Sweet spot prediction in tight sandstone reservoir based on well-bore rock physical simulation

To establish the relationship among reservoir characteristics and rock physical parameters,we construct the well-bore rock physical models firstly,considering the influence factors,such as mineral composition,shale content,porosity,fluid type and saturation.Then with analyzing the change rules of elastic parameters along with the above influence factors and the cross-plots among elastic parameters,the sensitive elastic parameters of tight sandstone reservoir are determined,and the rock physics template of sweet spot is constructed to guide pre-stack seismic inversion.The results show that velocity ratio and Poisson impedance are the most sensitive elastic parameters to indicate the lithologic and gas-bearing properties of sweet spot in tight sandstone reservoir.The high-quality sweet spot is characterized by the lower velocity ratio and Poisson impedance.Finally,the actual seismic data are selected to predict the sweet spots in tight sandstone gas reservoirs,so as to verify the validity of the rock physical simulation results.The significant consistency between the relative logging curves and inversion results in different wells implies that the utilization of well-bore rock physical simulation can guide the prediction of sweet spot in tight sandstone gas reservoirs.

4D-stress evolution of tight sandstone reservoir during horizontal wells injection and production: A case study of Yuan 284 block,Ordos Basin,NW China

To investigate the 4D stress change during injection and production in tight sandstone reservoirs, a multi-physical fields modeling method is proposed considering the reservoir heterogeneity, hydraulic fracture and complex injection-production system. The 4D stress evolution of tight sandstone reservoir in Yuan 284 block of Huaqing oilfield, Ordos Basin,during injection-production in horizontal well network is investigated by modeling coupled flow and geomechanics. Results show:(1) Induced by injection and production, the 3D stress increases near the injectors but decreases near the producers, and the horizontal stresses are distributed in obvious strips along their respective stress directions.(2) The horizontal stress difference is the highest at the horizontal wellbore beside injectors during injection and production, while it is the lowest in undeveloped zone between the injectors, and the orientation of maximum horizontal principal stress changes the most near the injectors, which is distributed radially.(3) The hydraulic fracture in re-fracturing well was observed to be asymmetrical in geometry and deflected as the stress changed. The results provide theoretical guidance for horizantal well network modification and re-fracturing optimization design in tight sandstone reservoir.

Tight sandstone reservoir sensitivity and damage mechanism analysis: A case study from Ordos Basin, China and implications for reservoir damage prevention

Analysis of reservoir sensitivity to velocity,water,salt,acid,alkali and stress is critical for reservoir protection.To study the tight sandstone reservoir sensitivity at different formation depths(effective stress)and formation water conditions(pH,salinity,and fluid velocity),a series of dynamic core flow tests under different pH,salinity,acid,and effective stress conditions were performed on samples from tight sandstone reservoirs of the Upper Triassic Yanchang 8(T_(3)y^(8))Member and conventional reservoirs of the Middle-Lower Jurassic Yan'an 9(J_(1-2)y^(9))Member in the Ordos Basin.The results indicate that,compared with the conventional reservoirs,the tight sandstone reservoirs are more sensitive to velocity and stress,less sensitive to water,alkali and salinity,and respond better to acid fracturing.In addition,the critical conditions(salinity,velocity,pH,and stress)for pumping drilling,completion,and fracturing fluids into tight sandstone reservoirs were investigated.A combination of scanning electron microscopy coupled with energy-dispersive spectrometry(SEM-EDS),cathodoluminescence(CL),casting thin section(CTS)and nuclear magnetic resonance(NMR)images,high-pressure mercury injection capillary pressure(MICP)measurements as well as X-ray fluorescence spectral(XRF)analyses were employed to analyze the damage mechanisms of the conventional reservoirs(J_(1-2)y^(9))and tight sandstone reservoirs(T_(3)y^(8))caused by fluid invasion.The results suggest that reservoir sensitivity is primarily conditioned by the composition of detrital components and interstitial fillings,petrophysical properties,pore-throat structure,and diagenetic facies.All these factors control the sensitivity types and extent of the reser-voirs.Our results indicate that the poorer the reservoir physical properties,the stronger the reservoir heterogeneity and sensitivity,implying that tight sandstone reservoirs are more susceptible to changes in fluids than conventional reservoirs.This study offers insights into the reservoir damage types and helps to improve the design and implementation of protection measures for tight sandstone reservoir exploration.

