Micromechanism and mathematical model of stress sensitivity in tight reservoirs of binary granular medium

Research on reservoir rock stress sensitivity has traditionally focused on unary granular structures,neglecting the binary nature of real reservoirs,especially tight reservoirs.Understanding the stresssensitive behavior and mathematical characterization of binary granular media remains a challenging task.In this study,we conducted online-NMR experiments to investigate the permeability and porosity evolution as well as stress-sensitive control mechanisms in tight sandy conglomerate samples.The results revealed stress sensitivity coefficients between 0.042 and 0.098 and permeability damage rates ranging from 65.6%to 90.9%,with an average pore compression coefficient of 0.0168—0.0208 MPa 1.Pore-scale compression occurred in three stages:filling,compression,and compaction,with matrix pores playing a dominant role in pore compression.The stress sensitivity of binary granular media was found to be influenced by the support structure and particle properties.High stress sensitivity was associated with small fine particle size,high fines content,high uniformity coefficient of particle size,high plastic deformation,and low Young's modulus.Matrix-supported samples exhibited a high irreversible permeability damage rate(average=74.2%)and stress sensitivity coefficients(average=0.089),with pore spaces more slit-like.In contrast,grain-supported samples showed low stress sensitivity coefficients(average=0.021)at high stress stages.Based on the experiments,we developed a mathematical model for stress sensitivity in binary granular media,considering binary granular properties and nested interactions using Hertz contact deformation and Poiseuille theory.By describing the change in activity content of fines under stress,we characterized the non-stationary state of compressive deformation in the binary granular structure and classified the reservoir into three categories.The model was applied for production prediction using actual data from the Mahu reservoir in China,showing that the energy retention rates of support-dominated,fill-dominated,and matrix-controlled reservoirs should be higher than 70.1%,88%,and 90.2%,respectively.

Numerical Simulation of Oil-Water Two-Phase Flow in Low Permeability Tight Reservoirs Based on Weighted Least Squares Meshless Method

In response to the complex characteristics of actual low-permeability tight reservoirs,this study develops a meshless-based numerical simulation method for oil-water two-phase flow in these reservoirs,considering complex boundary shapes.Utilizing radial basis function point interpolation,the method approximates shape functions for unknown functions within the nodal influence domain.The shape functions constructed by the aforementioned meshless interpolation method haveδ-function properties,which facilitate the handling of essential aspects like the controlled bottom-hole flow pressure in horizontal wells.Moreover,the meshless method offers greater flexibility and freedom compared to grid cell discretization,making it simpler to discretize complex geometries.A variational principle for the flow control equation group is introduced using a weighted least squares meshless method,and the pressure distribution is solved implicitly.Example results demonstrate that the computational outcomes of the meshless point cloud model,which has a relatively small degree of freedom,are in close agreement with those of the Discrete Fracture Model(DFM)employing refined grid partitioning,with pressure calculation accuracy exceeding 98.2%.Compared to high-resolution grid-based computational methods,the meshless method can achieve a better balance between computational efficiency and accuracy.Additionally,the impact of fracture half-length on the productivity of horizontal wells is discussed.The results indicate that increasing the fracture half-length is an effective strategy for enhancing production from the perspective of cumulative oil production.

Experimental study on the degree and damage-control mechanisms of fuzzy-ball-induced damage in single and multi-layer commingled tight reservoirs

Fuzzy-ball working fluids(FBWFs)have been successfully applied in different development phases of tight reservoirs.Field reports revealed that FBWFs satisfactorily met all the operational and reservoir damage control requirements during their application.However,the damage-control mechanisms and degree of formation damage caused by fuzzy-ball fluids have not been investigated in lab-scale studies so far.In this study,the degree of fuzzy-ball-induced damage in single-and double-layer reservoirs was evaluated through core flooding experiments that were based on permeability and flow rate indexes.Additionally,its damage mechanisms were observed via scanning electron microscope and energy-dispersive spectroscopy tests.The results show that:(1)For single-layer reservoirs,the FBWF induced weak damage on coals and medium-to-weak damage on sandstones,and the difference of the damage in permeability or flow rate index on coals and sandstones is below 1%.Moreover,the minimum permeability recovery rate was above 66%.(2)For double-layer commingled reservoirs,the flow rate index revealed weak damage and the overall damage in double-layer was lower than the single-layer reservoirs.(3)There is no significant alteration in the microscopic structure of fuzzy-ball saturated cores with no evidence of fines migration.The dissolution of lead and sulfur occurred in coal samples,while tellurium in sandstone,aluminum,and magnesium in carbonate.However,the precipitation of aluminum,magnesium,and sodium occurred in sandstone but no precipitates found in coal and carbonate.The temporal plugging and dispersion characteristics of the FBWFs enable the generation of reservoir protection layers that will minimize formation damage due to solid and fluid invasion.

