To study the relative sensitivity of permeability to pore pressure Pp and confining pressure Pc for clay-rich rocks, permeability measurements were performed on samples of four clay-rich sandstones. A new method （her...To study the relative sensitivity of permeability to pore pressure Pp and confining pressure Pc for clay-rich rocks, permeability measurements were performed on samples of four clay-rich sandstones. A new method （hereafter denoted the ＂slide method＂） was developed and used for analyzing the permeability data obtained. The effective pressure coefficients for permeability nk were calculated. The values of nk were found to be greater than 1.0 and insensitive to changes in pressure. These results confirmed observations previously made on clay-rich rocks. Also, the coefficients nk obtained had different characteristics for different samples because of differences in the types of clay they contained. The effective pressure law （σeff=Pc-nkPp） determined using the slide method gave better results about k（oefr） than classic Terzaghi＇s law （σeff=Pc-nkPp）.展开更多
Burial dissolution of feldspar and carbonate minerals has been proposed to generate large volumes of secondary pores in subsurface reservoirs. Secondary porosity due to feldspar dissolution is ubiquitous in buried san...Burial dissolution of feldspar and carbonate minerals has been proposed to generate large volumes of secondary pores in subsurface reservoirs. Secondary porosity due to feldspar dissolution is ubiquitous in buried sandstones;however, extensive burial dissolution of carbonate minerals in subsurface sandstones is still debatable. In this paper, we first present four types of typical selective dissolution assemblages of feldspars and carbonate minerals developed in di erent sandstones. Under the constraints of porosity data, water–rock experiments, geochemical calculations of aggressive fluids, diagenetic mass transfer, and a review of publications on mineral dissolution in sandstone reservoirs, we argue that the hypothesis for the creation of significant volumes of secondary porosity by mesodiagenetic carbonate dissolution in subsurface sandstones is in conflict with the limited volume of aggressive fluids in rocks. In addition, no transfer mechanism supports removal of the dissolution products due to the small water volume in the subsurface reservoirs and the low mass concentration gradients in the pore water. Convincing petrographic evidence supports the view that the extensive dissolution of carbonate cements in sandstone rocks is usually associated with a high flux of deep hot fluids provided via fault systems or with meteoric freshwater during the eodiagenesis and telodiagenesis stages. The presumption of extensive mesogenetic dissolution of carbonate cements producing a significant net increase in secondary porosity should be used with careful consideration of the geological background in prediction of sandstone quality.展开更多
The tight sandstones of the Upper Triassic Xujiahe Formation（T_3x） constitute important gas reservoirs in western Sichuan.The Xujiahe sandstones are characterized by low to very low porosity （av.5.22%and 3.62%） fo...The tight sandstones of the Upper Triassic Xujiahe Formation（T_3x） constitute important gas reservoirs in western Sichuan.The Xujiahe sandstones are characterized by low to very low porosity （av.5.22%and 3.62%） for the T_3x^4 and T_3x^2 sandstones,respectively）,extremely low permeability（av. 0.060 mD and 0.058 mD for the T_3x^4 and T_3x^2 sandstones,respectively）,strong heterogeneity,micronano pore throat,and poor pore throat sorting.As a result of complex pore structure and the occurrence of fractures,weak correlations exist between petrophysical properties and pore throat size,demonstrating that porosity or pore throat size alone does not serve as a good permeability predictor.Much improved correlations can be obtained between permeability and porosity when pore throat radii are incorporated. Correlations between porosity,permeability,and pore throat radii corresponding to different saturations of mercury were established,showing that the pore throat radius at 20%mercury saturation（R_（20）） is the best permeability predictor.Multivariate regression analysis and artificial neural network（ANN） methods were used to establish permeability prediction models and the unique characteristics of neural networks enable them to be more successful in predicting permeability than the multivariate regression model.In addition, four petrophysical rock types can be identified based on the distributions of R_（20）,each exhibiting distinct petrophysical properties and corresponding to different flow units.展开更多
Influenced by neo-tectonic movement, the Sanhu area of China＇s Qaidam Basin formed in the Quaternary in response to migration of its depocentre. A study of core material from the Qijia 1 Well reveals novel Quaternary...Influenced by neo-tectonic movement, the Sanhu area of China＇s Qaidam Basin formed in the Quaternary in response to migration of its depocentre. A study of core material from the Qijia 1 Well reveals novel Quaternary aqueously deposited aeolian sandstones in the Qigequan Formation of the Sanhu area. Here we report the sedimentary petrology and geochemistry data of these deposits that constrain their depositional history. Evidence for aeolian influence during deposition includes： sorting and roundness, pure quartz sand with single mode grain size distribution and few suspension materials,very fine sand grain size distribution indicating sorting by saltation and suspension transport, dish-shaped and crescentshaped pits in grain surfaces indicating aeolian transport and chemical composition similar to that observed in active or recent dune deposits, namely enrichment in Si O_2, Na_2 O, and Mg O relative to the sand dam sediment in the lakeshore.Identification of these aqueously deposited aeolian sandstones expands the range of sedimentary deposit types found in the Sanhu area and improves understanding of its paleoclimatic history.展开更多
Hydrocarbon resources in low-permeability sandstones are very abundant and are extensively distributed. Low-permeability reservoirs show several unique characteristics, including lack of a definite trap boundary or ca...Hydrocarbon resources in low-permeability sandstones are very abundant and are extensively distributed. Low-permeability reservoirs show several unique characteristics, including lack of a definite trap boundary or caprock, limited buoyancy effect, complex oil-gas-water distribution, without obvious oil-gas-water interfaces, and relatively low oil （gas） saturation. Based on the simulation experiments of oil accumulation in low-permeability sandstone （oil displacing water）, we study the migration and accumulation characteristics of non-Darcy oil flow, and discuss the values and influencing factors of relative permeability which is a key parameter characterizing oil migration and accumulation in low-permeability sandstone. The results indicate that： 1） Oil migration （oil displacing water） in low- permeability sandstone shows non-Darcy percolation characteristics, and there is a threshold pressure gradient during oil migration and accumulation, which has a good negative correlation with permeability and apparent fluidity; 2） With decrease of permeability and apparent fluidity and increase of fluid viscosity, the percolation curve is closer to the pressure gradient axis and the threshold pressure gradient increases. When the apparent fluidity is more than 1.0, the percolation curve shows modified Darcy flow characteristics, while when the apparent fluidity up＂ non-Darcy percolation curve; 3） Oil-water is less than 1.0, the percolation curve is a ＂concave- two-phase relative permeability is affected by core permeability, fluid viscosity, apparent fluidity, and injection drive force; 4） The oil saturation of low- permeability sandstone reservoirs is mostly within 35%-60%, and the oil saturation also has a good positive correlation with the permeability and apparent fluidity.展开更多
The fractures and kerogen,which generally exist in the shale,are signifcant to the CO_(2) huf-n-puf in the shale reservoir.It is important to study the efects of fractures and kerogen on oil recovery during CO_(2) huf...The fractures and kerogen,which generally exist in the shale,are signifcant to the CO_(2) huf-n-puf in the shale reservoir.It is important to study the efects of fractures and kerogen on oil recovery during CO_(2) huf-n-puf operations in the fracture-matrix system.In this study,a modifed CO_(2) huf-n-puf experiment method is developed to estimate the recovery factors and the CO_(2) injectivity in the fractured organic-rich shales and tight sandstones.The efects of rock properties,injection pressure,and injection time on the recovery factors and CO_(2) usage efciency in shales and sandstones are discussed,respectively.The results show that although the CO_(2) injectivity in the shale is higher than that in the sandstone with the same porosity;besides,the recovery factors of two shale samples are much lower than that of two sandstone samples.This demonstrates that compared with the tight sandstone,more cycles are needed for the shale to reach a higher recovery factor.Furthermore,there are optimal injection pressures(close to the minimum miscible pressure)and CO_(2) injection volumes for CO_(2) huf-npuf in the shale.Since the optimal CO_(2) injection volume in the shale is higher than that in the sandstone,more injection time is needed to enhance the oil recovery in the shale.There is a reference sense for CO_(2) huf-n-puf in the fractured shale oil reservoir for enhanced oil recovery(EOR)purposes.展开更多
