Unconventional oil and gas resources serve as vital replacement energy in China's hydrocarbon portfolio,and their efficient development is of great significance for safeguarding national energy security.The implementation of staged multi-clus-ter hydraulic fracturing in horizontal wells,along with the optimization of intra-stage cluster design parameters,is critical to maximizing the production potential of unconventional reservoirs.Clarifying fracture propagation mechanisms and quantifying the relationship between fracture geometry and well productivity is key to optimize intra-stage multi-cluster fracturing strategies.In this study,a phase-field method is employed to simulate the competitive propagation morphology of multiple fractures within a fracturing stage.A fracture morphology identification technique is integrated to construct a two-dimensional equivalent fracture model,which can characterize the stimulated flow pathways.Equivalent physical parameters after stimulation are extracted and transferred-together with geometric descriptors-as input for a discrete fracture flow model.This enables automatic coupling and data transfer between the geometric and flow models,thereby facilitating quantitative evaluation of production performance under different fracturing scenarios and ultimately achieving fully coupled fracture propagation-fluid flow simulation.The accuracy and feasibility of the dual-model coupling method are verified through comparison with laboratory-scale physical simulation experiments and field fracturing data.On this basis,the effects of intra-stage cluster number and cluster spacing on fracture morphology and production response are further investigated.The results show that,as the cluster spacing increases from 15 m to 25 m,the fracture deflection point shifts farther from the wellbore,and the tip deflection angle decreases from 30° to 24°.Meanwhile,the pressure gradient around the fracture tip is reduced,weakening the fluid driving force and significantly diminishing inter-fracture fluid interference.This change leads to a decline in peak daily oil production and stabilized production rate,with daily and cumulative oil output decreasing by 35.88%and 35.89%,respectively.In contrast,when the number of clusters per stage increases from 3 to 5,the deflection angle at the tip of the outer fractures increases from 30° to 34°,while the coverage of the induced stress field expands from 36.74%to 42.46%.This results in a higher pressure gradient surrounding the fractures,enhancing the fluid driving force and significantly improving oil mobilization.Consequently,peak daily and cumulative oil production increased by 40.49%and 45.467%,respectively.Therefore,optimizing the intra-stage cluster spacing and cluster number can effectively balance the degree of fracture interference and enhance single-well productivity,thereby improving the overall effectiveness of staged multi-cluster hydraulic fracturing in horizontal wells.

Low salinity water flooding is a new technology for enhancing oil recovery by adjusting the ion composition or con-centration of injected water.However,the applicable reservoir conditions and enhanced oil recovery mechanism of low salinity water flooding have not yet reached a consensus.In this paper,a series of laboratory experiments of wettability control-based low salinity flooding are carried out with plunger rock samples from marine carbonate reservoirs in the Middle East as the research object.Based on the theory of Derjaguin-Landau-Verwey-Overbeek theory(DLVO),an interfacial reaction model of a typical crude oil/brine/rock system is established,and the contact angle and total separation pressure are calculated simultaneously with the augmented Young-Laplace formula.The reliability of the model is verified by the literature experimental data,and the effects of ion concentration and ion type on the separation pressure curve and contact angle are clarified.The results show that in low salinity environments,the pore surface of carbonate rock is more water-wet under the action of fluid flushing,the oil displacement efficiency is higher,and the low salinity water improves the crude oil recovery by 3.2%;under the assumption of constant charge,the mathematical model established based on the DLVO theory for the crude oil/brine/rock system can accurately predict the change of contact angle;compared with the ion concentration,ion type has a greater impact on separation pressure and contact angle.Among divalent ions,Mg2+ions exhibit a more pronounced influence on wettability control compared to Ca2+ions.When the water film thickness is minimal,van der Waals force is the main force affecting the separation pressure.As the thickness of water film increases,the electric double layer force gradually becomes the main force.This study contributes to a deeper understanding of the wettability control mechanism of low salinity water flooding for enhanced oil recovery.