Characterization of favorable lithofacies in tight sandstone reservoirs and its significance for gas exploration and exploitation: A case study of the 2nd Member of Triassic Xujiahe Formation in the Xinchang area, Sichuan Basin

By using core,logging curves,and experiment data,favorable lithofacies types in the 2 nd Member of Triassic Xujiahe Formation in the Xinchang area,Sichuan Basin were classified,standard of the favorable lithofacies was established,planar distribution regularities of the favorable lithofacies were identified,and forming mechanisms of the favorable lithofacies and their control effect on production were examined.(1)The 2 nd Member of Xujiahe Formation has twelve types of lithofacies,among which multiple layer medium-coarse grain sandstone lithofacies,parallel bedding medium-coarse grain sandstone lithofacies,massive bedding medium-coarse grain sandstone lithofacies,inclined bedding medium-coarse grain sandstone lithofacies,and charcoal-bearing medium-coarse grain sandstone lithofacies with better physical properties and higher gas content are favorable lithofacies;they feature low gamma,low neutron porosity,low resistivity,and high acoustic travel time on logging curves.(2)The sedimentary process controls spatial distribution of sand bodies which are the material basis of the favorable lithofacies;post diagenetic fluids would differentially reconstruct the favorable lithofacies;tectonic activities and abnormal formation pressure made strata slide along the weakness plane,giving rise to fractures in different types of rocks,which can enhance the reservoir permeability significantly.(3)The development degree of favorable lithofacies is a major factor affecting stable production of gas well.

Fractal Characteristics and Main Controlling Factors of High-Quality Tight Sandstone Reservoirs in the Southeastern Ordos Basin

Due to the complex conditions and strong heterogeneity of tight sandstone reservoirs,the reservoirs should be classified and the controlling factors of physical properties should be studied.Cast thin section observations,cathodoluminescence,scanning electron microscopy(SEM),X-ray diffraction(XRD),and high-pressure mercury injection(HPMI)were used to classify and optimize the reservoir.The Brooks-Corey model and stepwise regression were used to study the fractal dimension and main controlling factors of the physical properties of the high-quality reservoir.The results show that the reservoirs in the study area can be divided into four types,and the high-quality reservoir has the best physical properties and pore-throat characteristics.In the high-quality reservoir,the homogeneity of transitional pores was the best,followed by that of micropores,and the worst was mesopores.The porosity was controlled by depth and kaolinite.The model with standardized coefficients is y=12.454−0.778×(Depth)+0.395×(Kaolinite).The permeability was controlled by depth,illite/montmorillonite,and siliceous cement,and the model with standardized coefficients is y=1.689−0.683×(Depth)−0.395×(Illite/Montmorillonite)−0.337×(Siliceous Cement).The pore-throat evolutionary model shows that the early-middle diagenetic period was when the reservoir physical properties were at their best,and the kaolinite intercrystalline pores and residual intergranular pores were the most important.

Gas-Water Production of a Continental Tight-Sandstone Gas Reservoir under Different Fracturing Conditions

A numerical model of hydraulic fracture propagation is introduced for a representative reservoir(Yuanba continental tight sandstone gas reservoir in Northeast Sichuan).Different parameters are considered,i.e.,the interlayer stress difference,the fracturing discharge rate and the fracturing fluid viscosity.The results show that these factors affect the gas and water production by influencing the fracture size.The interlayer stress difference can effectively control the fracture height.The greater the stress difference,the smaller the dimensionless reconstruction volume of the reservoir,while the flowback rate and gas production are lower.A large displacement fracturing construction increases the fracture-forming efficiency and expands the fracture size.The larger the displacement of fracturing construction,the larger the dimensionless reconstruction volume of the reservoir,and the higher the fracture-forming efficiency of fracturing fluid,the flowback rate,and the gas production.Low viscosity fracturing fluid is suitable for long fractures,while high viscosity fracturing fluid is suitable for wide fractures.With an increase in the fracturing fluid viscosity,the dimensionless reconstruction volume and flowback rate of the reservoir display a non-monotonic behavior,however,their changes are relatively small.