Genesis and microscopic characteristics of tight reservoirs in the Fengcheng Formation, at the southern margin of the Mahu Sag

The tight reservoirs of the Fengcheng Formation at the southern margin of the Mahu Sag have strong heterogeneity due to the diversity in their pore types, sizes, and structures. The microscopic characteristics of tight reservoirs and the mechanisms that generate them are of significance in identifying the distribution of high-quality reservoirs and in improving the prediction accuracy of sweet spots in tight oil reservoirs. In this paper, high-pressure mercury intrusion (HPMI) and nuclear magnetic resonance (NMR) experiments were carried out on samples from the tight reservoirs in the study area. These experimental results were combined with cluster analysis, fractal theory, and microscopic observations to qualitatively and quantitatively evaluate pore types, sizes, and structures. A classification scheme was established that divides the reservoir into four types, based on the microstructure characteristics of samples, and the genetic mechanisms that aided the development of reservoir microstructure were analyzed. The results show that the lower limit for the tight reservoir in the Fengcheng Formation is Φ of 3.5% and K of 0.03 mD. The pore throat size and distribution span gradually decrease from Type I, through Type II and Type III reservoirs to non-reservoirs, and the pore type also evolves from dominantly intergranular pores to intercrystalline pores. The structural trend shows a decrease in the ball-stick pore-throat system and an increase in the branch-like pore-throat system. The dual effects of sedimentation and diagenesis shape the microscopic characteristics of pores and throats. The sorting, roundness, and particle size of the original sediments determine the original physical properties of the reservoir. The diagenetic environment of ‘two alkalinity stages and one acidity stage’ influenced the evolution of pore type and size. Although the cementation of authigenic minerals in the early alkaline environment adversely affected reservoir properties, it also alleviated the damage of the later compaction to some extent. Dissolution in the mid-term acidic environment greatly improved the physical properties of this tight reservoir, making dissolution pores an important reservoir space. The late alkaline environment occurred after large-scale oil and gas accumulation. During this period, the cementation of authigenic minerals had a limited effect on the reservoir space occupied by crude oil. It had a more significant impact on the sand bodies not filled with oil, making them function as barriers.

Evaluation of hydraulic fracturing of horizontal wells in tight reservoirs based on the deep neural network with physical constraints

Accurate diagnosis of fracture geometry and conductivity is of great challenge due to the complex morphology of volumetric fracture network. In this study, a DNN (deep neural network) model was proposed to predict fracture parameters for the evaluation of the fracturing effects. Field experience and the law of fracture volume conservation were incorporated as physical constraints to improve the prediction accuracy due to small amount of data. A combined neural network was adopted to input both static geological and dynamic fracturing data. The structure of the DNN was optimized and the model was validated through k-fold cross-validation. Results indicate that this DNN model is capable of predicting the fracture parameters accurately with a low relative error of under 10% and good generalization ability. The adoptions of the combined neural network, physical constraints, and k-fold cross-validation improve the model performance. Specifically, the root-mean-square error (RMSE) of the model decreases by 71.9% and 56% respectively with the combined neural network as the input model and the consideration of physical constraints. The mean square error (MRE) of fracture parameters reduces by 75% because the k-fold cross-validation improves the rationality of data set dividing. The model based on the DNN with physical constraints proposed in this study provides foundations for the optimization of fracturing design and improves the efficiency of fracture diagnosis in tight oil and gas reservoirs.