In order to investigate the deformation characteristic and transport behavior of oil-water micro-interface and its evolution law under different wettability conditions in water flooding,a Hele-Shaw cylindrical model has been constructed based on the N-S equation.Phase field method has been employed to track the topological deformation characteristics of oil-water micro-interface in water flooding.The effect of wettability,oil-water viscosity ratio,and capillary number on the deformation characteristic and evolution process of oil-water micro-interfaces has been studied.The simulation results show that the dynamic evolution process of oil-water micro-interfaces observed from the model surface in water flooding can be divided into four stag-es,including breakthrough,fracture,three-phase contact line intersection,and micro-interface merging.The breakthrough and fracture phenomenon of oil-water micro-interfaces can be observed repeatedly in the displacement process,and is not affected by wettability and rock particle distribution.Three-phase contact line intersection and micro-interface merging phenomenon have the similar deformation characteristics and evolution law in the vertical profile of the model,which are mainly influenced by wet-tability and rock particle distribution.Three-phase contact line intersection phenomenon occurs more frequently under water-wet condition,while the micro-interface merging phenomenon occurs more frequently under oil-wet condition.The change amplitude of displacement front decreases and then increases in water flooding as wettability changes from strong water-wet to strong oil-wet,which exhibits the piston-like displacement under weak water-wet condition.The simulation results show that the highest oil displacement efficiency is observed under weak water-wet condition,while the lowest oil displacement efficiency(61.06%)is observed under strong oil-wet condition.Moreover,as the oil-water viscosity ratio increases from 20 to 100,the occurrence rate of three-phase contact line intersection phenomenon decreases,the micro oil displacement efficiency decreases by 8.56%,and the initial displacement pressure also increases under weak water-wet and the same injected pore volume multiple condition.As the capillary number increases from 0.66×10-3 to 2.0×10-3,the occurrence rate of three-phase contact line intersection phenomenon increases,the volumes of residual oil decreases,the micro oil displacement efficiency increases by 9.36%,and the displacement pressure also decreases under weak water-wet and the same injected pore volume multiple condition.This reveals that the micro oil displacement efficiency can be significantly improved by increasing the occurrence rate of three-phase contact line intersection phenomenon under water-wet condition.The research results can enrich the micro flow mechanism in water flooding,and provide a theoretical basis for further explore and utilize the residual oil.

As a critical technical approach for shale reservoir development,dynamic imbibition displacement during the fractur-ing stage has emerged as a focal point in reservoir engineering research over recent years.In light of global energy demands and ongoing exploration of unconventional oil and gas resources,the significance of this technology in enhancing the exploitation of shale oil reservoirs cannot be overstated.However,the specific mechanisms of dynamic imbibition process in shale oil reservoirs influenced by various factors still aren't unclear,and it's difficult to accurately quantify their impact on imbibition oil production efficiency.These uncertainties significantly hinder further improvement in the development efficiency of shale oil reservoirs,lead to higher development costs and bring huge challenges to sustainable resource development. Aiming at the unclear dynamic imbibition mechanisms and action laws of shale oil reservoir,a core-scale numerical simulation model was established,and the control variable method was adopted to set up 15 simulation schemes.By these methods,the mechanisms of displacement pressure difference,capillary radius,wetting angle and oil-water viscosity of dynamic imbibition displacement effect,and the change laws of fluid seepage were revealed.The effects of displacement pressure difference,capillary radius,wetting angle,and oil-water viscosity on the effectiveness of dynamic imbibition oil recovery,and the laws of fluid seepage changes were clarified in this study.The results show that:During dynamic imbibition,as the capillary radius increase from 0.1 μm to 10 μm,capillary force decrease and fluid seepage rate accelerates,leading to 8.0%increase in imbibition recovery.Along with the displacing pressure difference increases from 0 MPa to 3 MPa,the imbibition upgrades from static to dynamic,and the imbibition recovery degree increases by 7.9%.It is considered that the displacing pressure difference and the recovery degree are in accordance with the power function relationship,and there is an optimal displacing pressure difference.With changes in rock wettability from hydrophilic to neutral or oleophilic,extraction degree decreases from 48.9%for water-wet conditions to 33.9%for oil-wet conditions.As crude oil viscosity decreases from 53.3 mPa·s to 13.99 mPa·s,imbibition recovery rate increases by 9.1%;the higher the viscosity of water phase,the smaller the initial imbibition velocity,but the better the imbibition displacement effect.In oil field operation,by optimizing injection pressure,selecting suitable fracturing fluid and surfactant,the hydrophilic degree and displacement phase viscosity can be improved,and the dynamic imbibition process can be improved to increase the oil displacement efficiency.In the future,the complexity of multiphase flows and the heterogeneity of reservoirs should be further considered to study the influence of various factors on the dynamic imbibition process of shale from different scales.