A number of beach-bar sandstone reservoir beds are developed in the upper fourth member of the Eocene Shahejie Formation （Es4s） on the southern slope of the Dongying Sag.Based on the analysis of seismic and logging ...A number of beach-bar sandstone reservoir beds are developed in the upper fourth member of the Eocene Shahejie Formation （Es4s） on the southern slope of the Dongying Sag.Based on the analysis of seismic and logging data,with characterization and petrographic studies of core and cutting samples,this paper analyzes the hydrocarbon accumulation characteristics in two typical blocks of the Boxing and Wangjiagang oilfields,especially reservoir bed heterogeneity and migration conditions that influence oil and gas distribution,calculates the index of reservoir bed quality （IRQ） with a mathematical method,and discusses the relationship between driving force and resistance of hydrocarbon accumulation.Taking into account the characteristics of thin interbeds in beach-bar sandstones,an experimental model simulated the characteristics of hydrocarbon migration and accumulation in thin interbedded sandstones with reservoir bed heterogeneity.The results showed that hydrocarbon distribution and properties were extremely non-uniform.Reservoir bed and migration conditions controlled hydrocarbon accumulation in beach-bar sandstones.IRQ is above 0.4 in the main hydrocarbon region.Sand body distribution,structural configuration and fault systems controlled the direction of regional migration and location of hydrocarbon accumulation.Simulation experiments indicated that the change of driving force for hydrocarbon migration affected selective accumulation mechanisms.Hydrocarbon moved vertically along fault zones to the reservoir and resulted in the distribution of hydrocarbon in the reservoir.Two kinds of hydrocarbon accumulation models exist in the study area.One is a hydrocarbon accumulation model controlled by reservoir bed heterogeneity and the second is a hydrocarbon accumulation model controlled by a complex migration system with faults connecting sandbodies.Finally,different exploration strategies should be adopted for the detailed exploration for beach-bar sandstone reservoirs according to different geological backgrounds.展开更多
Fracability is a property that indicates how easy reservoir rocks can be fractured in hydraulic fracturing operations.It is a key parameter for fracturing design and evaluation.In order to utilize continuous logging d...Fracability is a property that indicates how easy reservoir rocks can be fractured in hydraulic fracturing operations.It is a key parameter for fracturing design and evaluation.In order to utilize continuous logging data to predict fracability,synchronous tests of dynamic and static mechanical parameters of rocks under different confining pressures were conducted on13 tight sandstone samples derived from the central Junggar Basin,China.A modified formula between dynamic and static mechanical parameters was established.Fracability of the tight reservoir in the Junggar Basin was then evaluated based on brittleness index,fracture toughness,and fracability index.The effectiveness of fracturing was analyzed combined with the oil testing curve after hydraulic fracturing.The results show that:(1)The distribution of oil-bearing formations in the studied area coincides well with stratum of higher fracability index.(2)The critical fracability index is determined to be 0.3,three formations are selected as fracturing candidates,and a thin mudstone interbed is identified in the oil-bearing formation.(3)Well testing curve verifies the reliability of the fracability evaluation method and the accuracy of the modified formula between dynamic and static mechanical parameters.This study provides useful information for improving fracturing operations of tight oil and gas reservoirs.展开更多
Microscopic seepage characteristics are critical for the evaluation of tight sandstone reservoirs.In this study,a digital core approach integrating microscopic seepage simulation and CT scanning was developed to chara...Microscopic seepage characteristics are critical for the evaluation of tight sandstone reservoirs.In this study,a digital core approach integrating microscopic seepage simulation and CT scanning was developed to characterize microscopic seepage and fracture effectiveness(the ratio of micro-fractures that contributes to fluid flow)of tight sandstones.Numerical simulations were carried out for characterizations of tight sandstones.The results show that the axial permeability of the investigated cylindrical tight sandstone from Junggar Basin in China is 0.460μm~2,while the radial permeability is 0.3723μm~2,and the axial and radial effective fracture ratios are 0.4387 and 0.4806,respectively,indicating that cracks are not fully developed and the connectivity between micro-cracks is poor.Directional permeability that is difficult to measure by laboratory experiments can be obtained readily using the proposed method in this paper.The results provide important information for improving the exploration and development of tight sandstone reservoirs.展开更多
The tight sandstones in the Permian Lower Shihezi Formation of Shilijiahan area in the Ordos Basin was taken as study object in this research to quantitatively determine the effects of burial depth, burial time and co...The tight sandstones in the Permian Lower Shihezi Formation of Shilijiahan area in the Ordos Basin was taken as study object in this research to quantitatively determine the effects of burial depth, burial time and compaction strength on porosity during densification of reservoir. Firstly, sandstone compaction profiles were analyzed in detail. Secondly, the theoretical study was performed based on visco-elasto-plastic stress–strain model. Thirdly, multiple regression and iterative algorithm were used respectively to ascertain the variation trends of Young's modulus and equivalent viscosity coefficient with burial depth and burial time. Accordingly, the ternary analytic porosity-reduction model of sandstone compaction trend was established. Eventually, the reasonability of improved model was tested by comparing with thin-section statistics under microscope and the models in common use. The study shows that the new model can divide the porosity reduction into three parts, namely, elastic porosity loss, visco-plastic porosity loss and porosity loss from cementation. And the results calculated by the new model of litharenite in He 2 Member are close to the average value from the thin-section statistics on Houseknecht chart, which approximately reveals the relative magnitudes of compaction and cementation in the normal evolution trend of sandstone porosity. Furthermore, the model can more exactly depict the compaction trend of sandstone affected little by dissolution than previous compaction models, and evaluate sandstone compaction degree and its contribution to reservoir densification during different burial and uplift processes.展开更多
Estimating gas enrichments is a key objective in exploring sweet spots within tight sandstone gas reservoirs.However,the low sensitivity of elastic parameters to gas saturations in such formations makes it a significa...Estimating gas enrichments is a key objective in exploring sweet spots within tight sandstone gas reservoirs.However,the low sensitivity of elastic parameters to gas saturations in such formations makes it a significant challenge to reliably estimate gas enrichments using seismic methods.Through rock physical modeling and reservoir parameter analyses conducted in this study,a more suitable indicator for estimating gas enrichment,termed the gas content indicator,has been proposed.This indicator is formulated based on effective fluid bulk modulus and shear modulus and demonstrates a clear positive correlation with gas content in tight sandstones.Moreover,a new seismic amplitude variation versus offset(AVO)equation is derived to directly extract reservoir properties,such as the gas content indicator and porosity,from prestack seismic data.The accuracy of this proposed AVO equation is validated through comparison with the exact solutions provided by the Zoeppritz equation.To ensure reliable estimations of reservoir properties from partial angle-stacked seismic data,the proposed AVO equation is reformulated within the elastic impedance inversion framework.The estimated gas content indicator and porosity exhibit favorable agreement with logging data,suggesting that the obtained results are suitable for reliable predictions of tight sandstones with high gas enrichments.Furthermore,the proposed methods have the potential to stimulate the advancement of other suitable inversion techniques for directly estimating reservoir properties from seismic data across various petroleum resources.展开更多