Revolutionizing Tight Reservoir Production: A Novel Dual-Medium Unsteady Seepage Model for Optimizing Volumetrically Fractured Horizontal Wells

This study presents an avant-garde approach for predicting and optimizing production in tight reservoirs,employing a dual-medium unsteady seepage model specifically fashioned for volumetrically fractured horizontal wells.Traditional models often fail to fully capture the complex dynamics associated with these unconventional reservoirs.In a significant departure from these models,our approach incorporates an initiation pressure gradient and a discrete fracture seepage network,providing a more realistic representation of the seepage process.The model also integrates an enhanced fluid-solid interaction,which allows for a more comprehensive understanding of the fluid-structure interactions in the reservoir.This is achieved through the incorporation of improved permeability and stress coupling,leading to more precise predictions of reservoir behavior.The numerical solutions derived from the model are obtained through the sophisticated finite element method,ensuring high accuracy and computational efficiency.To ensure the model’s reliability and accuracy,the outcomes were tested against a real-world case,with results demonstrating strong alignment.A key revelation from the study is the significant difference between uncoupled and fully coupled volumetrically fractured horizontal wells,challenging conventional wisdom in the field.Additionally,the study delves into the effects of stress,fracture length,and fracture number on reservoir production,contributing valuable insights for the design and optimization of tight reservoirs.The findings from this study have the potential to revolutionize the field of tight reservoir prediction and management,offering significant advancements in petroleum engineering.The proposed approach brings forth a more nuanced understanding of tight reservoir systems and opens up new avenues for optimizing reservoir management and production.

Pore Characteristics of the Fine-Grained Tight Reservoirs in the Yabulai Basin, Northwestern China

This work investigated the pore structure characteristics and reservoir features of the finegrained tight reservoirs in the lower member of the Xinhe Formation(J2x1) in the Xiaohu subsag,Yabulai Basin based on core samples through various techniques. Interbedded silt/fine sandstones and mudstones are developed in the study area. Scanning electron microscopy(SEM) images were used to delineate different types of pores, including primary intergranular pores, secondary intergranular and intragranular pores, organic pores and fractures. The pore types were distinguished by pore size, pore area, location and formation process. The pore radii of the fine-grained rocks range from 1 nm to 1.55μm, mainly concentrated between 5 and 300 nm by low pressure N2adsorption and MICP analyses. The pore structure parameters of pore throat size and pore throat sorting coefficient are both positively correlated with porosity, while pore throat sorting coefficient has a negative correlation with permeability. The pore structures of the studied samples are much related to the mineral type and content and grain size, followed by TOC content. In these rocks with relatively low TOC and low maturity, the rigid minerals protect pores with pressure shadow from collapse, and dissolution-related pores contribute a lot to inorganic porosity. In contrast, these rocks with abundant TOC contain a large number of organic pores. The permeability of the fine-grained tight reservoir is mainly dominated by larger pore throats, while a large number of small pores(mostly <0.1 μm) contribute considerably to porosity. These results have deepened our understanding of the interbedded fine-grained tight reservoirs and can be applicable to fine-grained reservoirs in a similar setting.

Experimental Investigation on the Pressure Propagation Mechanism of Tight Reservoirs

Low permeability tight sandstone reservoirs have a high filtrational resistance and a very low fluid flow rate.As a result,the propagation speed of the formation pressure is low and fluid flow behaves as a non-Darcy flow,which typically displays a highly non-linear behavior.In this paper,the characteristics and mechanism of pressure propagation in this kind of reservoir are revealed through a laboratory pressure propagation experiment and through data from an actual tight reservoir development.The main performance mechanism is as follows:A new pressure cage concept is proposed based on the pressure variation characteristics of the laboratory experiments.There are two methods of energy propagation in the actual water injection process:one is that energy is transmitted to the deep reservoir by the fluid flowing through the reservoir,and the other is that energy is transmitted by the elasticity of the reservoir.For one injection well model and one production well model,the pressure distribution curve between the injection and production wells,as calculated by the theoretical method,has three section types,and they show an oblique“S”shape with a straight middle section.However,the actual pressure distribution curve is nonlinear,with an obvious pressure advance at the front.After the injection pressure increases to a certain level,the curve shape is an oblique and reversed“S”shape.Based on the research,this paper explains the deep-seated reasons for the difference in pressure distribution and proposes that it is an effective way to develop low permeability tight reservoirs using the water injection supplement energy method.