During the development of CO2 injection in low-permeability reservoirs,carbonated water formed after CO2 dissolves in water can effectively improve the imbibition effect,and thus improve the reservoir development benefit.By measuring the oil-water interfacial tension,contact angle and imbibition recovery factor,the effect of temperature and pressure on imbibition recovery in low-permeability cores under high-pressure CO2 was investigated.The results show that increasing temperature and CO2 pressure can improve oil-water interface characteristics and enhance imbibition recovery.At 8 MPa,the temperature increas-es from 20℃to 80℃,the interfacial tension increases by 2.25 mN·m-1,and the contact angle decreases by 15.2°.The influence of temperature on oil-water interface characteristics is stronger than that of CO2 solubility.With the increase of temperature,CO2 solubility decreases,but the interfacial tension increases,the hydrophilicity of rock enhances,and the fluidity of crude oil increases,so the imbibition efficiency increases.At 80℃,the pressure increases from 4 MPa to 10 MPa,the interfacial tension decreases by 3 mN·m-1,and the contact angle decreases by 18.4°.Pressure mainly affects the oil-water interface characteristics by changing the CO2 solubility in the liquid phase.With the increase of pressure,the CO2 solubility increases,the interfacial tension decreases,the hydrophilicity of rock enhances,the fluidity of crude oil also increases,so the imbibition efficiency increases effec-tively.Heating and pressurization have a certain synergistic effect on improving imbibition efficiency.Under the combined action of the two,although the interfacial tension only slightly decreases,the hydrophilicity of the rock enhances significantly,which accelerates the escape of crude oil in the matrix pore throat and effectively improves the imbibition recovery in low-permeability cores.The research results enrich the imbibition production mechanism,and can provide theoretical reference for CO2 injection development in low-permeability reservoirs.

According to the low porosity,ultra-low permeability and neutral partial oil wetting of shale reservoir,the corre-sponding microscopic model of capillary bundle is designed.The wettability of microscopic model changed by the compound system of molecular film agent(DM)and surfactant octadecyl trimethyl ammonium chloride(STAC)was studied.It is found that DM(1000mg/L)/STAC(concentration≤critical micelle concentration),the wetting modified contact angle is positively correlated with the STAC concentration,the maximum contact angle can reach 100.51°,and it is a monolayer adsorption with an average adsorption thickness of 2.064nm;Dm(1000mg/L)/STAC(concentration＞critical micelle concentration),the wetting modified contact angle is negatively correlated with the STAC concentration,and the adsorption layer is multilayer adsorption.Taking shale oil reservoir of Permian Lucaogou Formation in Jimusar sag as a feature,a capillary bundle model equivalent to pore throat diameter was etched,with radius of 5μm and depth of flow channel of 5μm.Then,through DM/STAC wetting modification,based on hydrophilic wetting and wetting modified capillary tube bundle model,the differential pressure-flow method was used to test the fluid percolation law.As a result,when the fluid flows at low speed,it is characterized by non-Darcy percolation and has a threshold pressure gradient.Moreover,the change of wettability causes the capillary force to turn,affecting the law of fluid percolation.