Quantitative characterization of tight gas sandstone reservoirs using seismic data via an integrated rock-physics-based framework

Seismic characterizing of tight gas sandstone (TGS) reservoirs is essential for identifying promising gas-bearing regions. However, exploring the petrophysical significance of seismic-inverted elastic properties is challenging due to the complex microstructures in TGSs. Meanwhile, interbedded structures of sandstone and mudstone intensify the difficulty in accurately extracting the crucial tight sandstone properties. An integrated rock-physics-based framework is proposed to estimate the reservoir quality of TGSs from seismic data. TGSs with complex pore structures are modeled using the double-porosity model, providing a practical tool to compute rock physics templates for reservoir parameter estimation. The VP/VS ratio is utilized to predict the cumulative thickness of the TGS reservoirs within the target range via the threshold value evaluated from wireline logs for lithology discrimination. This approach also facilitates better capturing the elastic properties of the TGSs for quantitative seismic interpretation. Total porosity is estimated from P-wave impedance using the correlation obtained based on wireline log analysis. After that, the three-dimensional rock-physics templates integrated with the estimated total porosity are constructed to interpret microfracture porosity and gas saturation from velocity ratio and bulk modulus. The integrated framework can optimally estimate the parameters dominating the reservoir quality. The results of the indicator proposed based on the obtained parameters are in good agreement with the gas productions and can be utilized to predict promising TGS reservoirs. Moreover, the results suggest that considering microfracture porosity allows a more accurate prediction of high-quality reservoirs, further validating the applicability of the proposed method in the studied region.

Effect and quantitative evaluation of CO_2 derived from organic matter in coal on the formation of tight sandstone reservoirs

Tight reservoirs are widely distributed, especially in coal measure strata. Identification of the densification mechanism of the tight sandstone reservoirs is critical in effectively exploring and exploiting tight gasoil resources. In this study, the gas for mation from type III organic matter in coal was kinetically modeled for the whole diagenetic stage, from the shallow buried biogas generation stage to the deep buried thermal gas generation stage. The results demonstrated that during hydrocarbon formation, quantities of nonhydrocarbon gases, such as CO2, were generated. The proportion of CO2 is about 50%70% of that of the C15, which far exceeds the CO2 content （05%） in the natural gas in the sedimentary basins. Geological case study analysis showed that a considerable part of the ＂lost＂ gaseous CO2 was converted into carbonate cement under favorable envi ronments. Under the ideal conditions, the volume of the carbonate cement transformed from total CO2 generated by 1 m3 coal （Junggar Basin Jurassic, TOC 67%） can amount to 0.32 m3. Obviously, this process plays a very important role in the for mation of tight sandstone reservoirs in the coal measures. Our results also show that the kinetic generation processes of Ci5 and CO2 are asynchronous. There are two main stages of CO2 generation, one at the weak diagenetic stage and the other at the overmature stage, which are different from largescale multistage hydrocarbon gas generation. Therefore, we can understand the mechanism of tight gas charging by determining the filling time for a tight gas reservoir and the key period of CO2 genera tion. Further analysis and correlation studies of a specific region are of great significance for determining the mechanism and modeling gas charging in tight reservoirs. It should be noted that the formation of tight sandstone reservoirs is the combined result of complex organicinorganic and waterrockhydrocarbon interactions. The details of spatial and temporal distributions of the carbonate cement derived from the organic C02, which combines with metal ions （Ca/Mg/Fe） in the formation water, should be further investigated.

A Comprehensive Porosity Prediction Model for the Upper Paleozoic Tight Sandstone Reservoir in the Daniudi Gas Field, Ordos Basin

This paper investigated the porosity controlling factors for tight sandstone reservoir in the Daniudi gas field, Ordos Basin based on an integrated petrographic, petrophysical and geostatistical analyses, and proposed a comprehensive prediction model for reservoir porosity. Compaction was found to be a key factor for causing reservoir densification. The degree of sandstone compaction appears to be affected by grain sizes and sorting. Under normal compaction conditions（e.g., cement content less than 6%, and with no dissolution）, the variation in reservoir porosity with burial depth can be well correlated with grain compositions, grain sizes, and sorting. Based on qualitative examination of the controlling factors for reservoir porosities, geostatistics were used to quantify the effects of various geological parameters on reservoir porosities. A statistical model for comprehensive prediction of porosity was then established, on the assumption that the present reservoir porosity directly relates to both normal compaction and diagenesis. This model is easy to use, and has been validated with measured porosity data. The porosity controlling factors and the comprehensive porosity prediction can be used to quantify effects of the main controlling factors and their interaction on reservoir property evolution, and may provide a reference model for log interpretation.

