Reservoir Physical Properties Research Articles

Reservoir characteristics analysis and favorable area prediction of Zhuhai Formation, Wenchang A oilfield, South China Sea

Wenchang A oilfield is a recently discovered low-permeability oilfield in the western South China Sea. The exploration target is the Zhuhai Formation, which reservoir lithology changes significantly, and the distribution of favorable reservoirs is unclear. In this study, the reservoir characteristics of the Zhuhai Formation in the Wenchang A oilfield, South China Sea, were analyzed through core identification, thin section identification, physical property testing, pre-stack geostatistical inversion, and frequency-based AVO inversion. Pre-stack geostatistical inversion is based on geostatistics and combines the seismic inversion algorithm with the stochastic sequential simulation algorithm. While the frequency-varying AVO inversion method is an extension of the conventional AVO inversion method, with its core technology being spectrum decomposition. After frequency division, multiple data sets directly participate in the calculation, which enhances the stability and accuracy of inversion.We also predict the favorable reservoir areas of six small layers in the Zhuhai Formation. The results show that 1) the reservoir lithology of the Zhuhai Formation mainly consists of feldspar quartz sandstone and feldspar quartz sandstone, indicating high compositional maturity. The porosity of the reservoir ranges from 14.0% to 19.0%, with an average value of 16.3%. The permeability of the reservoir ranges from 3.1 mD to 126.1 mD, with an average value of 22.4 mD, indicating a medium porosity and low permeability reservoir. The supporting structure of a sandstone reservoir is particle-supported, with the main contact being the “point-line” contact between particles. The main types of pores in sandstone are primary intergranular pores and secondary intergranular dissolved pores. Some pores are feldspar-dissolved pores, and occasionally there are hetero-based micropore. 2) The diagenesis of the Zhuhai Formation reservoir mainly includes compaction, cementation, and dissolution. Cementation and dissolution have minimal impact on the physical properties of reservoirs. The porosity loss of the reservoir after compaction ranges between 16.0% and 27.9%, and the compaction rate ranges between 40.0% and 69.8%, indicating a medium compaction diagenetic facies. 3) The favorable areas of each layer of the Zhuhai Formation are mainly concentrated in the southwest of the study area. The upper layer of ZH1I, the upper layer of ZH1II and the lower layer of ZH1II exhibit the best physical properties, the thickest favorable sand body, the strongest oil and gas display, the widest range of favorable areas, and the greatest exploration potential. The favorable exploration potential of layer 1 in the lower part of ZH1I and layer 2 in the upper part of ZH1II is moderate. The second layer in the lower part of ZH1II has the poorest properties and lower exploration potential. The main factors affecting the favorable area include physical properties, oil and gas display, sand body thickness, etc.

Reservoir Quality Under the Control of Gravity Flows in the C7 Member of Yanchang Formation in the Jinghe Oilfield, Ordos Basin, China

The late Triassic sandstone reservoir in the C7 member of the Jinghe oilfield southern Ordos basin is a typical deep-water gravity flow tight oil reservoir. Sedimentary microfacies, physical properties, and petrographic analysis were being examined for quality determination. Pore structure and physical properties data together combined with, thin sections, and scanning electron microscope and core images were used to identify factors controlling reservoir physical properties. The depositional system under debates of different gravity flows including debris flow, seismite slumping, and turbidity flows. Among which sandy debris flow facies shows a better distribution of porosity and permeability followed by seismite-slump, where turbidity facies are the poorest. The petrophysical analysis shows that the study oil interval is a typical tight sandstone reservoir with an average porosity of 9% and permeability average being 0.025mD. The rock classification criteria of the C7 sandstone reveal the sub-categories of lithic feldspar sandstone and feldspar lithic sandstone. Average quartz sandstone contents of 48.25%, average feldspar sandstone content being 25%, and lithic fragments content of 29%. The formation lithology comprises mostly fine-grained sandstone and small pore size, which disclose that the porosity-permeability distribution increases proportional to the average and median pore throat radius, and decreases with average and median pressure. The microfacies distribution shows that the depositional facies controlled physical properties. The sandstone primary pores are affected by the mineral composition of quartz, feldspar, illite, smectite, kaolinite, calcite, and dolomite. Features such as dissolved pores and intergranular pore filling by feldspar, silky-like aggregates of illite-smectite intergranular pore filling and most diagenetic minerals influenced the sandstone pores beside the compaction.