Rock spontaneous imbibiton is the process of wetting phase fluid within the pore space spontaneously exhausting and driving the non-wetting phase,which is one of the important mechanisms for tight reservoirs to improve recovery.Due to the complexity of porous media characteristics and fracture morphology and other factors,the researches on imbibiton and mass transfer laws between fractures and pores have not yet been fully elucidated.In this paper,based on the phase field method and fluid motion equations,a pore-scale dynamic imbibiton and suction numerical model was established to analyze the mass transfer mechanism between fractures and pores within complex pore structures and the relationship with the recovery rate.The results show that:(1)the imbibiton process mainly covers three key stages inside the pore space:rapid penetration of the fracture,interaction between the fracture and the pore space,and gradual advancement in the pore space(i.e.,repulsion process).A faster injection rate will hinder the imbibiton process,and result in more residual oil retention.(2)There is a specific critical fracture width,and when the fracture width is about 40 times the average pore size,the recovery rate will fluctuate up and down in a certain range.As the critical fracture width decreases,the positive correlation between the fracture dimensionless number and the recovery rate is shown.(3)Fracture systems of different complexity have different effects on fluid transport.As the critical fracture width decreases,the impact of different fracture complexity on fluid mobilization is different.Specifically,with the increase of fracture complexity,the wave range of imbibiton effect become larger.The decrease of crack width will exacerbate the phenomenon of oil droplet aggregation,which will significantly slow down the recovery rate and cause clogging problems in the small pore area.(4)The number increase of the system open boundaries can effectively enhance the contact area of the wetting phase,which can maximize the dynamic utilization of the pore space,and form a synergistic seepage drive mechanism.The optimal imbibiton recovery was achieved under the four-sided open(AFO)condition,while the worst recovery was achieved under the one-sided open(OEO)condition.At the same dimensionless time,TEO and OEO show higher normalized recovery rates due to the strong non-homogeneous effect of the open number of end faces and spatial distribution model,while the recovery change curves of the remaining three boundary conditions show relatively concentrated trends.

In the process of fracturing in tight reservoirs,the imbibition and displacement of crude oil in reservoir pores by fracturing fluids has gradually become a key research field of enhanced oil recovery technology.However,the production characteristics and mechanism of pore crude oil at different scales in the process of imbibition are still unclear,which seriously restricts the optimal design of fracturing fluid system and the reasonable selection of mining technology.Taking the Chang 7 member tight reservoir in the Ordos Basin as the research object,the amphoteric surfactant(EAB-40)was used as the main agent of the clean fracturing fluid system,combined with T1-T2 two-dimensional nuclear magnetic resonance and wettability test,the influence of surfactant concentration on reservoir interface properties and fracturing fluid imbibition and displacement efficiency was systematically studied,and its microscopic mechanism was revealed.The experimental results show that EAB-40 signifi-cantly enhances the capillary driving force and crude oil desorption efficiency by synergistically reducing the oil-water interfacial tension(up to the order of 10-2 mN/m)and inducing the wettability reversal(the contact angle is reduced from 147° to 57.34°).The comprehensive oil displacement effect of the fracturing fluid system is optimal when the concentration of surfactant is 0.1 wt%.During the imbibibibition process,the wettability inversion is caused by the concentration of water-wet minerals in the small pores,and the diffusion of surfactants causes the wetting inversion,which drives the crude oil to migrate efficiently from the small pores T2<1 ms to the middle(T2 is between 1 and 100 ms)and large pores T2>100 ms.Polymer molecules improve the rheological properties of the fracturing fluid system and promote the deep utilization of residual oil in bound oil and blind end pores.Realize the triple synergistic imbibibibibition mechanism of"IFT reduction-wetting inversion-viscoelastic flow control".

Shale oil is one of the most potential and strategic alternative oil resource in China.It's of great significance to clarify the fluid distribution and evolution laws in porous media for enhancing the recovery of shale oil during the fracturing-soak-ing-producing process.In this work,a multi-component multiphase lattice Boltzmann model was adopted to study the shale oil flow mechanism during fracturing-soaking-producing process.Firstly,the accuracy of the model was verified using Laplace's law,contact angle,and stratified flow.Then,based on the scanning electron microscope(SEM)image of Jiyang shale,the struc-ture of the shale porous medium was constructed including the distribution of fracture and matrix pores.Subsequently,the lattice Boltzmann model was used to simulate the fracturing-soaking-producing process of shale porous media,and the fluid distribution characteristics at different stages were analyzed.Then the effects of different soaking time,reservoir wettability and drainage rate were explored further.The results show that the fracturing fluid will seep into the matrix pore and replace the oil phase under the action of capillary force during the soaking stage,and with the increase of soaking time,the backflow rate of fracturing fluid return tends to decrease;the water-wet core has a better development effect than the neutral and oil-wet cores,and the utilization rate of fracturing fluid and the degree of crude oil utilization in the matrix are higher;the higher drainage rate will make the pore pressure drop rapidly,which is not conducive to the development and production of the shale oil.The fluid flow mechanisms during the shale oil fracturing-soaking-producing process are investigated from a pore-scale perspective,which provides support for the formulation of a reasonable production schedule for shale oil wells.