In this study, an integrated approach for diagenetic facies classification, reservoir quality analysis and quantitative wireline log prediction of tight gas sandstones(TGSs) is introduced utilizing a combination of fi...In this study, an integrated approach for diagenetic facies classification, reservoir quality analysis and quantitative wireline log prediction of tight gas sandstones(TGSs) is introduced utilizing a combination of fit-for-purpose complementary testing and machine learning techniques. The integrated approach is specialized for the middle Permian Shihezi Formation TGSs in the northeastern Ordos Basin, where operators often face significant drilling uncertainty and increased exploration risks due to low porosities and micro-Darcy range permeabilities. In this study, detrital compositions and diagenetic minerals and their pore type assemblages were analyzed using optical light microscopy, cathodoluminescence, standard scanning electron microscopy, and X-ray diffraction. Different types of diagenetic facies were delineated on this basis to capture the characteristic rock properties of the TGSs in the target formation.A combination of He porosity and permeability measurements, mercury intrusion capillary pressure and nuclear magnetic resonance data was used to analyze the mechanism of heterogeneous TGS reservoirs.We found that the type, size and proportion of pores considerably varied between diagenetic facies due to differences in the initial depositional attributes and subsequent diagenetic alterations;these differences affected the size, distribution and connectivity of the pore network and varied the reservoir quality. Five types of diagenetic facies were classified:(i) grain-coating facies, which have minimal ductile grains, chlorite coatings that inhibit quartz overgrowths, large intergranular pores that dominate the pore network, the best pore structure and the greatest reservoir quality;(ii) quartz-cemented facies,which exhibit strong quartz overgrowths, intergranular porosity and a pore size decrease, resulting in the deterioration of the pore structure and reservoir quality;(iii) mixed-cemented facies, in which the cementation of various authigenic minerals increases the micropores, resulting in a poor pore structure and reservoir quality;(iv) carbonate-cemented facies and(v) tightly compacted facies, in which the intergranular pores are filled with carbonate cement and ductile grains;thus, the pore network mainly consists of micropores with small pore throat sizes, and the pore structure and reservoir quality are the worst. The grain-coating facies with the best reservoir properties are more likely to have high gas productivity and are the primary targets for exploration and development. The diagenetic facies were then translated into wireline log expressions(conventional and NMR logging). Finally, a wireline log quantitative prediction model of TGSs using convolutional neural network machine learning algorithms was established to successfully classify the different diagenetic facies.展开更多
Quantitative prediction of reservoir properties(e.g., gas saturation, porosity, and shale content) of tight reservoirs is of great significance for resource evaluation and well placements. However, the complex pore st...Quantitative prediction of reservoir properties(e.g., gas saturation, porosity, and shale content) of tight reservoirs is of great significance for resource evaluation and well placements. However, the complex pore structures, poor pore connectivity, and uneven fluid distribution of tight sandstone reservoirs make the correlation between reservoir parameters and elastic properties more complicated and thus pose a major challenge in seismic reservoir characterization. We have developed a partially connected double porosity model to calculate elastic properties by considering the pore structure and connectivity, and to analyze these factors' influences on the elastic behaviors of tight sandstone reservoirs. The modeling results suggest that the bulk modulus is likely to be affected by the pore connectivity coefficient, while the shear modulus is sensitive to the volumetric fraction of stiff pores. By comparing the model predictions with the acoustic measurements of the dry and saturated quartz sandstone samples, the volumetric fraction of stiff pores and the pore connectivity coefficient can be determined. Based on the calibrated model, we have constructed a 3D rock physics template that accounts for the reservoir properties' impacts on the P-wave impedance, S-wave impedance, and density. The template combined with Bayesian inverse theory is used to quantify gas saturation, porosity, clay content, and their corresponding uncertainties from elastic parameters. The application of well-log and seismic data demonstrates that our 3D rock physics template-based probabilistic inversion approach performs well in predicting the spatial distribution of high-quality tight sandstone reservoirs in southwestern China.展开更多
To clarify the formation and distribution of feldspar dissolution pores and predict the distribution of high-quality reservoir in gravity flow sandstone of the 7^(th) member of Triassic Yanchang Formation(Chang 7 Memb...To clarify the formation and distribution of feldspar dissolution pores and predict the distribution of high-quality reservoir in gravity flow sandstone of the 7^(th) member of Triassic Yanchang Formation(Chang 7 Member)in the Ordos Basin,thin sections,scanning electron microscopy,energy spectrum analysis,X-ray diffraction whole rock analysis,and dissolution experiments are employed in this study to investigate the characteristics and control factors of feldspar dissolution pores.The results show that:(1)Three types of diagenetic processes are observed in the feldspar of Chang 7 sandstone in the study area:secondary overgrowth of feldspar,replacement by clay and calcite,and dissolution of detrital feldspar.(2)The feldspar dissolution of Chang 7 tight sandstone is caused by organic acid,and is further affected by the type of feldspar,the degree of early feldspar alteration,and the buffering effect of mica debris on organic acid.(3)Feldspars have varying degrees of dissolution.Potassium feldspar is more susceptible to dissolution than plagioclase.Among potassium feldspar,orthoclase is more soluble than microcline,and unaltered feldspar is more soluble than early kaolinized or sericitized feldspar.(4)The dissolution experiment demonstrated that the presence of mica can hinder the dissolution of feldspar.Mica of the same mass has a significantly stronger capacity to consume organic acids than feldspar.(5)Dissolution pores in feldspar of Chang 7 Member are more abundant in areas with low mica content,and they improve the reservoir physical properties,while in areas with high mica content,the number of feldspar dissolution pores decreases significantly.展开更多
Underground engineering often passes through water-rich fractured rock masses, which are prone to fracture and instability under the long-term coupling of in-situ stress field and pore water(P-W) pressure, ultimately ...Underground engineering often passes through water-rich fractured rock masses, which are prone to fracture and instability under the long-term coupling of in-situ stress field and pore water(P-W) pressure, ultimately threatening the stability of underground structures. In order to explore the mechanical properties of rocks under H-M coupling, the corresponding damage constitutive(D-C) model has become the focus of attention. Considering the inadequacy of the current research on rock strength parameters,energy evolution characteristics and D-C model under H-M coupling, the mechanical properties of typical sandstone samples are discussed based on laboratory tests. The results show that the variation of characteristic stresses of sandstone under H-M coupling conforms to the normalized attenuation equation and Mohr-Coulomb(M-C) criterion. The P-W pressure mechanism of sandstone exhibits a dynamic change from softening effect to H-M fracturing effect. The closure stress is mainly provided by cohesive strength, while the initiation stress, damage stress, and peak stress are jointly dominated by cohesive strength and friction strength. In addition, residual stress is attributed to the friction strength formed by the bite of the fracture surface. Subsequently, the energy evolution characteristics of sandstone under H-M coupling were studied, and it was found that P-W pressure weakened the energy storage capacity and energy dissipation capacity of sandstone, and H-M fracturing was an important factor in reducing its energy storage efficiency. Finally, combined with energy dissipation theory and statistical damage theory, two types of D-C models considering P-W pressure are proposed accordingly, and the model parameters can be determined by four methods. The application results indicate that the proposed and modified D-C models have high reliability, and can characterize the mechanical behavior of sandstone under H-M coupling, overcome the inconvenience of existing D-C models due to excessive mechanical parameters,and can be applied to the full-range stress–strain process. The results are conducive to revealing the deformation and damage mechanisms of rocks under H-M coupling, and can provide theoretical guidance for related engineering problems.展开更多
3D printing is widely adopted to quickly produce rock mass models with complex structures in batches,improving the consistency and repeatability of physical modeling.It is necessary to regulate the mechanical properti...3D printing is widely adopted to quickly produce rock mass models with complex structures in batches,improving the consistency and repeatability of physical modeling.It is necessary to regulate the mechanical properties of 3D-printed specimens to make them proportionally similar to natural rocks.This study investigates mechanical properties of 3D-printed rock analogues prepared by furan resin-bonded silica sand particles.The mechanical property regulation of 3D-printed specimens is realized through quantifying its similarity to sandstone,so that analogous deformation characteristics and failure mode are acquired.Considering similarity conversion,uniaxial compressive strength,cohesion and stress–strain relationship curve of 3D-printed specimen are similar to those of sandstone.In the study ranges,the strength of 3D-printed specimen is positively correlated with the additive content,negatively correlated with the sand particle size,and first increases then decreases with the increase of curing temperature.The regulation scheme with optimal similarity quantification index,that is the sand type of 70/140,additive content of 2.5‰and curing temperature of 81.6℃,is determined for preparing 3D-printed sandstone analogues and models.The effectiveness of mechanical property regulation is proved through uniaxial compression contrast tests.This study provides a reference for preparing rock-like specimens and engineering models using 3D printing technology.展开更多