Dynamic seismic signatures in a fluid‐saturated porous periodically layered medium considering effects of intrinsic anisotropy

AbstractThe interlayer wave‐induced fluid flow is an important mechanism for seismic attenuation and dispersion, as well as frequency‐dependent anisotropy, in the fluid‐saturated porous layered medium. This mechanism is closely related to the medium physical properties, and thus quantifying this mechanism is of significance for the seismic inversion of medium physical properties. Although numerous models have been proposed to quantify this mechanism, most models do not consider the effects of layer intrinsic anisotropy. To solve this problem, the effective complex‐valued and frequency‐dependent stiffness coefficients are derived for the fluid‐saturated porous medium composed of periodic transversely isotropic layers. Using the derived solutions, we study the effects of layer intrinsic anisotropy on seismic dispersion and attenuation, as well as frequency‐dependent anisotropy. It has been found that different matrix or fluid property contrasts between adjacent layers lead to different effects of intrinsic anisotropy. In addition, the effects of intrinsic anisotropy are also influenced by the fluid distribution when both matrix and fluid properties contrast among adjacent layers exist. In the low‐ and high‐frequency limits of wave‐induced fluid flow, our model reduces to the previous known results, which validates the correctness of our model. Our model can be applied in the seismic inversion of physical properties of reservoirs with intrinsic anisotropy, such as shale and tight sandstone reservoirs. In addition, our model can also be extended to cases with more complex intrinsic anisotropy and, thus, can be applied to complex anisotropic fractured reservoirs in the future.

Quantitative characterization and fracture morphology in reservoirs with various lithologies: An experimental investigation

Accurately quantifying the development of hydraulic fractures is pivotal for further elucidating the relationship between reservoir physical properties and hydraulic fracture propagation. In this research, we centered on reservoirs featuring diverse lithologies, procured downhole full-diameter cores, conducted triaxial hydraulic fracturing experiments, and employed CT scanning and electron microscopy to characterize fracture morphology. The primary findings are summarized as follows: sandstones specimens typically exhibit bi-wing fractures inclined at a certain angle to σH, with internal microfractures predominantly comprised of corrugated shear fractures traversing mineral grains. Conversely, conglomerate specimens display a higher prevalence of branching fractures, with fracture zones forming in areas of gravel densities and weak heterogeneous matrices, along with the development of multiple microfractures. Volcanic rock specimens fractures primarily propagate via deflection following NF activation, showcasing two modes of microfracture propagation: through and alongside the NF. Quantitative parameters of fracture morphology indicate that the fractal dimension ranges from 2.02 to 2.08 for sandstone fractures, 2.19 to 2.22 for conglomerate fractures, and 2.11 to 2.13 for volcanic rock fractures. Notably, the NF filler in volcanic rock undergoes erosion by fracturing fluid, accumulating non-uniformly on the surface of rock crystals, thereby augmenting fracture tortuosity. Additionally, the fracture surface area of conglomerates surpasses that of sandstones and volcanic rocks by 1.3 times, with the stripping rate of conglomerate fracture surfaces exceeding 10%. Furthermore, the average normal width of conglomerate fractures surpasses 2 mm, whereas volcanic rock and sandstone measure 1.6 mm and 1.1 mm, respectively. Notably, sandstone fractures exhibit uniform normal width distribution, while conglomerate fractures, especially those around gravels and eroded by fracturing fluid, manifest larger widths. Moreover, NF influenced volcanic rock fractures also exhibit wider widths. Elucidating the quantitative attributes of fracture morphology in lithologically diverse reservoirs holds significant implications for formulating hydraulic fracturing and targeted optimization strategies aimed at enhancing fracturing efficacy.