Multiphase flow in porous media is an important research topic in the field of oil and gas reservoir development.Due to the complex geological conditions in China,properties of rocks,such as permeability and porosity,are complex and hetero-geneous.The numerical solution for the complex multiphase flow problems needs to overcome challenges such as the system's multiple variables,strong nonlinearity,large computational cost,and the preservation of physical properties.For the traditional incompressible and immiscible two-phase flow model,the IMplicit Pressure Explicit Saturation(IMPES)semi-implicit scheme is a widely-used important algorithm for solving such problems,where the pressure equation is solved implicitly,and the saturation is updated explicitly.However,the traditional IMPES scheme requires the calculation of saturation gradients when updating the saturation.Therefore,it is not suitable for solving the two-phase flow problems in complex heterogeneous media.Hoteit and Firoozabadi proposed an improved IMPES method,allowing the method to reproduce discontinuous saturation in heterogeneous media.However,these two IMPES methods only update the saturation through the mass conservation equation of one phase of fluid,they cannot guarantee that the other phase of fluid also satisfies the local mass conservation property.The derivations of the pressure equations for these two IMPES methods are obtained by adding the volume conservation equations of each phase at the continuous level of partial differential equations,and then using incompletely matched spatial discretization methods for the pressure equation and the saturation equation.Therefore,it is impossible to simultaneously ensure the local mass conservation of each phase for the two-phase fluid.In this paper,based on several types of novel IMPES semi-implicit schemes for solving two-phase flow in porous media that we have published in recent years,we propose a new framework for deriving the pressure equation in IMPES.That is,we first discretize the volume conservation equation of each phase using a spatial discretization method with local conservation,and then add up the discretized volume conservation equations of each phase.In this way,a complete match in spatial discretization between the pressure equation and the saturation equation is achieved.Essentially,it overcomes the difficulty in previous literatures that the IMPES semi-implicit method cannot simultaneously ensure that both phases of the fluid satisfy local mass conservation.The novel IMPES method ensures that each phase of the fluid satisfies local mass conservation,the saturation is bounded,the computational scheme is an unbiased solution,and it is suitable for solving two-phase flow problem with different capillary pressure distributions in heterogeneous porous media.The novel phase-wise conservation IMPES framework proposed in this paper also has an advantage that the traditional IMPES does not have.That is,in the novel phase-by-phase conservation IMPES framework,it is only necessary to define the spatial discretization method of the volume conservation or mass conservation equation,and there is no need to separately define the spatial discretization method of the pressure equation.The solutions of several types of novel IMPES semi-implicit schemes that we have published in recent years can be regarded as special cases of the novel phase-by-phase conservation IMPES framework proposed in this paper.The IMPES framework in this paper can also be applied for more complex multi-component and multi-phase flow in porous media to construct more novel schemes.At the same time,through numerical examples of heterogeneous porous media,this paper verifies the effectiveness and superiority of the novel IMPES method in dealing with two-phase flow problems under complex geological conditions.Compared with the traditional method,it is more adaptable,more stable,and more efficient.