Numerical investigation of refracturing with/without temporarily plugging diverters in tight reservoirs

Refracturing is an importa nt technique to tap the potential of reservoirs and boost production in depleted oil and gas fields.However,fracture propagation during refracturing,including both conventional refracturing and temporary-plugging refracturing remains poorly understood,especially for cases with non-uniform distribution of formation pressure due to long-term oil production and water injection.Therefore,taking pilot tests of refracturing with sidetracking horizontal wells in tight reservoirs in the Changqing Oilfield,China as an example,we establish a three-dimensional numerical model of conventional refracturing and a numerical model of temporary-plugging refracturing based on the discrete lattice method.Non-uniform distributions of formation pressure are imported in these models.We discuss the effects of key operating parameters such as injection rate,cluster spacing,and number of clusters on the propagation of multi-cluster fractures for conventional refracturing.For temporaryplugging refracturing,we examine the impacts of controlling factors such as the timing and number of temporary plugging on fracture propagation.In addition,we analyze a field case of temporaryplugging refracturing using well P3 in the Changqing Oilfield.The results show that fractures during re fracturing tend to propagate preferentially and dominantly in the depleted areas.Improved stimulation effect can be obtained with an optimal injection rate and a critical cluster spacing.The proposed model of temporary-plugging refracturing can well describe the temporary plugging of dominant existingfractures and the creation of new-fractures after fracturing fluid is forced to divert into other clusters from previous dominant clusters.Multiple temporary plugging can improve the balanced propagation of multi-cluster fractures and obtain the maximum fracture area.The established numerical model and research results provide theoretical guidance for the design and optimization of key operating parameters for refracturing,especially for temporary-plugging refracturing.

Techniques for improving fracture-controlled stimulated reservoir volume in ultra-deep fractured tight reservoirs: A case study of Kuqa piedmont clastic reservoirs, Tarim Basin, NW China

Based on analysis of the reasons for low efficiency and low production after fracturing of some wells in the ultra-deep fractured tight reservoirs of the Kuqa piedmont zone, Tarim Basin and the matching relationship between the in-situ stress field and natural fractures, technological methods for creating complex fracture networks are proposed. Through theoretical study and large-scale physical simulation experiments, the mechanical conditions for forming complex fracture network in the Kuqa piedmont ultra-deep reservoirs are determined. The effectiveness of temporary plugging and diversion, and multi-stage fracturing to activate natural fractures and consequently realize multi-stage diversion is verified. The coupling effect of hydraulic fractures and natural fractures activating each other and resulting in "fracture swarms" is observed. These insights provide theoretical support for improving fracture-controlled stimulated reservoir volume(FSRV) in ultra-deep tight reservoirs. In addition, following the concept of volume fracturing technology and based on the results of fracture conductivity experiments of different processes, fracturing technologies such as multi-stage fracture-network acid fracturing, "multi-stage temporary plugging + secondary fracturing", fracturing of multiple small layers by vertically softness-and-hardness-oriented subdivision, and weighted-fluid refracturing are proposed to increase the FSRV. New environment-friendly weighted-fluid with low cost and new fracturing fluid system with low viscosity and high proppant-carrying capacity are also developed. These techniques have achieved remarkable results in field application.

Advances and challenges in hydraulic fracturing of tight reservoirs: A critical review

The hydraulic fracturing technology has been widely utilized to extract tight resources.Hydraulic frac-turing involves rock failures,complex fracture generation,proppant transport and fracture closure.All these behaviors affect the productivity of fractured wells.In this work,the advances and challenges in hydraulic fracturing development of tight reservoirs are summarized from following aspects:the hy-draulic fracture propagation,the proppant transport and distribution in hydraulic fractures,the calcu-lation of hydraulic fracture conductivity,and productivity and/or pressure analysis model of multi-stages fractured horizontal wells.Current fracture propagation simulation methods generate only limited propagation paths and cannot truly reflect the complexity of the propagation.The current proppant migration and distribution research is mainly focused on indoor experimental studies of proppant migration in a single fracture or branched fracture,and simulation studies on proppant migration and distribution in a small-scale single slab fracture.Whereas fractures formed after hydraulic fracturing in tight reservoirs are generally complicated.There is a lack of models for calculating complex fracture conductivity that take into consideration the effect of proppant placement and proppant distribution in fractures,fracture surface roughness and dissolution,diffusion,deposition,elastic embedding,and creep caused by stress.The productivity models of fractured horizontal wells are mostly conducted based on the original reservoir fluid saturation and pressure distribution.Most of the studies are focused only on one aspect of the fracturing process.Predications of well performance after fracturing based on these studies are often inconsistent with actual field data.The paper also discusses the future research di-rections of fracturing in tight reservoirs and the results may be used to promote the development of tight reservoirs.