Investigation of Asphaltene Precipitation and Reservoir Damage during CO2 Flooding in High-Pressure, High-Temperature Sandstone Oil Reservoirs

Summary Asphaltenes are heavy aromatic hydrocarbon compounds contained in reservoir fluids and may precipitate when the reservoir pressure is reduced by production or when gas is injected into the reservoir, and then further deposit on pore-throat surfaces causing reservoir damage. At present, the research on asphaltene precipitation and reservoir damage is carried out in conventional reservoirs, and the influence of CO2 injection under high-pressure, high-temperature (HPHT) conditions has not yet been clearly understood. In this work, we combined perturbed-chain statistical association fluid theory (PC-SAFT) calculation, experiments, phase-state simulation, and numerical simulation to predict the asphaltene precipitation with different pressures, temperatures, and amounts of injected gas and to clarify the influence on reservoir permeability and oil production when using CO2 injection. The results show that the precipitation of asphaltenes in the process of CO2 injection is the desorption of colloid-asphaltene inclusions caused by gas molecules and then the mutual polymerization process between dispersed asphaltene molecules. CO2 injection will increase the amount of precipitation and move the precipitation curve to the right side. The degree of permeability reduction caused by the deposition of asphaltenes in the core is 12.87–37.54%; the deposition of asphaltenes in the reservoir is mainly around the injection/production wells and along the injected gas profile. Considering asphaltenes, the oil recovery degree is reduced by 1.5%, and the injection rate is reduced by 17%. The reservoir pressure, temperature, and physical properties have a strong correlation with the degree of reservoir damage, while the initial asphaltene content has a low correlation. This work will be of great interest to operators seeking to enhance oil recovery by CO2 injection in deep reservoirs.

Dynamic Evolution Mechanism of Reservoir Physical Properties during Oil Shale In Situ Conversion

Dynamic Evolution Mechanism of Reservoir Physical Properties during Oil Shale In Situ Conversion

Pore‐throat structure and fractal characteristics of tight gas sandstone reservoirs: A case study of the second member of the Upper Triassic Xujiahe Formation in Zhongba area, western Sichuan depression, China

Pore‐throat structure is a key factor that influences the storage and fluid flow capacity of tight sandstone reservoirs. Taking the tight sandstone reservoir of Xu2 Fm in Zhongba area as an example, the reservoir quality, pore‐throat type and pore size distribution of tight sandstone in the study area were described by casting thin section, scanning electron microscope and high‐pressure mercury injection test. In order to quantitatively characterize the complexity and heterogeneity of pore‐throat structure, fractal analysis was performed using mercury saturation and pore size data. This study mainly reveals the relationship between the geometric shape characteristics and fractal dimension of the binary pore structure of ultra‐low permeability tight sandstone and clarifies the influence of different scale pore throats on reservoir physical properties. The results indicate that the physical properties of the reservoir in the study area are poor, the pores are mainly intergranular pores and dissolution pores, the throat is flake and necked and the pore size distribution range is large. The fractal curve obtained by the mercury saturation method shows a significant turning point, and the pore‐throat system is divided into two types: small‐scale and large‐scale. The fractal dimension of large‐scale pore throat is greater than the three‐dimensional Euclidean space dimension, which does not conform to the fractal theory. The fractal dimension of small‐scale pore throat is closely related to the pore‐throat structure and has obvious fractal characteristics. The geometric shape of binary pore‐throat structure in tight sandstone is the main factor affecting the difference of fractal dimension. The development of small pores in sandstone is positively correlated with the total porosity, but its contribution to permeability is relatively low. The physical properties of tight sandstone are mainly controlled by the development degree of large‐scale pore throat.

Effective reservoir identification and sweet spot prediction in Chang 8 Member tight oil reservoirs in Huanjiang area, Ordos Basin