Karst-related carbonate fracture-cavity reservoirs play a vital role in global oil and gas field development.Especially under deep to ultra-deep conditions,their internal structures and filling-modification processes exhibit extreme complexity.Identifying the types and degree of fillings in paleokarst caves carries significant theoretical and practical value for evaluating effective reservoir space,optimizing development strategies,and tapping remaining oil potential.Based on an extensive review of the literature,this study proposes a systematic classification scheme for the filling phases and detrital filling phases of karst caves,highlighting key advancements in the geological understanding of internal cave filling structures.The article summarizes the current models of karst cave filling in the Tahe Area,focusing on technological progress in identifying and predicting filling materials and determining the degree of filling in paleokarst caves.Progress in identifying cave filling facies is primarily reflected in the genetic classification of modern surface cave detrital filling facies and the categorization of paleokarst cave fillings.Early methods for identifying and predicting cave filling materials and assessing filling degrees relied on qualitative and semi-quantitative approaches using logging and seismic data.With the advent of artificial intelligence(AI)technology,the application of machine learning's powerful generalization capabilities to identify and predict filling materials and degrees has emerged as a cutting-edge research direction in this field.The classification of filling modes in paleokarst caves suggests utilizing the coupling relationship between hydrogeology and cave development within the hierarchical structure framework of the paleokarst fracture-cave system.This approach,combined with the types of internal filling materials revealed by actual drilling data,facilitates the construction of filling models.However,current classifications of filling types in paleokarst caves primarily focus on differences in rock physical components,without adequately reflecting the dynamic mechanisms of filling formation.Additionally,the accuracy of identifying cave fillings remains insufficient,hindering the comprehensive determination of the sequence of fillings within caves.Currently,seismic inversion technology,commonly used for predicting cave fillings,can only estimate mud content and fails to accurately evaluate the degree of filling for all materials.Consequently,predicting the spatial distribution of filling degrees in paleokarst underground river networks requires further research and development.In light of these challenges,this article argues that leveraging AI technology to identify and predict the types and degrees of cave filling materials represents a promising trend.Future research should focus on improving the representativeness of sample sets,as well as the accuracy and generalization capabilities of prediction networks.

In response to issues such as high water cuts and simultaneous gas-water production during the development of the J58 well block in the Ordos Basin,this study evaluates the influence of various reservoir factors on movable fluids based on pore-throat size classification in tight sandstone reservoirs.This helps to clarify the gas distribution pattern from a microscopic perspective.Taking 10 typical tight sandstone cores from the Shihezi Formation as examples,casting thin section observation,scanning electron microscopy(SEM),X-ray diffraction(XRD),high-pressure mercury intrusion(HPMI),and nuclear magnetic resonance(NMR)experiments were conducted.Using multifractal theory and NMR parameter-based pore-throat distribution transformation methods,the impact of reservoir parameters on the distribution of movable fluids within pore throats of different sizes was assessed.The results show that based on the shape and parameters of mercury intrusion curves,the pore structure can be divided into three types.Type Ⅰ shows a bimodal distribution of pore-throat sizes,with good physical properties and connec-tivity;Type Ⅱ shows an unimodal distribution dominated by medium-sized pores,with good sorting,but due to limited pore-throat size,their physical properties are inferior to Type Ⅰ;Type Ⅲ have a pore-throat size distribution dominated by nanopores as the main peak and mesopores as the secondary peak,with the strongest heterogeneity in physical properties.According to the turning points in pore-throat size and fractal characteristic curves,the pore throats can be classified into mesopores(0.1～1 μm),micropores(0.01～0.1 μm),and nanopores(0.001～0.01 μm).Movable fluids are mainly found within mesopores and micropores,where the mesopores content plays a decisive role in the volume of movable fluids,while micropores,when in relatively high proportion,also have certain gas storage potential.Nanopores,however,have little impact on movable fluid distribution.The content of brittle minerals mainly affects the amount of movable fluid in mesopores,whereas clay mineral content has a negative impact on movable fluid content across all pore-throat sizes.The porosity contributed by different pore-throat sizes is positively correlated with movable fluid content;however,this correlation decreases as pore-throat size decreases due to the influence of reservoir connectivity.Permeability controls the distribution of movable fluids within pore throats of different sizes.Among pore-throat structure parameters,a higher fractal dimension negatively affects the distribution of movable fluids both overall and within pore-throats of different sizes.Owing to the limitations imposed by differing contributions of pore-throat sizes to reservoir properties,the maximum mercury saturation parameter can only be used to characterize the distribution of movable fluids within mesopores.