Authigenic clay minerals and calcite dissolution influence reservoir quality in tight sandstones:Insights from the central Junggar Basin,NW China

Authigenic clays and calcite cements are important in the development of reservoir tightness and the formation of hydrocarbon sweet spots.We investigated Jurassic low-permeability sandstone reservoirs in the central Junggar Basin,NW China,using petrography,mineralogy,porosity,and permeability assessment,and stable C and O isotope analysis to ascertain the influence of authigenic clays and calcites on reservoir quality.Here,we establish the properties and diagenetic processes of the reservoir sandstones,and construct a generalizable model of reservoir quality.The results show that the sandstones are mainly litharenite and feldspathic litharenite and can be classified into ductile-lithic-rich sandstones and ductile-lithic-poor sandstones according to rock composition.The ductile-lithic-rich sandstones are tight(mean porosity?7.31%;mean permeability?0.08 mD)as a result of intense compaction.In contrast,the ductile-lithic-poor sandstones can be classified into five types according to diagenetic process.The formation of favorable hydrocarbon reservoir properties is closely related to the presence of authigenic clays and dissolution of calcite.In particular,kaolinite fills intergranular pores,thereby blocking pore space and reducing reservoir quality.Chlorite coating resists compaction and limits the formation of quartz overgrowths,thereby preserving pore space and enhancing reservoir quality.Calcite controls reservoir quality through both precipitation and dissolution.Calcite precipitation results in reduced reservoir quality,whereby early calcites that were precipitated in formation water resist compaction and provide the basis for subsequent dissolution and late precipitation,whereas dissolution of calcite in mesodiagenesis improves reservoir quality.A generalized model is formulated by relating diagenetic facies types to depth and porosity,providing a reference for other similar reservoirs.Our data suggest that deeply buried tight sandstones can be exploration prospects under favorable conditions involving the presence of authigenic clays and dissolution of calcite,as in the central Junggar Basin of this study.

Production forecasting methods for different types of gas reservoirs

Hydrocarbon production in oil and gas fields generally progresses through stages of production ramp-up,plateau(peak),and decline during field development,with the whole process primarily modeled and forecasted using lifecycle models.SINOPEC's conventional gas reservoirs are dominated by carbonates,low-permeability tight sandstone,condensate,volcanic rocks,and medium-to-high-permeability sandstone.This study identifies the optimal production forecasting models by comparing the fitting coefficients of different models and calculating the relative errors in technically recoverable reserves.To improve forecast precision,it suggests substituting exponential smoothing method-derived predictions for anomalous data caused by subjective influences like market dynamics and maintenance activities.The preferred models for carbonate gas reservoir production forecasts are the generalized Weng's,Beta,Class-I generalized mathematical,and Hu-Chen models.The Vapor pressure and Beta models are optimal for forecasting the annual productivity of wells(APW)from gas-bearing low-permeability tight sandstone reservoirs.The Wang-Li,Beta,and Yu QT tb models are apt for moderate-to-small-reserves,single low-permeability tight sandstone gas reservoirs.The Rayleigh,Hu-Chen,and generalized Weng's models are suitable for condensate gas reservoirs.For medium-to-high-permeability sandstone gas reservoirs,the lognormal,generalized gamma,and Beta models are recommended.

