analyzing the potential for enhancing oil recovery. It is also an essential basis for scientifically formulating medium-term and long-term plans. The dynamic and static heterogeneity of oil reservoirs significantly impacts oil recovery. The optimization of differentiated injection and production in single wells can achieve balanced injection and production in heterogeneous oil reservoirs and enhance oil recovery. Currently， the influence of dynamic and static heterogeneity is not fully considered in the existing oil recovery prediction methods， and oil recovery is difficult to accurately predict under the different injection and production conditions in single wells. In this paper， uncompartmentalized water-flooded oil reservoirs were taken as an example； the main controlling factors influencing the oil recovery of water-flooded oil reservoirs were identified by the numerical simulation technology and mathematical statistics analysis methods. The water flooding for efficiency improvement technology was proposed based on the optimization of differentiated injection and production in single wells. The orthogonal experimental design method was adopted， and the main dynamic and static influencing factors， economic policy limits， etc.， were integrated to design multiple groups of highly operable schemes for simulation. With the help of multi-factor nonlinear fitting means， the reservoir heterogeneity was fully considered to adapt to the best technical policies. Under economic condition constraints， a rapid prediction model for the economic oil recovery of water flooding oil reservoirs was constructed based on the optimization of differentiated injection and production. Field practice applications showed that this method could achieve rapid and accurate prediction of the economic oil recovery for the differentiated injection and production development of water flooding heterogeneous oil reservoirs.

Abstract:

Water flooding is one of the most important methods for reservoir development. Water flooding production contributes to over 70% of crude oil production in China. The wettability of rock surfaces is a key factor influencing the water-oil two-phase flow process and the microscopic displacement efficiency in the porous media of reservoirs. A micropore structure model of sandstone was established using computed tomography （CT） scanning technology to elucidate the influence of wettability on the flow behavior of water-oil two-phase in three-dimensional porous media. Based on Navier-Stokes equations， the immiscible flow of water-oil two-phase in microscopic three-dimensional porous media was simulated， and the level set （LS） method was used to capture the interface changes of the two-phase in real time. The results show that wettability significantly influences the microscopic displacement efficiency， fluid distribution， and flow paths of water flooding in three-dimensional porous media. When the rock surface is in a water-wet state， the injected water can rapidly mobilize and uncover the oil droplets of the porous medium. In an oil-wet state， the water tends to flow readily along the central positions of pore throats， forming film-like remaining oil. The water-oil interface is mainly affected by capillary force， viscous force， and displacement pressure in water-wet or oil-wet pore throats. Wettability and pore throat diameter affect the direction of various forces. Moderately adjusting the wettability of rock surfaces will delay the occurrence of the water flooding fingering phenomenon and enhance the microscopic displacement efficiency.

Abstract:

Chang 6 reservoir in Ordos Basin is an essential tight oil accumulation area. This paper comprehensively utilized core data， thin section identification， mercury injection， and high-precision scanning electron microscopy （SEM） and studied the reservoir characteristics in the study area from multiple aspects， including petrological properties， physical properties， pore-throat matching development characteristics， and pore structure features. On this basis， CO₂ flooding physical simulation experiments were conducted by the online nuclear magnetic resonance （NMR） at high temperatures and high pressures， and the multiple phase flow and migration behavior of crude oil were monitored during various stages of CO₂ flooding in real-time. The fluid saturation， ultimate recovery， residual oil distribution， and microscopic producing characteristics of crude oil in pores with different sizes are quantitatively studied， and the effects of injection pressures on the ultimate recoveries and recoveries of crude oil in microscopic pores are explored. The results show that the characteristics of Chang 6 reservoir in the study area are significantly different. The reservoir lithologies are mainly fine-grained feldspar sandstones and lithic feldspar sandstones， with an average porosity of 10.2% and an average permeability of 0.79 mD， predominantly low-porosity to ultra-low permeability tight reservoirs. The pore types are mainly intergranular pores， feldspar-dissolved pores， and zeolite-dissolved pores. According to the capillary pressure curve characteristics of the reservoir， Chang 6 reservoir can be divided into I， II， and III types from good to poor， with a good correlation between the pore-throat structure parameters and permeability. The crude oil in the study area is mainly stored in three types of pores （< 0.1 μm， 0.1-1 μm， and 1-10 μm）. There are differences in the microscopic production characteristics of CO₂ flooding in pores with different sizes. The recoveries of crude oil in macropores and medium pores show a gradual increase trend， while the recovery of crude oil in large and medium pores shows an increasing trend， while that in small pores shows a trend of decreasing first and then increasing. The injection pressure is positively correlated with the recovery of CO₂ flooding. High-pressure CO₂ flooding can enhance the mass transfer between oil and gas， reduce interfacial tension， and then improve the overall recovery. The research results can provide a reference for the efficient development of tight oil reservoirs in the study area.