A simulated oil viscosity prediction model is established according to the relationship between simulated oil viscosity and geometric mean value of T2spectrum,and the time-varying law of simulated oil viscosity in por...A simulated oil viscosity prediction model is established according to the relationship between simulated oil viscosity and geometric mean value of T2spectrum,and the time-varying law of simulated oil viscosity in porous media is quantitatively characterized by nuclear magnetic resonance(NMR)experiments of high multiple waterflooding.A new NMR wettability index formula is derived based on NMR relaxation theory to quantitatively characterize the time-varying law of rock wettability during waterflooding combined with high-multiple waterflooding experiment in sandstone cores.The remaining oil viscosity in the core is positively correlated with the displacing water multiple.The remaining oil viscosity increases rapidly when the displacing water multiple is low,and increases slowly when the displacing water multiple is high.The variation of remaining oil viscosity is related to the reservoir heterogeneity.The stronger the reservoir homogeneity,the higher the content of heavy components in the remaining oil and the higher the viscosity.The reservoir wettability changes after water injection:the oil-wet reservoir changes into water-wet reservoir,while the water-wet reservoir becomes more hydrophilic;the degree of change enhances with the increase of displacing water multiple.There is a high correlation between the time-varying oil viscosity and the time-varying wettability,and the change of oil viscosity cannot be ignored.The NMR wettability index calculated by considering the change of oil viscosity is more consistent with the tested Amott(spontaneous imbibition)wettability index,which agrees more with the time-varying law of reservoir wettability.展开更多
The Santos Basin in Brazil has witnessed significant oil and gas discoveries in deepwater pre-salt since the 21^(st)century.Currently,the waters in eastern Brazil stand out as a hot area of deepwater exploration and p...The Santos Basin in Brazil has witnessed significant oil and gas discoveries in deepwater pre-salt since the 21^(st)century.Currently,the waters in eastern Brazil stand out as a hot area of deepwater exploration and production worldwide.Based on a review of the petroleum exploration and production history in Brazil,the challenges,researches and practices,strategic transformation,significant breakthroughs,and key theories and technologies for exploration from onshore to offshore and from shallow waters to deep-ultra-deep waters and then to pre-salt strata are systematically elaborated.Within 15 years since its establishment in 1953,Petrobras explored onshore Paleozoic cratonic and marginal rift basins,and obtained some small to medium petroleum discoveries in fault-block traps.In the 1970s,Petrobras developed seismic exploration technologies and several hydrocarbon accumulation models,for example,turbidite sandstones,allowing important discoveries in shallow waters,e.g.the Namorado Field and Enchova fields.Guided by these models/technologies,significant discoveries,e.g.the Marlim and Roncador fields,were made in deepwater post-salt in the Campos Basin.In the early 21^(st)century,the advancements in theories and technologies for pre-salt petroleum system,carbonate reservoirs,hydrocarbon accumulation and nuclear magnetic resonance(NMR)logging stimulated a succession of valuable discoveries in the Lower Cretaceous lacustrine carbonates in the Santos Basin,including the world-class ultra-deepwater super giant fields such as Tupi(Lula),Mero and Buzios.Petroleum development in complex deep water environments is extremely challenging.By establishing the Technological Capacitation Program in Deep Waters(PROCAP),Petrobras developed and implemented key technologies including managed pressure drilling(MPD)with narrow pressure window,pressurized mud cap drilling(PMCD),multi-stage intelligent completion,development with Floating Production Storage and Offloading units(FPSO),and flow assurance,which remarkably improved the drilling,completion,field development and transportation efficiency and safety.Additionally,under the limited FPSO capacity,Petrobras promoted the world-largest CCUS-EOR project,which contributed effectively to the reduction of greenhouse gas emissions and the enhancement of oil recovery.Development and application of these technologies provide valuable reference for deep and ultra-deepwater petroleum exploration and production worldwide.The petroleum exploration in Brazil will consistently focus on ultra-deep water pre-salt carbonates and post-salt turbidites,and seek new opportunities in Paleozoic gas.Technical innovation and strategic cooperation will be held to promote the sustainable development of Brazil's oil and gas industry.展开更多
Based on an elaboration of the resource potential and annual production of tight sandstone gas and shale gas in the United States and China,this paper reviews the researches on the distribution of tight sandstone gas ...Based on an elaboration of the resource potential and annual production of tight sandstone gas and shale gas in the United States and China,this paper reviews the researches on the distribution of tight sandstone gas and shale gas reservoirs,and analyzes the distribution characteristics and genetic types of tight sandstone gas reservoirs.In the United States,the proportion of tight sandstone gas in the total gas production declined from 20%-35%in 2008 to about 8%in 2023,and the shale gas production was 8310×10^(8)m^(3)in 2023,about 80%of the total gas production,in contrast to the range of 5%-17%during 2000-2008.In China,the proportion of tight sandstone gas in the total gas production increased from 16%in 2010 to 28%or higher in 2023.China began to produce shale gas in 2012,with the production reaching 250×10^(8)m^(3)in 2023,about 11%of the total gas production of the country.The distribution of shale gas reservoirs is continuous.According to the fault presence,fault displacement and gas layer thickness,the continuous shale gas reservoirs can be divided into two types:continuity and intermittency.Most previous studies believed that both tight sandstone gas reservoirs and shale gas reservoirs are continuous,but this paper holds that the distribution of tight sandstone gas reservoirs is not continuous.According to the trap types,tight sandstone gas reservoirs can be divided into lithologic,anticlinal,and synclinal reservoirs.The tight sandstone gas is coal-derived in typical basins in China and Egypt,but oil-type gas in typical basins in the United States and Oman.展开更多
A better understanding of the controls on reservoir quality has become essential in the petroleum exploration in recent years. Determining the original composition of tile sediment framework is important not only for ...A better understanding of the controls on reservoir quality has become essential in the petroleum exploration in recent years. Determining the original composition of tile sediment framework is important not only for paleogeographic reconstructions, but it is also vital tbr predicting the nature of physical and chemical diagenesis of the potential reservoirs. Depositional setting and diagenesis are important factors in controlling the type and quality of most siliciclastic reservoirs. We studied the Upper Triassic Chang 8 and 6 members, where the relationship between sediment provenance and diagenesis was examined. The study attempts to clarify sediment provenance and post-depositional diagenetic modifications of the sandstones through systematic analytical methods including petrographic macro- and microscopic analysis of grain and heavy mineral types, and measurements of the palaeocurrent direction of the Yanchang Formation sediments in the outcrops in order to determine the provenance of the studied sediments. Furthermore, the relationship between framework grains, pore types and diagenesis of the sediments was analyzed by thin section petrographic characterization using a polarizing microscope. Additionally, a JEOL JSM-T330 scanning electron microscope （SEM） equipped with a digital imaging system was used to investigate the habits and textural relationships of diagenetic minerals. On the basis of our results, we believe that sediment provenance is a significant factor which controls the type and degree of diagenesis which may be expected in sandstones. In the Chang 8 and 6 members, tile formation of chlorite rims and laumontite cement was observed where volcanic rock fragments constitute a large part of the framework grains. Furthermore, high biotite content provides abundant iron and magnesium and enables the tbnnation of chlorite rims due to biotite hydrolysis. In addition, ductile deformation of biotite leads to strong mechanical compaction of the sediments. Conversely, high feldspar content diminishes the degree of mechanical compaction, however the dissolution of feldspar minerals in sandstones is commonly observed. Apart from feldspars, quartz and other rigid fi＇amework grains highly control the degree of mechanical compaction during the initial stage of burial （0-2 km）.展开更多
基金supported by a grant from the National Natural Science Foundation of China(Grant No.50774064)the Open Fund PLN0802 of the State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation(Southwest Petroleum University)
文摘To study the relative sensitivity of permeability to pore pressure Pp and confining pressure Pc for clay-rich rocks, permeability measurements were performed on samples of four clay-rich sandstones. A new method （hereafter denoted the ＂slide method＂） was developed and used for analyzing the permeability data obtained. The effective pressure coefficients for permeability nk were calculated. The values of nk were found to be greater than 1.0 and insensitive to changes in pressure. These results confirmed observations previously made on clay-rich rocks. Also, the coefficients nk obtained had different characteristics for different samples because of differences in the types of clay they contained. The effective pressure law （σeff=Pc-nkPp） determined using the slide method gave better results about k（oefr） than classic Terzaghi＇s law （σeff=Pc-nkPp）.