Abstract The Chang 8 reservoir of the Huanjiang Oilfield in the Ordos Basin is a tight sandstone reservoir with poor reservoir physical properties and uneven oil distribution. In this study, the effective reservoirs developed on a large scale under the condition of horizontal well volume fracturing technology of the Chang 8 Member was identified based on the data of core observation, experimental analysis, logging, oil test, and production dynamics, and the identification standard of effective reservoirs in terms of reservoir physical properties, oil content, and comprehensive logging characteristics of gas logging was established. This scheme allows for a thorough identification of the effective reservoirs for horizontal well development in tight sandstone reservoirs. The findings indicate that the study area’s tight oil resources can be successfully produced. The well logging results show that the oil-bearing property of sand bodies with oil stains is better than that of oil spots. The bottom limit of the acoustic wave time difference is 210 μs/m, the permeability is 0.03 mD, the porosity is 6.0%, the rock resistivity is 30 Ω m, and the total hydrocarbon gas measurement value exceeds five times the baseline. At the same time, the total oil thickness is greater than 6 m, and the thickness of a single sand body is above 4 m. We have defined the lower limit standard of high-efficiency reservoir of Chang 8 tight oil in L289 block of Huanjiang oilfield. According to the analysis of oil-bearing property, comprehensive logging display, and reservoir thickness, the geological “sweet spots” is optimized to provide reference for subsequent mining. Through comparative analysis, the rules and trends are found to provide a basis for selecting mining strategies. With the help of technical means such as numerical simulation and geological modeling, the prediction accuracy and decision-making effect are improved. By clarifying the lower limit standard of reservoir, optimizing geological “sweet spots” and avoiding risk areas, the mining efficiency is improved and the cost is reduced, which provides reference for similar oilfield development.

Enrichment model and major controlling factors of below-source tight oil in Lower Cretaceous Fuyu reservoirs in northern Songliao Basin, NE China

Based on the geochemical, seismic, logging and drilling data, the Fuyu reservoirs of the Lower Cretaceous Quantou Formation in northern Songliao Basin are systematically studied in terms of the geological characteristics, the tight oil enrichment model and its major controlling factors. First, the Quantou Formation is overlaid by high-quality source rocks of the Upper Cretaceous Qingshankou Formation, with the development of nose structure around sag and the broad and continuous distribution of sand bodies. The reservoirs are tight on the whole. Second, the configuration of multiple elements, such as high-quality source rocks, reservoir rocks, fault, overpressure and structure, controls the tight oil enrichment in the Fuyu reservoirs. The source-reservoir combination controls the tight oil distribution pattern. The pressure difference between source and reservoir drives the charging of tight oil. The fault-sandbody transport system determines the migration and accumulation of oil and gas. The positive structure is the favorable place for tight oil enrichment, and the fault-horst zone is the key part of syncline area for tight oil exploration. Third, based on the source-reservoir relationship, transport mode, accumulation dynamics and other elements, three tight oil enrichment models are recognized in the Fuyu reservoirs: (1) vertical or lateral migration of hydrocarbon from source rocks to adjacent reservoir rocks, that is, driven by overpressure, hydrocarbon generated is migrated vertically or laterally to and accumulates in the adjacent reservoir rocks; (2) transport of hydrocarbon through faults between separated source and reservoirs, that is, driven by overpressure, hydrocarbon migrates downward through faults to the sandbodies that are separated from the source rocks; and (3) migration of hydrocarbon through faults and sandbodies between separated source and reservoirs, that is, driven by overpressure, hydrocarbon migrates downwards through faults to the reservoir rocks that are separated from the source rocks, and then migrates laterally through sandbodies. Fourth, the differences in oil source conditions, charging drive, fault distribution, sandbody and reservoir physical properties cause the differential enrichment of tight oil in the Fuyu reservoirs. Comprehensive analysis suggests that the Fuyu reservoir in the Qijia–Gulong Sag has good conditions for tight oil enrichment and has been less explored, and it is an important new zone for tight oil exploration in the future.

Influence of reservoir physical properties on guar gum fracturing fluid damage in unconventional tight reservoirs