Abstract:

The minimum miscible pressure （MMP） of CO₂ and crude oil is an important parameter for distinguishing miscible flooding from immiscible flooding of CO₂. In addition， effectively reduce the MMP of CO2 and crude oil has become a key issue for enhanced oil recovery in low-permeability reservoirs. To solve the problem that miscible flooding cannot be realized in a block of tight conglomerate reservoir in M Oilfield， Xinjiang， this paper screened the most effective demixing agent through the experimental method of core flooding and evaluated the influence of demixing agent injection on CO₂ huff-n-puff effect in cores of tight conglomerate reservoirs. The results show that the MMP of CO₂ and crude oil decreases the most when isobutyl citrate is injected， so it is selected as the best demixing agent. At the same temperature， the viscosity of the crude oil decreases as the concentration of isobutyl citrate increases； its viscosity reduction effect on oil is equivalent when the concentrations of isobutyl citrate are 0.6% and 0.8%， respectively.Based on the demixing ability and economy， the injection volume and concentration of isobutyl citrate are determined as 0.006 PV and 0.6%， respectively. The mechanism that isobutyl citrate could decrease the MMP of CO₂ and crude oil is the ability to reduce the viscosity of crude oil and promote the extraction capability of CO₂. The parameter optimization results of laboratory CO₂ huff-n-puff experiments are as follows： The optimal gas injection timing arrives when the pressure failure is 10%； the optimal gas injection volume is 0.75 PV， and the optimal shut-in duration is 15 h. The CO₂ huff-n-puff recovery increases from 12.89% without demixing agent injection to 19.36%. The optimized isobutyl citrate has an obvious effect on enhancing CO₂ huff-n-puff recovery.

Abstract:

For exploratory wells where natural gas has been discovered in new regions or for new adjustment wells in mature areas，it is essential to conduct productivity testing （also known as deliverability testing） after completing the gas test and shut-in to obtain the reservoir pressure， to determine the absolute open flow rate and inflow performance relationship （IPR） curves of the gas well.These results provide a reliable technical foundation for developing the gas reservoir development program. Internationally， methods for evaluating gas well productivity are mainly quadratic form and exponential form expressed by the squared pressure and solved by the production of the gas well and the corresponding flowing bottomhole pressure from a multi-point test （typically four points）. In this paper， the productivity equation for the pseudo-pressure of the gas well was derived based on the quadratic equation for the pressure gradient and flow velocity proposed by Forchheimer （1901） and the pseudo-pressure function proposed by Al-Hussainy （1966）. Additionally， the exponential equation of pseudo-pressure was obtained by using the correction method proposed by Rawlins （1936）. Example applications demonstrate that the evaluation results for absolute open flow rate are essentially identical using both the quadratic and exponential equations expressed in terms of pseudo-pressure.

Abstract:

In the context of carbon neutrality， brine water viscosity directly influences the CO₂-brine water two-phase flow process in the reservoir when the technology of CO₂ storage in brine water reservoirs is used to achieve carbon reduction targets. Currently，the viscosity prediction method based on the pressure effect still needs to be improved. In this study， the existing calculation methods were optimized by using the least squares method， BP neural network， and BP neural network based on a genetic algorithm.The brine water viscosity was taken as a binary function of temperature and molar concentration， as well as a ternary function of temperature， molar concentration， and pressure， respectively， and an optimized model of viscosity prediction considering the effect of pressure was established. Then， the optimal prediction was obtained， and the effect of viscosity on flow was systematically analyzed based on the level-set method of COMSOL software. The results show that the existing empirical formula could be optimized using the least squares method， but the effect is not apparent. After considering the pressure， the prediction accuracy can be improved by 45.2% using the binary BP neural network and by 57.32% using the binary BP neural network. Therefore， in the case of sufficient experimental data， reliable brine water viscosity values can be obtained in a wide range of pressures based on the BP neural network model. In the absence of the corresponding experimental data， the brine water viscosity values can be obtained by the empirical formula method because the empirical formula method can predict the trend of viscosity change. In addition， it can be found that the viscosity affects the distribution of the fluid in the flow channel through the simulation results， which in turn affects the flow velocity. A larger viscosity ratio indicates a minor fluctuation of the average velocity at the outlet and faster stability， and a larger viscosity ratio indicates smaller residual water saturation， which is more favorable for the replacement process， and the two are in a logarithmic function of the relationship.

Abstract:

The permeability of high water-cut reservoirs will change during long-term water flooding. The traditional parameters characterizing water flooding do not consider the influence of critical flow velocity when describing the time variation law of reservoir permeability. Therefore， the concept of effective cumulative water flux was put forward， and the critical flow velocity was used as the velocity limit of particle migration to correct the influence of water flux on reservoir permeability to a certain extent. The ridge evolution model of reservoir permeability changing with effective cumulative water flux was obtained by experiments and coupled with the three-dimensional two-phase oil-water flow equation. As a result， a time variation reservoir permeability flow model based on effective cumulative water flux was established. The results show that the permeability of the Berea core changes greatly even at a low displacement rate under long-term water flooding， and the critical flow velocity under high multiple water flooding （0.006 cm/s） is lower than that under normal conditions （0.015 cm/s）. By considering the effective cumulative water flux of critical flow velocity to characterize the time variation characteristics of reservoir permeability， the numerical simulation results of complex fluvial reservoir models are more consistent with the time variation characteristics of reservoir permeability caused by microparticle migration. Therefore， the effective cumulative water flux can better describe the time variation law of reservoir permeability under the influence of critical flow velocity.

Abstract:

The opening of natural fractures during water injection in fractured tight oil reservoirs can expand the swept volume of water flooding， but it also easily forms high-permeability channels. Therefore， it is crucial to understand the impact of natural fracture opening on water injection development for enhancing the effectiveness of water flooding in tight oil reservoirs. This paper presented a method that coupled the Perkins-Kern-Nordgren （PKN） model with an oil-water two-phase flow model， which utilized the embedded discrete fracture method （EDFM） to establish a numerical simulation approach of oil reservoirs for finely characterizing fracture dynamics during water flooding and compare its results with analytical solutions to verify its accuracy. The numerical simulation results indicate that the fracture propagation velocity at the well bottom exhibits a characteristic of rapid initial expansion followed by a slow-down under constant pressure water injection. The average pressure within the fracture fluctuates due to the opening and closing of fractures during water injection-induced fracture propagation. In a single-injection and single-production mode，there is a critical value for fracture propagation length； the fracture expands the swept volume of water flooding when the fracture propagation length is below the critical value. However， the fracture causes water channeling when the fracture propagation length exceeds the critical value. The proposed coupled model of fracture propagation was applied to numerical simulation studies of unstable water injection in the X low-pressure tight oil reservoir. The results suggest that unstable water injection could moderately induce fracture opening， increase the swept volume of water flooding， prevent rapid water encroachment in oil wells， and significantly improve the water flooding development effect in tight oil reservoirs.

Abstract:

Microsphere flooding technology has attracted much attention because it effectively blocks high-permeability channels and improves reservoir flow performance. Based on core flooding experiments and rheological experiments， the dispersion， oil displacement performance， long-term stability， and action mechanism of microspheres in sewage at different concentrations and pH values from Shengli Oilfield were systematically analyzed. The results show that as the concentration of sewage from Shengli Oilfield increases from 0 to 50%， the average particle size of the microspheres increases from 1.2 μm to 2.0 μm， indicating a significant deterioration in dispersion. Under different pH conditions， the average particle size of the microspheres is 2.2 μm in the sewage with a pH of 4， while it decreases to 1.3 μm， showing better dispersion in the sewage with a pH of 9. The core flooding experiments indicate that the oil displacement efficiency of the microspheres is the highest， reaching 50.3%， in sewage with high organic content from Shengli Oilfield. The long-term stability of the microspheres is poor in the sewage at a concentration of 30%， with the average particle size increasing to 2.1 μm after 28 days. The rheological experiments show that microsphere suspensions exhibit shear thickening properties， with a shear stress of 9.1 Pa at a shear rate of 1 000 s^-1. The mechanism analysis reveals that the microspheres interact with impurities and suspended particles in the sewage through electrostatic adsorption， physical adsorption， and chemical adsorption，significantly affecting their dispersion and oil displacement effects.