基金funded by the Natural Science Foundation of China Project(Nos.41602138,41872140,41911530189)the National Science and Technology Special Grant(No.2016ZX05006-007+2 种基金No.2016ZX05006-003)the Fundamental Research Funds for the Central Universities(18CX07007A)the State Key Laboratory of Organic Geochemistry,GIGCAS(No.SKLOG-201709)
文摘Burial dissolution of feldspar and carbonate minerals has been proposed to generate large volumes of secondary pores in subsurface reservoirs. Secondary porosity due to feldspar dissolution is ubiquitous in buried sandstones;however, extensive burial dissolution of carbonate minerals in subsurface sandstones is still debatable. In this paper, we first present four types of typical selective dissolution assemblages of feldspars and carbonate minerals developed in di erent sandstones. Under the constraints of porosity data, water–rock experiments, geochemical calculations of aggressive fluids, diagenetic mass transfer, and a review of publications on mineral dissolution in sandstone reservoirs, we argue that the hypothesis for the creation of significant volumes of secondary porosity by mesodiagenetic carbonate dissolution in subsurface sandstones is in conflict with the limited volume of aggressive fluids in rocks. In addition, no transfer mechanism supports removal of the dissolution products due to the small water volume in the subsurface reservoirs and the low mass concentration gradients in the pore water. Convincing petrographic evidence supports the view that the extensive dissolution of carbonate cements in sandstone rocks is usually associated with a high flux of deep hot fluids provided via fault systems or with meteoric freshwater during the eodiagenesis and telodiagenesis stages. The presumption of extensive mesogenetic dissolution of carbonate cements producing a significant net increase in secondary porosity should be used with careful consideration of the geological background in prediction of sandstone quality.
基金supported by the Important National Science&Technology Specific Project (2008ZX05002-004)
文摘The tight sandstones of the Upper Triassic Xujiahe Formation（T_3x） constitute important gas reservoirs in western Sichuan.The Xujiahe sandstones are characterized by low to very low porosity （av.5.22%and 3.62%） for the T_3x^4 and T_3x^2 sandstones,respectively）,extremely low permeability（av. 0.060 mD and 0.058 mD for the T_3x^4 and T_3x^2 sandstones,respectively）,strong heterogeneity,micronano pore throat,and poor pore throat sorting.As a result of complex pore structure and the occurrence of fractures,weak correlations exist between petrophysical properties and pore throat size,demonstrating that porosity or pore throat size alone does not serve as a good permeability predictor.Much improved correlations can be obtained between permeability and porosity when pore throat radii are incorporated. Correlations between porosity,permeability,and pore throat radii corresponding to different saturations of mercury were established,showing that the pore throat radius at 20%mercury saturation（R_（20）） is the best permeability predictor.Multivariate regression analysis and artificial neural network（ANN） methods were used to establish permeability prediction models and the unique characteristics of neural networks enable them to be more successful in predicting permeability than the multivariate regression model.In addition, four petrophysical rock types can be identified based on the distributions of R_（20）,each exhibiting distinct petrophysical properties and corresponding to different flow units.
基金funding support from the Qinghai Oilfield Company of the China National Petroleum Corporation
文摘Influenced by neo-tectonic movement, the Sanhu area of China＇s Qaidam Basin formed in the Quaternary in response to migration of its depocentre. A study of core material from the Qijia 1 Well reveals novel Quaternary aqueously deposited aeolian sandstones in the Qigequan Formation of the Sanhu area. Here we report the sedimentary petrology and geochemistry data of these deposits that constrain their depositional history. Evidence for aeolian influence during deposition includes： sorting and roundness, pure quartz sand with single mode grain size distribution and few suspension materials,very fine sand grain size distribution indicating sorting by saltation and suspension transport, dish-shaped and crescentshaped pits in grain surfaces indicating aeolian transport and chemical composition similar to that observed in active or recent dune deposits, namely enrichment in Si O_2, Na_2 O, and Mg O relative to the sand dam sediment in the lakeshore.Identification of these aqueously deposited aeolian sandstones expands the range of sedimentary deposit types found in the Sanhu area and improves understanding of its paleoclimatic history.
基金supported by the National Natural Science Foundation Project (No.40772088)the National Basic Research Program ("973" Program,Grant No. 2006CB202305)
文摘Hydrocarbon resources in low-permeability sandstones are very abundant and are extensively distributed. Low-permeability reservoirs show several unique characteristics, including lack of a definite trap boundary or caprock, limited buoyancy effect, complex oil-gas-water distribution, without obvious oil-gas-water interfaces, and relatively low oil （gas） saturation. Based on the simulation experiments of oil accumulation in low-permeability sandstone （oil displacing water）, we study the migration and accumulation characteristics of non-Darcy oil flow, and discuss the values and influencing factors of relative permeability which is a key parameter characterizing oil migration and accumulation in low-permeability sandstone. The results indicate that： 1） Oil migration （oil displacing water） in low- permeability sandstone shows non-Darcy percolation characteristics, and there is a threshold pressure gradient during oil migration and accumulation, which has a good negative correlation with permeability and apparent fluidity; 2） With decrease of permeability and apparent fluidity and increase of fluid viscosity, the percolation curve is closer to the pressure gradient axis and the threshold pressure gradient increases. When the apparent fluidity is more than 1.0, the percolation curve shows modified Darcy flow characteristics, while when the apparent fluidity up＂ non-Darcy percolation curve; 3） Oil-water is less than 1.0, the percolation curve is a ＂concave- two-phase relative permeability is affected by core permeability, fluid viscosity, apparent fluidity, and injection drive force; 4） The oil saturation of low- permeability sandstone reservoirs is mostly within 35%-60%, and the oil saturation also has a good positive correlation with the permeability and apparent fluidity.
基金We gratefully acknowledge the National Key R&D Program of China(Grant No.2019YFA0705502,Grant No.2019YFA0705501)the fnancial support from the Shandong Provincial Natural Science Foundation(ZR2019QEE037,ZR2019MEE058)the Fundamental Research Funds for the Central Universities(17CX05005,18CX02104A).
文摘The fractures and kerogen,which generally exist in the shale,are signifcant to the CO_(2) huf-n-puf in the shale reservoir.It is important to study the efects of fractures and kerogen on oil recovery during CO_(2) huf-n-puf operations in the fracture-matrix system.In this study,a modifed CO_(2) huf-n-puf experiment method is developed to estimate the recovery factors and the CO_(2) injectivity in the fractured organic-rich shales and tight sandstones.The efects of rock properties,injection pressure,and injection time on the recovery factors and CO_(2) usage efciency in shales and sandstones are discussed,respectively.The results show that although the CO_(2) injectivity in the shale is higher than that in the sandstone with the same porosity;besides,the recovery factors of two shale samples are much lower than that of two sandstone samples.This demonstrates that compared with the tight sandstone,more cycles are needed for the shale to reach a higher recovery factor.Furthermore,there are optimal injection pressures(close to the minimum miscible pressure)and CO_(2) injection volumes for CO_(2) huf-npuf in the shale.Since the optimal CO_(2) injection volume in the shale is higher than that in the sandstone,more injection time is needed to enhance the oil recovery in the shale.There is a reference sense for CO_(2) huf-n-puf in the fractured shale oil reservoir for enhanced oil recovery(EOR)purposes.