Shale pores serve as the primary reservoir space for shale gas,whose structural characteristics directly determine the gas occurrence state,enrichment degree,and flow mechanisms.However,the complex structure and strong heterogeneity of organic pores in shale gas reservoirs significantly constrain precise reservoir evaluation and dynamic development.To clarify the three-dimensional structural characteristics of organic pores in the Lower Paleozoic shale reservoirs in South China,this study focuses on two organic-rich shale successions in the northern Guizhou:The Lower Cambrian Niutitang Formation and the Lower Silurian Longmaxi Formation shales,which exhibit significantly different thermal maturities.An integrated approach was employed,combining organic matter extraction,low-temperature nitrogen adsorption,and focused ion beam-scanning electron microscopy(FIB-SEM)three-dimensional reconstruction techniques to systematically characterize the microstructure of organic pores in these two shale successions.Based on nitrogen adsorption and FIB data,the Frenkel-Halsey-Hill(FHH)and box-counting models were respectively applied to evaluate the complexity of organic matter pore structures across different scales.The results show that the moderately mature Longmaxi Formation shale(equivalent vitrinite reflectance Ro=2.1%～2.8%)contains well-developed organic pores,predominantly exhibiting bubble-like and sponge-like cluster morphologies with pore sizes(r)mainly ranging from 200 nm to 450 nm,along with high specific surface area(133.9～159.5 m2/g)and substantial pore volume.In contrast,the overmature Niutitang Formation shale(Ro=3.0%～3.8%)contains smaller organic pores(r=10～140?nm)with irregular or slit-shaped geometries,showing lower specific surface area(30.9～31.4 m2/g)and reduced pore volume.Three-dimensional pore network modeling further reveals distinct connectivity patterns between these two shale successions.In the Longmaxi Formation shale,organic pores are primarily isolated with poor connectivity,and large pores(r>140 nm)contribute approximately 70%of the total pore volume.The Niutitang Formation shale,however,shows enhanced connectivity among large pores(r>150 nm)through thermal-induced microfractures formed during organic matter condensation,while small pores(r<150 nm)remain largely isolated yet account for 64%of the total pore volume.Fractal dimension analysis highlights additional structural differences.The Niutitang Formation shale exhibits higher fractal dimensions for large organic matter pores(D2=2.37～2.78),indicating greater structural complexity,whereas the organic pores of the Longmaxi Formation shale display relatively regular geometries with lower fractal dimensions.These variations are mainly controlled by differences in thermal maturity.Our study provides systematic understanding of three-dimensional pore structure evolution in shales with different thermal maturities,and offers theoretical foundations for shale gas reservoir evaluation and development strategies in northern Guizhou.

Reservoir physical parameters serve as fundamental quantitative indices for characterizing the storage capacity and fluid percolation potential of subsurface reservoirs.Well logging interpretation,a critical methodology for accurately estimating these parameters,constitutes a sophisticated nonlinear regression challenge.To address the inherent limitations of existing petrophysical parameter interpretation techniques,particularly their inadequate generalization performance under few-shot learning conditions,this investigation systematically devises a dual-framework analytical approach.This study initially proposes a sample optimization methodology based on cluster analysis.The spatial configuration of samples is partitioned through the implementation of the K-means clustering algorithm,followed by selective sample curation according to spatial distribution char-acteristics to maximize learning sample diversity.Building upon this optimized sample architecture,the study further introduces a hierarchical residual neural network-based interpretation framework for petrophysical parameter estimation.The proposed methodology enhances conventional fully connected neural architecture through four innovative mechanisms:(1)Integration of cross-layer residual connections facilitates progressive refinement of residual mappings between multivariate logging inputs and target petrophysical outputs,thereby enabling hierarchical abstraction of complex petrophysical relationships from limited training instances.(2)The integration of ensemble learning paradigms amalgamates diverse machine learning methodologies,effectively mitigating overfitting risks through algorithmic diversity.(3)The implementation of a multi-task learning framework establishes intrinsic correlations between porosity and permeability interpretation tasks via shared latent representations,thereby enhancing individual task generalizability under data scarcity constraints.(4)The introduction of a quadratically weighted root mean square error loss function preferentially reduces interpretation errors in high-permeability reservoir intervals.Results from 90 rigorously designed comparative experimental configurations in the study area demonstrate that the cluster-based sample opti-mization methodology effectively enhances generalization performance across multiple machine learning models under few-shot learning constraints.Application of the proposed hierarchical residual neural network framework for well-logging interpretation of reservoir porosity and permeability within the investigated reservoir area achieves coefficients of determination of 88%and 94%,respectively,demonstrating statistically significant superiority over conventional methodologies in both petrophysical interpretation accuracy and generalization capability.Blind testing validation on cored wells reveals 12 and 20 percentage point improvements in predictive precision compared to other various existing methodologies,the proposed approach in this study demonstrates substantial advancements in addressing few-shot learning challenges through algorithm optimization strategies encompassing distribution-based sample selection and multi-task collaborative frameworks.This methodology significantly enhances feature representation fidelity in petrophysical datasets,exhibiting superior petrophysical interpretation accuracy and enhanced generalization capabilities.