Pore and fracture characteristics of Cretaceous tight reservoir and its control effect on hydrocarbon accumulation in the Liuhe Basin

Tight oil and gas in the Cretaceous has been found in the Liuhe Basin,but the rules of tight reservoir and oil and gas accumulation are not clear.This paper discusses the developmental characteristics and evolution law of pores and fractures in the Cretaceous tight reservoir in the Liuhe Basin,and reveals its controlling effect on tight oil and gas accumulation.The results show that intercrystalline pores,intergranular pores and dissolution pores are scattered and only developed in shallow tight reservoirs,while microfractures are developed in both shallow and deep layers,which are the main type of reservoir space in the study area.The results of mercury intrusion porosimetry and nitrogen gas adsorption show that with the increase of depth,the proportion of macropores(microcracks)increases,while the proportion of micropores decreases.There are two stages of microfractures developed in the study area,corresponding to the initial fault depression stage from late Jurassic to early late Cretaceous and compressional uplift at the end of late Cretaceous.According to the principle of“inversion and back-stripping method”,combined with the data of optical microscopy and inclusions,the time of each key diagenesis and its contribution to porosity are revealed,and the porosity evolution history of reservoirs in different diagenetic stages is quantitatively restored.The porosity reduction rate of compaction can reach more than 80%,which is the main reason for reservoir densification.The relationship between pore evolution history and oil and gas accumulation history reveals that during the oil and gas filling period of the Xiahuapidianzi Formation(90-85 Ma),the reservoir porosity is only 1.15%,but the development of microfractures in the first stage of the reservoir is conducive to oil and gas accumulation.

Prestack forward modeling of tight reservoirs based on the Xu-White model

Inversion methods for conventional reservoirs cannot be used in tight reservoirs because of small differences in wave impedance between tight reservoirs and surrounding rocks. Tight reservoirs in westem China are characterized by strong heterogeneity; thus, it is difficult to predict favorable zones using conventional reservoir inversion methods. In this study, we propose an inversion method based on the Xu-White model. First, we modify the test parameters of the Xu-White model until model P- and S-wave velocities and density values agree with well-logging data. Then, we calculate P- and S-wave velocities, density, and Poisson ratio for different lithologies and oil saturation and construct different geological models for interbedded sand and shale. Subsequently, we use approximations to Zoeppritz equations to perform prestack forward modeling and analyze the response characteristics of prestack gathers for different physical properties, lithology, and oil saturation. We analyze the response of thirteen types of elastic parameters to porosity, clay content, and oil saturation. After the optimization of the real prestack gathers in the Z area of western China, we select an elastic parameter that is the most sensitive to lithology and oil saturation to predict the distribution of oil-producing reservoirs with high accuracy.

Pore throat structure and classification of Paleogene tight reservoirs in Jiyang depression,Bohai Bay Basin,China

The pore throat structure characteristics of Paleogene tight sandstone and sandy conglomerate in the Jiyang depression are studied using cast thin section,conventional mercury injection,constant rate mercury injection and micro CT scanning data,and a reservoir classification scheme based on pore throat structure parameters is established.The material composition and structural characteristics of tight reservoirs are analyzed by casting thin section data.The pore throat structure characteristics of tight reservoirs are studied by conventional mercury injection,constant rate mercury injection and micro CT scanning.Ten pore throat structure parameters are analyzed by cluster analysis.Based on the classification results and oil test results,the classification scheme of Paleogene tight reservoirs is established.The Paleogene tight reservoirs in the Jiyang depression have the characteristics of macropores and microthroats,with pores in micron scale,throats in nano-submicron scale,and wide variation of ratio of pore radius to throat radius.The permeability of the tight reservoir is controlled by throat radius,the smaller the difference between pore radius and throat radius,and the more uniform the pore throat size,the higher the permeability will be.The lower limits of average pore throat radius for the tight sandstone and tight sandy conglomerate to produce industrial oil flow without fracturing are 0.6μm and 0.8μm,respectively.Reservoirs that can produce industrial oil flow only after fracturing have an average pore-throat radius between 0.2-0.6μm,and reservoirs with average pore throat radius less than 0.2μm are ineffective reservoirs under the current fracturing techniques.Different types of tight sandstone and sandy conglomerate reservoirs are classified and evaluated,which are well applied in exploratory evaluation.