Solid phase residue, fracturing fluid filtration, and incomplete backflow during hydraulic fracturing can easily cause damage to tight sandstone reservoir. Thus, it is necessary to explore the relationship between the physical properties of tight reservoirs and damage caused by fracturing fluids. Based on the identification of reservoir physical properties, the relationship between reservoir physical properties and fracturing fluid damage was studied by core displacement, computerized tomography, and nuclear magnetic resonance (NMR). The results show that the higher the clay mineral content is, the denser the formed core is, and the corresponding core porosity and permeability are lower. When the permeability and porosity of the rock core are relatively high, the overall radius of the pore throat in the rock core shifts to the left under the action of the gel breaking fracturing fluid, showing a decreasing trend. However, when the permeability and porosity of the rock core are relatively low, the frequency peak of the smaller size of the pore throat in the rock core under the action of the gel breaking fracturing fluid increases upwards. The corresponding core permeability decline rate of the two types of tight sandstone reservoirs is 9.91%–8.78% and 15.85%–14.74%. The porosity decline rates are 5.53%–5.84% and 10.40%–9.94%. According to NMR results, it is speculated that under the action of gel breaking fracturing fluid, the small pore throats in the rock core are blocked or even disappear, while the proportion of smaller pore throats increases and the proportion of larger pore throats decreases. The results of this study provide theoretical reference for reservoir protection during the fracturing process of tight sandstone reservoirs.

Time-dependent model for two-phase flow in ultra-high water-cut reservoirs: Time-varying permeability and relative permeability

For the ultra-high water-cut reservoirs, after long-term water injection exploitation, the physical properties of the reservoir change and the heterogeneity of the reservoir becomes increasingly severe, which further aggravates the spatial difference of the flow field. In this study, the displacement experiments were employed to investigate the variations in core permeability, porosity, and relative permeability after a large amount of water injection. A relative permeability endpoint model was proposed by utilizing the alternating conditional expectation (ACE) transformation to describe the variation in relative permeability based on the experimental data. Based on the time dependent models for permeability and relative permeability, the traditional oil-water two-phase model was improved and discretized using the mimetic finite difference method (MFD). The two cases were launched to confirm the validation of the proposed model. The impact of time-varying physical features on reservoir production performance was studied in a real water flooding reservoir. The experimental results indicate that the overall relative permeability curve shifts to the right as water injection increases. This shift corresponds to a transition towards a more hydrophilic wettability and a decrease in residual oil saturation. The endpoint model demonstrates excellent accuracy and can be applied to time-varying simulations of reservoir physics. The impact of variations in permeability and relative permeability on the reservoir production performance yields two distinct outcomes. The time-varying permeability of the reservoir results in intensified water channeling and poor development effects. On the other hand, the time-varying relative permeability enhances the oil phase seepage capacity, facilitating oil displacement. The comprehensive time-varying behavior is the result of the combined influence of these two parameters, which closely resemble the actual conditions observed in oil field exploitation. The time-varying simulation technique of reservoir physical properties proposed in this paper can continuously and stably characterize the dynamic changes of reservoir physical properties during water drive development. This approach ensures the reliability of the simulation results regarding residual oil distribution.

Characteristics and Controlling Factors of Natural Fractures in Deep Carbonates of the Puguang Area, Sichuan Basin, China.

Understanding the types, characteristics, and controlling factors of natural fractures in deep and ultradeep carbonates is crucial for evaluating reservoir quality, optimizing well deployment, and comprehending their impact on hydrocarbon exploitation. Multiple types of natural fractures are widespread in the deep carbonates of the Feixianguan Formation in the Puguang area, northeastern Sichuan Basin, China, and the main controlling factors are complex. Based on geological, geophysical, and experimental data, this study defined fracture types and analyzed the fracture development characteristics in the deep Feixianguan carbonates. On this basis, the main geological factors that control the development and distribution of tectonic fractures were discussed by combining statistical and experimental analyses. Results indicate that natural fractures in the Feixianguan Formation can be genetically classified into tectonic and diagenetic fractures. Specifically, tectonic fractures include shear fractures and tensile fractures, in which the former are predominant. In the Feixianguan carbonates, tectonic shear fractures are mainly developed in the NE-SW and near E-W strikes, with dip angles mostly ranging from 30 to 70°. The majority of shear fractures appear on a small scale and have good effectiveness. The fracture heights and apertures are commonly less than 50 cm and 25 μm, respectively, and unfilled fractures account for more than half. The distribution and development of tectonic fractures are mainly controlled by lithology, mechanical stratigraphy, reservoir physical properties, diagenetic cementation, and faults. In the Feixianguan carbonates, tectonic fractures are more developed in crystalline dolomite. With the increasing thickness of mechanical stratigraphy, the fracture density decreases and the scale increases. The presence of early dissolution pores can prevent the formation of later tectonic fractures. Tectonic fractures in the NNW-SSE and near N-S strikes generally possess poor effectiveness due to multiple cementations after their formation. In the vicinity of faults, tectonic fractures generally stretch subparallel to the extension direction of the fault, and the development degree of fractures close to major faults is higher.