Abstract:

To solve the problem of unclear comparison and optimization methods for viscosity reducers in the development of chemical viscosity reduction for heavy oil， a quantitative relationship between the properties of viscosity reducers and their oil displacement efficiency was established using laboratory experiments and mathematical analysis methods. The quantitative relationship between the various properties and the oil displacement efficiency of the viscosity reducers was determined by using the linear regression method for a single-factor analysis. Based on the correlation coefficient in the regression， the main properties affecting oil displacement efficiency were clarified. Two indicators， namely oil displacement degree and oil displacement index， were proposed，and a calculation method for the oil displacement index that reflected the oil displacement efficiency was established. Research shows that the minimum emulsification speed， viscosity reduction rate， particle size of emulsion， and adsorption loss are the main properties affecting oil displacement efficiency. Dehydration rate and oil washing efficiency have a certain impact on oil displacement efficiency. In the low interfacial tension range， the influence of interfacial tension is not significant. The minimum emulsification speed， particle size of emulsion， adsorption loss， and dehydration rate are negatively correlated with oil displacement efficiency，while viscosity reduction rate and oil washing efficiency are positively correlated with oil displacement efficiency. A viscosity reducer featuring easy emulsification， high oil droplet passability after emulsification， strong anti-adsorption ability， strong flowability of emulsified crude oil， and strong stripping effect on crude oil is more likely to achieve higher oil displacement efficiency.The oil displacement index and oil displacement efficiency are linearly positively correlated， and the index can reflect the oil displacement efficiency. The rationality and practicality of the evaluation method have been verified through viscosity reduction stimulation and viscosity reduction displacement tests in the mining field.

Abstract:

In fractured-vuggy reservoirs， triple media consisting of fractures， vugs， or pores significantly affects oil and gas flow.However， traditional well testing interpretation methods have been proven to be ineffective in accurately describing the flow characteristics of the fluid. This paper introduced a numerical well testing method based on the fast marching method. This approach employed an embedded discrete fracture model to describe the triple media of fractured-vuggy reservoirs. The Eikonal equation was established to describe the fluid transmission process between different media and solved with the fast marching method. Then， the control equation under a one-dimensional diffusive time of flight coordinate system could be established. On this basis， two reservoir models were established according to the geological characteristics of different combinations of pores， fractures， and vugs： the vuggy reservoir model and the fractured-vuggy reservoir model. The results indicate that the size of vugs and their relative position to the wellbore lead to differences in the characteristics of the typical curve in vuggy reservoirs. When the vugs are connected to the wellbore， the pressure dynamic is influenced by different vug sizes， and the typical curve exhibits four distinct stages： wellbore storage， radial flow， late-time decline， and boundary flow. In contrast， when the vugs are not connected to the wellbore， the relative position of the vugs to the wellbore affects the pressure dynamic， and the typical curve experiences five stages： wellbore storage，radial flow， boundary flow， radial flow， and boundary flow. In the fractured-vuggy reservoirs， the typical curve undergoes four stages： wellbore storage， early-time decline， late-time decline， and boundary flow. The effective communication between vugs and natural fractures is a key factor that affects the productivity of oil reservoirs. Moreover， vugs serve as an advantageous space for fluid storage and have a greater impact on pressure dynamic changes during the whole production cycles of the reservoirs.Furthermore， the proposed numerical well testing method has been successfully applied to the dynamic analysis of actual reservoirs，demonstrating its applicability and effectiveness. Compared with traditional methods， this approach can more accurately characterize the fluid flow behavior in complex fractured-vuggy reservoirs， providing valuable insights for dynamic evaluation and development of similar reservoirs.