Characteristics and classification of paleozoic tight reservoirs in the central uplift of the South Yellow Sea Basin

Several sets of Paleozoic tight reservoirs are developed in the Central Uplift of the South Yellow Sea Basin.A qualitative analysis of the microscopic pore structure of the tight reservoir rocks was carried out through cast thin slice and scanning electron microscopic image observation.Based on reservoir pet-rophysical properties,thirty core samples in the Central Uplift of the South Yellow Sea Basin were selected for high-pressure mercury intrusion(HPMI)analysis,which was then combined with fractal calculation to classify and evaluate the tight reservoirs.The analysis of the HPMI curves and related parameters shows that the Paleozoic tight reservoirs can be divided into three types:Type-A,Type-B and Type-C.Type-A sandstone reservoirs contain pores with size mostly ranging between 0.01 and 0.1 mm,followed by pores with size range of 0.001-0.01 m m,and relatively fewer pores larger than 0.1 m m.The Type-B reservoirs are carbonate rocks with extremely heterogeneous pore size distribution,which is closely related to the development of dissolution pores and microfractures.Type-C sandstone reservoirs are dominated by nanopores and submicron pores that distribute more heterogeneously than pores in Type-A reservoirs.The pore distribution in sandstone reservoirs shows significant fractal characteristics and is closely related to the pore size.The heterogeneity of nanopore distribution has a negative cor-relation with porosity and median pressure and a relatively weak correlation with permeability.Our study has important implications for petroleum exploration in the South Yellow Sea Basin.

Analysis on the influencing factors of imbibition and the effect evaluation of imbibition in tight reservoirs

To exert the imbibition between cracks and matrix effectively and enhance the development effect of tight oil reservoirs, a physical simulation method for imbibition in different scales of cores is developed by combining a high-pressure large-model physical simulation system and nuclear magnetic resonance technology(NMR) to investigate the influencing factors of imbibition process in tight reservoirs, and construct a quantitative evaluation method for the imbibition in water flooding. The results show that in the process of counter-current imbibition, the lower the permeability, the later the oil droplet precipitation, the longer the imbibition equilibrium time, and the lower the recovery degree. Fractures can effectively expand the area of imbibition and the front edge of imbibition in the contact between the dense matrix and water, reduce the resistance of oil discharge, and improve the imbibition speed and the degree of recovery. The more hydrophilic the rock, the higher the imbibition rate and imbibition recovery of tight rocks. In the process of co-current imbibition, the lower the permeability, the more obvious the imbibition, and the displacement recovery is positively correlated with permeability, while the imbibition recovery is negatively correlated with the permeability. It also shows that the imbibition distance of the cyclic water injection is greater than that of the counter-current imbibition, and the higher the permeability and the injection multiple, the longer the imbibition distance. The combination of large-scale volume fracturing with changing reservoir wettability and cyclic water injection is conducive to improving the imbibition ability of tight reservoirs.

Stress sensitivity of tight reservoirs during pressure loading and unloading process

Laboratory experiments were conducted on laboratory-made tight cores to investigate the stress-dependent permeability hysteresis of tight reservoirs during pressure loading and unloading process. Based on experiment results, and Hertz contact deformation principle, considering arrangement and deformation of rock particles, a quantitative stress dependent permeability hysteresis theoretical model for tight reservoirs was established to provide quantitative analysis for permeability loss. The model was validated by comparing model calculated results and experimental results. The research results show that during the early pressure-loading period, structural deformation and primary deformation worked together, rock permeability reduced dramatically with increasing effective stress. When the effective stress reached a certain value, the structural deformation became stable while the primary deformation continued; the permeability variation tended to be smooth and steady. In the pressure unloading process, the primary deformation recovered with the decreasing effective stress, while the structural deformation could not. The permeability thus could not fully recover, and the stress-dependent hysteresis was obvious.