Types and genesis of sweet spots in the tight sandstone gas reservoirs:Insights from the Xujiahe Formation,northern Sichuan Basin,China

Through comprehensively applying geological and geophysical data,as well as core and thin section observation,the characteristics of reservoirs and fractures in the second member of the Xujiahe Formation(hereinafter referred to as Xu2 Member)in the Yuanba area,northern Sichuan Basin,were studied.Combined with the analysis of the main controlling factors of production capacity,the types and characteristics of the sweet spots in the tight sandstone gas reservoir were determined.The evaluation standards and geological models of the sweet spots were established.The results are as follows:(1)There are bedding-parallel fracture-,fault-induced fracture-,and pore-dominated sweet spots in the tight sandstone gas reservoirs of the Xu2 Member.(2)The bedding parallel fracture-dominated sweet spots have developed in quartz sandstones with well-developed horizontal fractures and micro-fractures.They are characterized by high permeability and high gas output during production tests.This kind of sweet spots is thin and shows a limited distribution.Their logging responses show extremely low gamma-ray(GR)values and medium-high AC values.Moreover,the bedding parallel fracture-dominated sweet spots can be mapped using seismic methods.(3)The fault-induced fracture-dominated sweet spots have welldeveloped medium-and high-angle shear fractures.Their logging responses show an increase in peaks of AC values and total hydrocarbon content and a decrease in resistivity.Seismically,the areas with welldeveloped fault-induced fracture-dominated sweet spots can be effectively mapped using the properties such as seismic entropy and maximum likelihood.(4)The pore-dominated sweet spots are developed in medium-grained feldspathic litharenites with good reservoir properties.They are thick and widely distributed.(5)These three types of sweet spots are mainly determined by sedimentation,diagenesis,and tectonism.The bedding parallel fracture-dominated sweet spots are distributed in beachbar quartz sandstones on the top of the 1st sand layer group in the Xu2 Member,which develops in a shore-shallow lake environment.The fault-induced fracture-dominated sweet spots mainly occur near faults.They are increasingly developed in areas closer to faults.The pore-dominated sweet spots are primarily distributed in the 2nd and 3rd sand layer groups,which lie in the development areas of distributary channels near provenances at western Yuanba area.Based on the geological and seismic data,a comprehensive evaluation standard for these three types of sweet spots of the tight sandstone reservoirs in the Xu2 Member has been established,which,on the one hand,lays the foundation for the development and evaluation of the gas reservoir,and on the other hand,deepens the understanding of sweet spot in the tight sandstone gas reservoirs.

Impacts of inorganic salts ions on the polar components desorption efficiency from tight sandstone:A molecular dynamics simulation and QCM-D study

Ions in brine significantly affect EOR.However,the mechanism of EOR with different brine is still controversial.By Combining Molecular Dynamics(MD)method and Quartz Crystal Microbalance with Dissipation(QCM-D)technology to analyze ions distribution and the mechanisms in detaching acidic components on the sandstone,an effective method to determine the detaching capacity was established.The results show that detaching capacity is related to ions distribution and hydration capacity.In the oil/brine/rock system,ions far from the rock are favorable for detaching,while ions near the rock are unfavorable for detaching due to ion bridging effect.The hydrogen bond between water and naphthenic acid is key to detaching.Cations strengthen the detaching by forming hydrated ions with water,and the detaching capacity is negatively correlated with hydrated ions radius and positively correlated with the water coordination number.The detaching determination coefficient was established by considering the ions distribution,ions types,and hydration strength,then verified by QCM-D.The brine detaching capacity with different Ca^(2+)/Mg^(2+)ratios was predicted based on MD and detaching determination coefficient,and verified by QCM-D.The optimal Ca^(2+)/Mg^(2+)ratio gave 7:3.This study provides theoretical guidance for targeted regulation of brine composition to improve the recovery of tight sandstone reservoir.

A new model for predicting irreducible water saturation in tight gas reservoirs

The irreducible water saturation(Swir) is a significant parameter for relative permeability prediction and initial hydrocarbon reserves estimation.However,the complex pore structures of the tight rocks and multiple factors of the formation conditions make the parameter difficult to be accurately predicted by the conventional methods in tight gas reservoirs.In this study,a new model was derived to calculate Swir based on the capillary model and the fractal theory.The model incorporated different types of immobile water and considered the stress effect.The dead or stationary water(DSW) was considered in this model,which described the phenomena of water trapped in the dead-end pores due to detour flow and complex pore structures.The water film,stress effect and formation temperature were also considered in the proposed model.The results calculated by the proposed model are in a good agreement with the experimental data.This proves that for tight sandstone gas reservoirs the Swir calculated from the new model is more accurate.The irreducible water saturation calculated from the new model reveals that Swir is controlled by the critical capillary radius,DSW coefficient,effective stress and formation temperature.