基金financially supported by National Major Projects of Fine Characterization of Complex Hydrocarbon Reservoir and Prediction of Remaining Oil Distribution (No. 20095009-003)
文摘A number of beach-bar sandstone reservoir beds are developed in the upper fourth member of the Eocene Shahejie Formation （Es4s） on the southern slope of the Dongying Sag.Based on the analysis of seismic and logging data,with characterization and petrographic studies of core and cutting samples,this paper analyzes the hydrocarbon accumulation characteristics in two typical blocks of the Boxing and Wangjiagang oilfields,especially reservoir bed heterogeneity and migration conditions that influence oil and gas distribution,calculates the index of reservoir bed quality （IRQ） with a mathematical method,and discusses the relationship between driving force and resistance of hydrocarbon accumulation.Taking into account the characteristics of thin interbeds in beach-bar sandstones,an experimental model simulated the characteristics of hydrocarbon migration and accumulation in thin interbedded sandstones with reservoir bed heterogeneity.The results showed that hydrocarbon distribution and properties were extremely non-uniform.Reservoir bed and migration conditions controlled hydrocarbon accumulation in beach-bar sandstones.IRQ is above 0.4 in the main hydrocarbon region.Sand body distribution,structural configuration and fault systems controlled the direction of regional migration and location of hydrocarbon accumulation.Simulation experiments indicated that the change of driving force for hydrocarbon migration affected selective accumulation mechanisms.Hydrocarbon moved vertically along fault zones to the reservoir and resulted in the distribution of hydrocarbon in the reservoir.Two kinds of hydrocarbon accumulation models exist in the study area.One is a hydrocarbon accumulation model controlled by reservoir bed heterogeneity and the second is a hydrocarbon accumulation model controlled by a complex migration system with faults connecting sandbodies.Finally,different exploration strategies should be adopted for the detailed exploration for beach-bar sandstone reservoirs according to different geological backgrounds.
基金supported by the National Science and Technology Major Project of the Ministry of Science and Technology of China(2016ZX05002-002)the National Natural Science Foundation of China(41972138).
文摘Fracability is a property that indicates how easy reservoir rocks can be fractured in hydraulic fracturing operations.It is a key parameter for fracturing design and evaluation.In order to utilize continuous logging data to predict fracability,synchronous tests of dynamic and static mechanical parameters of rocks under different confining pressures were conducted on13 tight sandstone samples derived from the central Junggar Basin,China.A modified formula between dynamic and static mechanical parameters was established.Fracability of the tight reservoir in the Junggar Basin was then evaluated based on brittleness index,fracture toughness,and fracability index.The effectiveness of fracturing was analyzed combined with the oil testing curve after hydraulic fracturing.The results show that:(1)The distribution of oil-bearing formations in the studied area coincides well with stratum of higher fracability index.(2)The critical fracability index is determined to be 0.3,three formations are selected as fracturing candidates,and a thin mudstone interbed is identified in the oil-bearing formation.(3)Well testing curve verifies the reliability of the fracability evaluation method and the accuracy of the modified formula between dynamic and static mechanical parameters.This study provides useful information for improving fracturing operations of tight oil and gas reservoirs.
基金financially supported by the National Natural Science Foundation of China(Grant No.41972138)the Technology Major Project of China(Grant No.ZD2019-183007,2016ZX05002-002)。
文摘Microscopic seepage characteristics are critical for the evaluation of tight sandstone reservoirs.In this study,a digital core approach integrating microscopic seepage simulation and CT scanning was developed to characterize microscopic seepage and fracture effectiveness(the ratio of micro-fractures that contributes to fluid flow)of tight sandstones.Numerical simulations were carried out for characterizations of tight sandstones.The results show that the axial permeability of the investigated cylindrical tight sandstone from Junggar Basin in China is 0.460μm~2,while the radial permeability is 0.3723μm~2,and the axial and radial effective fracture ratios are 0.4387 and 0.4806,respectively,indicating that cracks are not fully developed and the connectivity between micro-cracks is poor.Directional permeability that is difficult to measure by laboratory experiments can be obtained readily using the proposed method in this paper.The results provide important information for improving the exploration and development of tight sandstone reservoirs.
基金Supported by the National Natural Science Foundation of China(4167212441502147)PetroChina Science and Technology Major Project(2016ZX05047001-002)
文摘The tight sandstones in the Permian Lower Shihezi Formation of Shilijiahan area in the Ordos Basin was taken as study object in this research to quantitatively determine the effects of burial depth, burial time and compaction strength on porosity during densification of reservoir. Firstly, sandstone compaction profiles were analyzed in detail. Secondly, the theoretical study was performed based on visco-elasto-plastic stress–strain model. Thirdly, multiple regression and iterative algorithm were used respectively to ascertain the variation trends of Young's modulus and equivalent viscosity coefficient with burial depth and burial time. Accordingly, the ternary analytic porosity-reduction model of sandstone compaction trend was established. Eventually, the reasonability of improved model was tested by comparing with thin-section statistics under microscope and the models in common use. The study shows that the new model can divide the porosity reduction into three parts, namely, elastic porosity loss, visco-plastic porosity loss and porosity loss from cementation. And the results calculated by the new model of litharenite in He 2 Member are close to the average value from the thin-section statistics on Houseknecht chart, which approximately reveals the relative magnitudes of compaction and cementation in the normal evolution trend of sandstone porosity. Furthermore, the model can more exactly depict the compaction trend of sandstone affected little by dissolution than previous compaction models, and evaluate sandstone compaction degree and its contribution to reservoir densification during different burial and uplift processes.
基金supported by the National Natural Science Foundation of China(Grant Nos.42074153 and 42274160)。
文摘Estimating gas enrichments is a key objective in exploring sweet spots within tight sandstone gas reservoirs.However,the low sensitivity of elastic parameters to gas saturations in such formations makes it a significant challenge to reliably estimate gas enrichments using seismic methods.Through rock physical modeling and reservoir parameter analyses conducted in this study,a more suitable indicator for estimating gas enrichment,termed the gas content indicator,has been proposed.This indicator is formulated based on effective fluid bulk modulus and shear modulus and demonstrates a clear positive correlation with gas content in tight sandstones.Moreover,a new seismic amplitude variation versus offset(AVO)equation is derived to directly extract reservoir properties,such as the gas content indicator and porosity,from prestack seismic data.The accuracy of this proposed AVO equation is validated through comparison with the exact solutions provided by the Zoeppritz equation.To ensure reliable estimations of reservoir properties from partial angle-stacked seismic data,the proposed AVO equation is reformulated within the elastic impedance inversion framework.The estimated gas content indicator and porosity exhibit favorable agreement with logging data,suggesting that the obtained results are suitable for reliable predictions of tight sandstones with high gas enrichments.Furthermore,the proposed methods have the potential to stimulate the advancement of other suitable inversion techniques for directly estimating reservoir properties from seismic data across various petroleum resources.