Experimental analysis of matrix moveable oil saturation in tight sandstone reservoirs of the south Ordos Basin,China

Tight oil reservoirs in the south Ordos Basin are characterized by fractured,heterogeneous oil-bearing strata(an oil saturation of less than 55%on average),normal pressure(0.8±)and extra-low permeability(less than 0.3 mD).In the Chang 8 tight sandstone reservoir in Honghe oilfield,micro-and nanopores,especially those with a pore-throat radius of less than 1 mm,account for more than 90%.Fluid flow in the matrix is non-linear and crude oil flow rates are very low under normal pressure gradients.An improved understanding of oil mobility in a tight matrix is key to further development of normalpressure tight-oil resources in the continental basin.In this study,constant-velocity and high-pressure mercury injection experiments were conducted using samples of typical tight sandstone cores obtained from the south of Ordos Basin.A new method for reconstructing the full-scale pore-throat distribution characteristics of tight sandstone reservoirs was established successfully,based on which multistage centrifugal tests,tests of low-pressure differential displacement of oil by water,and nuclear magnetic resonance tests were conducted in order to obtain the distribution characteristics of moveable fluid in different pores.The moveable oil saturation(MOS)and degree of oil recovery(i.e.ratio of accumulative oil production to producing geologic reserves)of the core samples under different differential pressures for displacement were determined.As for the tight oil reservoirs in the south Ordos Basin,the moveable fluids are mainly stored in sub-micron(0.10-0.5 mm)pores.For Type I reservoirs(k>0.1 mD),the volume percentage of moveable fluid in pores with a radius larger than 0.5 mm is relatively high(greater than 40%).The degree of oil recovery of water flooding serves as the basis for forecasting recoverable reserves for tight oil reservoirs.Recoverable reserves under water flooding,mainly occur in pores with a radius greater than 0.5 mm.The contribution of Type I reserves to oil production is observed to be greater than 60%,and the degree of oil recovery reaches up to 17.1%.These results help improve our understanding on the evaluation and classification of Chang 8 tight sandstone reservoirs in Honghe oilfield and serve as theoretical basis for pilot tests to explore effective injection media and development methods to improve the matrix-driven pressure differences and displacement efficiency for oil.

The effects of various factors on spontaneous imbibition in tight oil reservoirs

Slickwater fracturing fluids have gained widespread application in the development of tight oil reservoirs. After the fracturing process, the active components present in slickwater can directly induce spontaneous imbibition within the reservoir. Several variables influence the eventual recovery rate within this procedure, including slickwater composition, formation temperature, degree of reservoir fracture development, and the reservoir characteristics. Nonetheless, the underlying mechanisms governing these influences remain relatively understudied. In this investigation, using the Chang-7 block of the Changqing Oilfield as the study site, we employ EM-30 slickwater fracturing fluid to explore the effects of the drag-reducing agent concentration, imbibition temperature, core permeability, and core fracture development on spontaneous imbibition. An elevated drag-reducing agent concentration is observed to diminish the degree of medium and small pore utilization. Furthermore, higher temperatures and an augmented permeability enhance the fluid flow properties, thereby contributing to an increased utilization rate across all pore sizes. Reduced fracture development results in a lower fluid utilization across diverse pore types. This study deepens our understanding of the pivotal factors affecting spontaneous imbibition in tight reservoirs following fracturing. The findings act as theoretical, technical, and scientific foundations for optimizing fracturing strategies in tight oil reservoir transformations.

Impacts of proppant distribution on development of tight oil reservoirs with threshold pressure gradient

Field evidence indicates that proppant distribution and threshold pressure gradient have great impacts on well productivity.Aiming at the development of unconventional oil reservoirs in Triassic Chang-7 Unit,Ordos Basin of China,we presented an integrated workflow to investigate how(1)proppant placement in induced fracture and(2)non-linear flow in reservoir matrix would affect well productivity and fluid flow in the reservoir.Compared with our research before(Yue et al.,2020),here we extended this study into the development of multi-stage fractured horizontal wells(MFHWs)with large-scale complicated fracture geometry.The integrated workflow is based on the finite element method and consists of simulation models for proppant-laden fluid flow,fracture flow,and non-linear seepage flow,respectively.Simulation results indicate that the distribution of proppant inside the induced cracks significantly affects the productivity of the MFHW.When we assign an idealized proppant distribution instead of the real distribution,there will be an overestimation of 44.98%in daily oil rate and 30.63%in cumulative oil production after continuous development of 1000 days.Besides,threshold pressure gradient(TPG)also significantly affects the well performance in tight oil reservoirs.If we simply apply linear Darcy’s law to the reservoir matrix,the overall cumulative oil production can be overrated by 77%after 1000 days of development.In general,this research provides new insights into the development of tight oil reservoirs with TPG and meanwhile reveals the significance of proppant distribution and non-linear fluid flow in the production scenario design.