Diagenetic evolution of clastic reservoirs and its records in fine subsection:significance and application

It was showed that understanding of the diagenetic modifications and its associated products in the deeply to ultra-deeply buried tight sandstone reservoirs(DUDTSR)is great important for reservoir characterization and hydrocarbon prediction.However,the fine characterization of diagenetic evolution via geologic modelling in tight sandstones remains a great challenge as for complexity of lithology,temperature,pressure and formation fluid throughout the entire life cycle of tight sandstone reservoirs.To help get a comprehensive idea of the distribution of diagenetic processes on the formation of DUDTSR in the long geological period,type-I and type-II fine sections of diagenetic stage for clastic reservoirs were creatively proposed and its essence was illustrated using the Paleogene Huagang(EH)Formation in the southern Xihu Sag.Through combination of both quantitative and qualitative methods which began with current formation temperature,vitrinite analysis,illite and I/S mixed layers based on analytical testing of the EH Formation,(1)Paleotemperature(T),vitrinite reflectivity and smectite in mixed layer during burial processes were restored based on numerical analysis,(2)The accurate division of diagenetic evolution was identified from coarse to fine process using new model,(3)And finally the geological significance of fine division of the conventional diagenetic stage was illustrated for low-porosity and tight sandstone reservoirs.

Classification and characteristics of tight oil plays

Based on the latest conventional–unconventional oil and gas databases and relevant reports,the distribution features of global tight oil were analyzed.A classification scheme of tight oil plays is proposed based on developed tight oil fields.Effective tight oil plays are defined by considering the exploiting practices of the past few years.Currently,potential tight oil areas are mainly distributed in 137 sets of shale strata in 84 basins,especially South America,North America,Russia,and North Africa.Foreland,craton,and continental rift basins dominate.In craton basins,tight oil mainly occurs in Paleozoic strata,while in continental rift basins,tight oil occurs in Paleozoic–Cenozoic strata.Tight oil mainly accumulates in the Cretaceous,Early Jurassic,Late Devonian,and Miocene,which correspond very well to six sets of globaldeveloped source rocks.Based on source–reservoir relationship,core data,and well-logging data,tight oil plays can be classified into eight types,above-source play,below-source play,beside-source play,in-source play,between-source play,in-source mud-dominated play,insource mud-subordinated play,and interbedded-source play.Specifically,between-source,interbedded-source,and in-source mud-subordinated plays are major targets for global tight oil development with high production.Incontrast,in-source mud-dominated and in-source plays are less satisfactory.

High-Inclination Coring of Chang-63 of the Yanchang Formation in Huaqing Oilfield, Ordos Basin: Implications for Ancient Flow Direction and Fracture Orientation

A promising method is to use coring of high-inclination well to find ancient flow direction and orient tiny natural fractures in massive sandstone of sandy debris flow. Determination of ancient flow direction can reduce the number of exploration wells, and orientation of natural fractures is of guiding significance to the deployment of water injection development well pattern. In Block X of Huaqing Oilfield, Ordos Basin, the cores of Chang 63 section were obtained from Well Y through 16 coring operations, with a total length of 105 m. Cores is oriented through drilling parameters, the number of cores, the angle between the core edge and horizontal bedding, the coincidence degree of core profile and directional flame structure. Therefore, the micro-fractures on the core are directional. The ancient flow directions of sandy debris flow were restored by load casting, groove casting, groove casting and imbricate structure. Our results show that the ancient flow directions of sandy debris flows were southwest, southeast, northwest, and west from bottom to top. The front of the Wuqi Delta is the main source of blocky sandstone with the best oil-bearing property. Affected by the topography of the lake bottom, the sandy debris flow turned locally in the northeast direction, and the sandy debris flow from this direction was formed. The NEE-SWW-trending fractures formed in the Yanshanian period are most developed in the Huaqing area, which should be considered in deploying the flooding well network. The north-south micro-fractures formed in the Himalayan period can improve the physical properties of tight sandstone, which is of great significance for tight sandstone reservoirs.