基金financially supported by the National Natural Science Foundation of China (No. 42272156)research on efficient exploration and development technology for tight stone gas of China United Coalbed Methane Corporation (No. ZZGSECCYWG 2021-322)。
文摘In this study, an integrated approach for diagenetic facies classification, reservoir quality analysis and quantitative wireline log prediction of tight gas sandstones(TGSs) is introduced utilizing a combination of fit-for-purpose complementary testing and machine learning techniques. The integrated approach is specialized for the middle Permian Shihezi Formation TGSs in the northeastern Ordos Basin, where operators often face significant drilling uncertainty and increased exploration risks due to low porosities and micro-Darcy range permeabilities. In this study, detrital compositions and diagenetic minerals and their pore type assemblages were analyzed using optical light microscopy, cathodoluminescence, standard scanning electron microscopy, and X-ray diffraction. Different types of diagenetic facies were delineated on this basis to capture the characteristic rock properties of the TGSs in the target formation.A combination of He porosity and permeability measurements, mercury intrusion capillary pressure and nuclear magnetic resonance data was used to analyze the mechanism of heterogeneous TGS reservoirs.We found that the type, size and proportion of pores considerably varied between diagenetic facies due to differences in the initial depositional attributes and subsequent diagenetic alterations;these differences affected the size, distribution and connectivity of the pore network and varied the reservoir quality. Five types of diagenetic facies were classified:(i) grain-coating facies, which have minimal ductile grains, chlorite coatings that inhibit quartz overgrowths, large intergranular pores that dominate the pore network, the best pore structure and the greatest reservoir quality;(ii) quartz-cemented facies,which exhibit strong quartz overgrowths, intergranular porosity and a pore size decrease, resulting in the deterioration of the pore structure and reservoir quality;(iii) mixed-cemented facies, in which the cementation of various authigenic minerals increases the micropores, resulting in a poor pore structure and reservoir quality;(iv) carbonate-cemented facies and(v) tightly compacted facies, in which the intergranular pores are filled with carbonate cement and ductile grains;thus, the pore network mainly consists of micropores with small pore throat sizes, and the pore structure and reservoir quality are the worst. The grain-coating facies with the best reservoir properties are more likely to have high gas productivity and are the primary targets for exploration and development. The diagenetic facies were then translated into wireline log expressions(conventional and NMR logging). Finally, a wireline log quantitative prediction model of TGSs using convolutional neural network machine learning algorithms was established to successfully classify the different diagenetic facies.
基金supported by the National Natural Science Foundation of China (42104121)the Scientific Research and Technology Development Project of the CNPC (2021DJ0606)。
文摘Quantitative prediction of reservoir properties(e.g., gas saturation, porosity, and shale content) of tight reservoirs is of great significance for resource evaluation and well placements. However, the complex pore structures, poor pore connectivity, and uneven fluid distribution of tight sandstone reservoirs make the correlation between reservoir parameters and elastic properties more complicated and thus pose a major challenge in seismic reservoir characterization. We have developed a partially connected double porosity model to calculate elastic properties by considering the pore structure and connectivity, and to analyze these factors' influences on the elastic behaviors of tight sandstone reservoirs. The modeling results suggest that the bulk modulus is likely to be affected by the pore connectivity coefficient, while the shear modulus is sensitive to the volumetric fraction of stiff pores. By comparing the model predictions with the acoustic measurements of the dry and saturated quartz sandstone samples, the volumetric fraction of stiff pores and the pore connectivity coefficient can be determined. Based on the calibrated model, we have constructed a 3D rock physics template that accounts for the reservoir properties' impacts on the P-wave impedance, S-wave impedance, and density. The template combined with Bayesian inverse theory is used to quantify gas saturation, porosity, clay content, and their corresponding uncertainties from elastic parameters. The application of well-log and seismic data demonstrates that our 3D rock physics template-based probabilistic inversion approach performs well in predicting the spatial distribution of high-quality tight sandstone reservoirs in southwestern China.
基金Supported by the National Natural Science Foundation of China(42202176)CNPC-Southwest University of Petroleum Innovation Consortium Cooperation Project(2020CX050103).
文摘To clarify the formation and distribution of feldspar dissolution pores and predict the distribution of high-quality reservoir in gravity flow sandstone of the 7^(th) member of Triassic Yanchang Formation(Chang 7 Member)in the Ordos Basin,thin sections,scanning electron microscopy,energy spectrum analysis,X-ray diffraction whole rock analysis,and dissolution experiments are employed in this study to investigate the characteristics and control factors of feldspar dissolution pores.The results show that:(1)Three types of diagenetic processes are observed in the feldspar of Chang 7 sandstone in the study area:secondary overgrowth of feldspar,replacement by clay and calcite,and dissolution of detrital feldspar.(2)The feldspar dissolution of Chang 7 tight sandstone is caused by organic acid,and is further affected by the type of feldspar,the degree of early feldspar alteration,and the buffering effect of mica debris on organic acid.(3)Feldspars have varying degrees of dissolution.Potassium feldspar is more susceptible to dissolution than plagioclase.Among potassium feldspar,orthoclase is more soluble than microcline,and unaltered feldspar is more soluble than early kaolinized or sericitized feldspar.(4)The dissolution experiment demonstrated that the presence of mica can hinder the dissolution of feldspar.Mica of the same mass has a significantly stronger capacity to consume organic acids than feldspar.(5)Dissolution pores in feldspar of Chang 7 Member are more abundant in areas with low mica content,and they improve the reservoir physical properties,while in areas with high mica content,the number of feldspar dissolution pores decreases significantly.
基金funding support from the National Natural Science Foundation of China(Nos.52174088 and 42277154)the Independent Innovation Research Fund Graduate Free Exploration Project(No.104972024JYS0007)supported by Wuhan University of Technology.
文摘Underground engineering often passes through water-rich fractured rock masses, which are prone to fracture and instability under the long-term coupling of in-situ stress field and pore water(P-W) pressure, ultimately threatening the stability of underground structures. In order to explore the mechanical properties of rocks under H-M coupling, the corresponding damage constitutive(D-C) model has become the focus of attention. Considering the inadequacy of the current research on rock strength parameters,energy evolution characteristics and D-C model under H-M coupling, the mechanical properties of typical sandstone samples are discussed based on laboratory tests. The results show that the variation of characteristic stresses of sandstone under H-M coupling conforms to the normalized attenuation equation and Mohr-Coulomb(M-C) criterion. The P-W pressure mechanism of sandstone exhibits a dynamic change from softening effect to H-M fracturing effect. The closure stress is mainly provided by cohesive strength, while the initiation stress, damage stress, and peak stress are jointly dominated by cohesive strength and friction strength. In addition, residual stress is attributed to the friction strength formed by the bite of the fracture surface. Subsequently, the energy evolution characteristics of sandstone under H-M coupling were studied, and it was found that P-W pressure weakened the energy storage capacity and energy dissipation capacity of sandstone, and H-M fracturing was an important factor in reducing its energy storage efficiency. Finally, combined with energy dissipation theory and statistical damage theory, two types of D-C models considering P-W pressure are proposed accordingly, and the model parameters can be determined by four methods. The application results indicate that the proposed and modified D-C models have high reliability, and can characterize the mechanical behavior of sandstone under H-M coupling, overcome the inconvenience of existing D-C models due to excessive mechanical parameters,and can be applied to the full-range stress–strain process. The results are conducive to revealing the deformation and damage mechanisms of rocks under H-M coupling, and can provide theoretical guidance for related engineering problems.
基金the National Natural Science Foundation of China(Nos.51988101 and 42007262).
文摘3D printing is widely adopted to quickly produce rock mass models with complex structures in batches,improving the consistency and repeatability of physical modeling.It is necessary to regulate the mechanical properties of 3D-printed specimens to make them proportionally similar to natural rocks.This study investigates mechanical properties of 3D-printed rock analogues prepared by furan resin-bonded silica sand particles.The mechanical property regulation of 3D-printed specimens is realized through quantifying its similarity to sandstone,so that analogous deformation characteristics and failure mode are acquired.Considering similarity conversion,uniaxial compressive strength,cohesion and stress–strain relationship curve of 3D-printed specimen are similar to those of sandstone.In the study ranges,the strength of 3D-printed specimen is positively correlated with the additive content,negatively correlated with the sand particle size,and first increases then decreases with the increase of curing temperature.The regulation scheme with optimal similarity quantification index,that is the sand type of 70/140,additive content of 2.5‰and curing temperature of 81.6℃,is determined for preparing 3D-printed sandstone analogues and models.The effectiveness of mechanical property regulation is proved through uniaxial compression contrast tests.This study provides a reference for preparing rock-like specimens and engineering models using 3D printing technology.