Total organic carbon(TOC)content is a crucial geochemical parameter for assessing reservoir quality and hydro-carbon generation potential of source rocks.The accurate prediction of TOC content is important for optimizing the exploration and development processes of shale oil and gas.With the rapid development of artificial intelligence technologies,individual machine learning algorithms have been increasingly applied to evaluate TOC content in shale.Despite the promising results of the individual machine learning algorithms,they are often subject to several challenges including overfitting,underfitting,and getting trapped in local optima of objective function.To address these limitations,the ensemble learning models are developed.Ensemble learning models leverage the strengths of multiple individual intelligent algorithms to enhance prediction accuracy and stability.Among them,combination strategy is one of the key factors in optimizing the ensemble learning models.Arithmetic average method as the simplest combination strategy fails to fully use prediction performance of the best individual intelligent model,and it can be severely affected by the individual intelligent model with a large prediction error,which can interfere with prediction outcome of overall model.In comparison,weighted summation method as a common combination strategy assigns the weights to different individual intelligent models according to their performance on training data.This method will perform excellently on training set,but it tends to have a poor performance when applied to test set.This paper develops an ensemble model based on an intelligent matching technology(IMTEM).The proposed method utilizes a set of robust intelligent algorithms including extreme gradient boosting,random forest,support vector machine,and extreme learning machine as algorithm modules to initially process input data.Then,the processed feature information combined with original log responses is fed to feedforward neural network layer for nonlinear transformation and feature learning,thereby enabling accurate and continuous estimation of TOC content in shale.To validate effectiveness of the IMTEM,the proposed method is applied to the prediction of TOC content in the Longmaxi Formation shale in the Sichuan Basin.Test results indicate that,compared to two ensemble models,five baseline models,and the ΔlogR method,predictions of the IMTEM exhibit higher consistency with measured TOC content.This demonstrates that the IMTEM is more suitable for predicting TOC content in shale.

To address the challenges of the oil-based drilling fluid system's deteriorating rheological properties and insufficient plugging pressure resistance under high-low temperature cycling conditions in the Yaha gas storage reservoir drilling,a tempera-ture-sensitive high-temperature thickener,RHT,was developed.Optimized plugging materials and supporting agents were selected to construct a high-temperature resistant oil-based drilling fluid system.Characterization methods,including infrared spectroscopy,nuclear magnetic resonance hydrogen spectra,thermogravimetric analysis,and differential scanning calorimetry(DSC),were used to analyze RHT's molecular structure,thermal stability,and temperature-sensitive characteristics in depth.The systematic evaluation of its rheological control in emulsions and oil-based drilling fluids was conducted.Experimental results showed that RHT significantly improved the shear-thinning and thixotropic properties of the emulsion,demonstrating excellent rheological control capabilities under high-low temperature cycling conditions.At 80℃,the dynamic yield stress increased by 87%without any increase in plastic viscosity;at 220℃,the dynamic yield stress increased by 220%,with a dynamic plastic ratio of 0.49 Pa/(mPa·s).The drilling fluid system maintained strong rock-carrying capacity after aging at 220℃and effectively sealed 20～40 mesh sand beds and 1～3 mm cracks,achieving a maximum pressure resistance of 8 MPa.In the field application of the Yaha gas storage reservoir well X,this system significantly enhanced the rock-carrying and plugging performance of the drilling fluid,reducing complexities such as fluid loss and stuck pipe incidents,thereby providing strong technical support for the efficient development of the Yaha gas storage reservoir.