Physical-property cutoffs of tight reservoirs by field and laboratory experiments: a case study from Chang 6, 8–9 in Ordos Basin

Tight sandstone reservoirs are generally characterized by complex reservoir quality,non-Darcy flow,and strong heterogeneity.Approaches utilized for evaluating physical property cutoffs of conventional reservoirs maybe inapplicable.Thus,a comprehensive investigation on physical property cutoffs of tight sandstone reservoirs is crucial for the reserve evaluation and successful exploration.In this study,a set of evaluation approaches take advantage of field operations(i.e.,core drilling,oil testing,and wireline well logging data),and simulation experiments(i.e.,high-pressure mercury injection-capillary pressure(MICP)experiment,oil-water relative permeability experiment,nuclear magnetic resonance(NMR)experiment,and biaxial pressure simulation experiment)were comparatively optimized to determine the physical property cutoffs of effective reservoirs in the Upper Triassic Chang 6,Chang 8 and Chang 9 oil layers of the Zhenjing Block.The results show that the porosity cutoffs of the Chang 6,Chang 8,and Chang 9 oil layers are 7.9%,6.4%,and 8.6%,and the corresponding permeability are 0.08 mD,0.05 mD,and 0.09 mD,respectively.Coupled with wireline well logging,mud logging,and oil testing,the cut-off of the thickness of single-layer effective reservoirs are approximately 3.0 m,3.0 m,and 2.0 m,respectively.Depending on the cutoffs of critical properties,a superimposed map showing the planar distribution of the prospective targets can be mapped,which may delineate the effective boundary of prospective targets for petroleum exploration of tight sandstone reservoirs.

Multi-scale fractures formation and distribution in tight sandstones—a case study of Triassic Chang 8 Member in the southwestern Ordos Basin

Fracture system is an important factor controlling tight oil accumulation in the Triassic Chang 8 Member,southwestern Ordos Basin,China.A systematic characterization of the multi-scale natural fractures is a basis for the efficient tight oil production.Based on outcrops,seismic reflections,well cores,well logs(image and conventional logging),casting thin sections,and scanning electron microscope observation,the multi-scale fractures occurrences and their influences on Chang 8 tight sandstone reservoirs are revealed.The results show that three periods of strike-slip faults and four scales of natural fractures developed,namely mega-scale(length>7×10^(7) mm),macro-scale(3.5×10^(5)<length<7×10^(7) mm),meso-scale(10<length<3.5×10^(5) mm),and micro-scale(length<10 mm)fractures.The mega-and macro-scale fractures developed by strike-slip faults are characterized by strike-segmentation and lateral zonation,which connect the source and reservoir.These scale fractures also influence the distribution and effectiveness of traps and reservoirs,which directly influence the hydrocarbon charging and distribution.The meso fractures include the tectonic,diagenetic,as well as hydrocarbon generation-related overpressure types.The meso-and micro-scale fractures improve the sandstone physical properties and also the tight oil well production performance.This integrated study helps to understand the distribution of multi-scale fractures in tight sandstones and provides a referable case and workflow for multi-scale fracture evaluation.

Key Elements Controlling Oil Accumulation within the Tight Sandstones

Tight oil sandstone reservoirs with low porosity and permeability, which are an unconventional petroleum resource, have been discovered in the Jurassic intervals of the central Junggar Basin, the northwestern China. To reveal the accumulation mechanism, a relatively comprehensive research was conducted, including oil-source correlation, porosity evolution, and hydrocarbon charging history. The results show that crude oil of these tight sandstone reservoirs were mainly from Permian source rocks with some contribution from Jurassic source rocks. The reservoirs were buried at shallow depth（〈3 100 m） and exposed to weak diagenesis, and thus had high porosity（18.5%） when the Permian-sourced oil from Permian source rock was charging, indicating high GOI values（〉5%）. In contrast, the sandstone reservoir had already become tight and did not provide available space to accumulate oil due to severe compaction and cementation when hydrocarbon from Jurassic source rock filled, evidenced by low GOI values（〈5%）. Therefore, reservoir porosity controls the oil accumulation within tight sandstone. Whether tight sandstone reservoirs accumulate oil depends on the reservoir quality when hydrocarbons charge. Before the exploration of tight oil sandstone reservoirs, it should be required to investigate the relationship between oil charging history and porosity evolution to reduce the exploration risk and figure out the available targets.