基金Supported by the Original Exploration Project of National Natural Science Foundation of China(5215000105)Young Teachers Fund for Higher Education Institutions of Huo Yingdong Education Foundation(171043)。
文摘A simulated oil viscosity prediction model is established according to the relationship between simulated oil viscosity and geometric mean value of T2spectrum,and the time-varying law of simulated oil viscosity in porous media is quantitatively characterized by nuclear magnetic resonance(NMR)experiments of high multiple waterflooding.A new NMR wettability index formula is derived based on NMR relaxation theory to quantitatively characterize the time-varying law of rock wettability during waterflooding combined with high-multiple waterflooding experiment in sandstone cores.The remaining oil viscosity in the core is positively correlated with the displacing water multiple.The remaining oil viscosity increases rapidly when the displacing water multiple is low,and increases slowly when the displacing water multiple is high.The variation of remaining oil viscosity is related to the reservoir heterogeneity.The stronger the reservoir homogeneity,the higher the content of heavy components in the remaining oil and the higher the viscosity.The reservoir wettability changes after water injection:the oil-wet reservoir changes into water-wet reservoir,while the water-wet reservoir becomes more hydrophilic;the degree of change enhances with the increase of displacing water multiple.There is a high correlation between the time-varying oil viscosity and the time-varying wettability,and the change of oil viscosity cannot be ignored.The NMR wettability index calculated by considering the change of oil viscosity is more consistent with the tested Amott(spontaneous imbibition)wettability index,which agrees more with the time-varying law of reservoir wettability.
文摘The Santos Basin in Brazil has witnessed significant oil and gas discoveries in deepwater pre-salt since the 21^(st)century.Currently,the waters in eastern Brazil stand out as a hot area of deepwater exploration and production worldwide.Based on a review of the petroleum exploration and production history in Brazil,the challenges,researches and practices,strategic transformation,significant breakthroughs,and key theories and technologies for exploration from onshore to offshore and from shallow waters to deep-ultra-deep waters and then to pre-salt strata are systematically elaborated.Within 15 years since its establishment in 1953,Petrobras explored onshore Paleozoic cratonic and marginal rift basins,and obtained some small to medium petroleum discoveries in fault-block traps.In the 1970s,Petrobras developed seismic exploration technologies and several hydrocarbon accumulation models,for example,turbidite sandstones,allowing important discoveries in shallow waters,e.g.the Namorado Field and Enchova fields.Guided by these models/technologies,significant discoveries,e.g.the Marlim and Roncador fields,were made in deepwater post-salt in the Campos Basin.In the early 21^(st)century,the advancements in theories and technologies for pre-salt petroleum system,carbonate reservoirs,hydrocarbon accumulation and nuclear magnetic resonance(NMR)logging stimulated a succession of valuable discoveries in the Lower Cretaceous lacustrine carbonates in the Santos Basin,including the world-class ultra-deepwater super giant fields such as Tupi(Lula),Mero and Buzios.Petroleum development in complex deep water environments is extremely challenging.By establishing the Technological Capacitation Program in Deep Waters(PROCAP),Petrobras developed and implemented key technologies including managed pressure drilling(MPD)with narrow pressure window,pressurized mud cap drilling(PMCD),multi-stage intelligent completion,development with Floating Production Storage and Offloading units(FPSO),and flow assurance,which remarkably improved the drilling,completion,field development and transportation efficiency and safety.Additionally,under the limited FPSO capacity,Petrobras promoted the world-largest CCUS-EOR project,which contributed effectively to the reduction of greenhouse gas emissions and the enhancement of oil recovery.Development and application of these technologies provide valuable reference for deep and ultra-deepwater petroleum exploration and production worldwide.The petroleum exploration in Brazil will consistently focus on ultra-deep water pre-salt carbonates and post-salt turbidites,and seek new opportunities in Paleozoic gas.Technical innovation and strategic cooperation will be held to promote the sustainable development of Brazil's oil and gas industry.
基金Supported by the National Key R&D Project(2019YFC1805505)National Natural Science Foundation of China(42272188,42172149,U2244209)+2 种基金Science and Technology Special Project of China National Petroleum Corporation(2023YQX10101)Petrochemical Joint Fund Integration Project of National Natural Science Foundation of China(U20B6001)Shale Gas Academician Workstation Project of Guizhou Energy Industry Research Institute Co.,Ltd.([2021]45-2)。
文摘Based on an elaboration of the resource potential and annual production of tight sandstone gas and shale gas in the United States and China,this paper reviews the researches on the distribution of tight sandstone gas and shale gas reservoirs,and analyzes the distribution characteristics and genetic types of tight sandstone gas reservoirs.In the United States,the proportion of tight sandstone gas in the total gas production declined from 20%-35%in 2008 to about 8%in 2023,and the shale gas production was 8310×10^(8)m^(3)in 2023,about 80%of the total gas production,in contrast to the range of 5%-17%during 2000-2008.In China,the proportion of tight sandstone gas in the total gas production increased from 16%in 2010 to 28%or higher in 2023.China began to produce shale gas in 2012,with the production reaching 250×10^(8)m^(3)in 2023,about 11%of the total gas production of the country.The distribution of shale gas reservoirs is continuous.According to the fault presence,fault displacement and gas layer thickness,the continuous shale gas reservoirs can be divided into two types:continuity and intermittency.Most previous studies believed that both tight sandstone gas reservoirs and shale gas reservoirs are continuous,but this paper holds that the distribution of tight sandstone gas reservoirs is not continuous.According to the trap types,tight sandstone gas reservoirs can be divided into lithologic,anticlinal,and synclinal reservoirs.The tight sandstone gas is coal-derived in typical basins in China and Egypt,but oil-type gas in typical basins in the United States and Oman.
基金supported by the National Natural Science Foundation of China(No.40972098,41272168)China Postdoctoral Science Foundation(2012M511941)
文摘A better understanding of the controls on reservoir quality has become essential in the petroleum exploration in recent years. Determining the original composition of tile sediment framework is important not only for paleogeographic reconstructions, but it is also vital tbr predicting the nature of physical and chemical diagenesis of the potential reservoirs. Depositional setting and diagenesis are important factors in controlling the type and quality of most siliciclastic reservoirs. We studied the Upper Triassic Chang 8 and 6 members, where the relationship between sediment provenance and diagenesis was examined. The study attempts to clarify sediment provenance and post-depositional diagenetic modifications of the sandstones through systematic analytical methods including petrographic macro- and microscopic analysis of grain and heavy mineral types, and measurements of the palaeocurrent direction of the Yanchang Formation sediments in the outcrops in order to determine the provenance of the studied sediments. Furthermore, the relationship between framework grains, pore types and diagenesis of the sediments was analyzed by thin section petrographic characterization using a polarizing microscope. Additionally, a JEOL JSM-T330 scanning electron microscope （SEM） equipped with a digital imaging system was used to investigate the habits and textural relationships of diagenetic minerals. On the basis of our results, we believe that sediment provenance is a significant factor which controls the type and degree of diagenesis which may be expected in sandstones. In the Chang 8 and 6 members, tile formation of chlorite rims and laumontite cement was observed where volcanic rock fragments constitute a large part of the framework grains. Furthermore, high biotite content provides abundant iron and magnesium and enables the tbnnation of chlorite rims due to biotite hydrolysis. In addition, ductile deformation of biotite leads to strong mechanical compaction of the sediments. Conversely, high feldspar content diminishes the degree of mechanical compaction, however the dissolution of feldspar minerals in sandstones is commonly observed. Apart from feldspars, quartz and other rigid fi＇amework grains highly control the degree of mechanical compaction during the initial stage of burial （0-2 km）.