Reservoir Characterization of Alluvial Glutenite in the Guantao Formation, Bohai Bay Basin, East China

Alluvial glutenite reservoirs have obviously stronger heterogeneous and more complex control factors than sandstone reservoirs. Taking the Binxian Uplift area in the Boahi Bay Basin as an example, the aim of this study is to clarify the characteristics and control factors of the alluvial glutenite reservoir quality and the influence of reservoir properties on hydrocarbon accumulation. Pore types in the study area mainly include residual intergranular pores, intergranular dissolved pores, intragranular dissolved pores, and mold pores. The residual intergranular pores and intergranular dissolved pores are the main pore types. Most samples have porosity greater than 15% and permeability is mainly concentrated between 50 mD and 500 mD. It is shown that lithology type, microfacies, and diagenesis have significant impact on the reservoir quality. The reservoir qualities of very fine sandstone and fine sandstone are better than those of conglomerate and gravel-bearing sandstone. Instead of grain size, sorting affects the alluvial glutenite reservoir quality significantly. Oil-bearing samples commonly have sorting coefficient less than 2 while non-oil-bearing samples have sorting coefficient larger than 2. There are significant differences in reservoir physical properties of different sedimentary microfacies. The stream flow in mid-alluvial fan (SFMA) and braided channels outside alluvial fans (BCOA) have relatively weaker compaction and better reservoir quality than the overflow sand body (OFSB) and debris-flow in proximal alluvial fan (DFPA). Calcite cementation, the main cement in the study area, commonly developed at the base of SFMA and BCOA and near the sandstone-mudrock contacts. The source of calcium carbonate for calcite cement mainly came from around mudstone. High calcite cement content commonly results in low porosity and permeability. Individual glutenite thickness is also an important influencing factor on reservoir quality. Reservoirs with large thickness (>4 m) have high porosity and permeability. Dissolution occurred in the reservoir, forming secondary dissolution pores and improving reservoir quality. The dissolution fluid for formation of secondary pores is mainly meteoric waters instead of organic acid. The reservoir property has an important influence on hydrocarbon accumulation. The lower limit of physical properties of an effective reservoir is a porosity of 27% and permeability of 225 mD. The findings of this study can be utilized to predict the reservoir quality of alluvial glutenite reservoirs effectively in the Bohai Bay Basin and other similar basins.

Evaluation of Recovery of Tight Sandstone Gas Reservoirs Based on a Seepage Steady-State Model

As an important indicator for measuring the effectiveness and level of oil and gas field development, recovery rate has always been a focus in the research of oil and gas fields. Reservoirs of tight sandstone gas formations have significant characteristics of low porosity, high permeability, and high water content, which leads to greater difficulty in their development and makes it challenging to evaluate the recovery rate. Newtonian mechanics, as an important component of the mechanical system, is an innovative application of classical mechanics in the field of seepage mechanics when applied to the two-phase flow of gas and water. Firstly, starting from the perspective of mechanics analysis, we derive a steady-state model for gas–water two-phase infiltration and obtain the productivity equation based on this model. Then, according to the steady-state model, we establish a method to calculate the effective control radius of gas reservoirs under different production conditions and reservoir physical properties. Finally, using Matlab 2018a programming based on the productivity equation, we calculate the gas recovery under different conditions during constant pressure drop production and constant production rate production. The results indicate that the effective control radius of the reservoir decreases with an increase in the economic ultimate daily gas production, increases with an increase in production pressure difference, slightly decreases with an increase in startup pressure gradient, and correspondingly increases with an increase in microtube radius and quantity. Regardless of whether it is production with a fixed pressure drop or production with a fixed production rate, the gas recovery decreases as the production pressure drop and bottomhole abandonment pressure increase, but it increases as the proportion of the single-well control radius increases. In production with a fixed pressure drop, the gas recovery remains consistent across different reservoir quality indices. However, in production with a fixed production rate, the gas recovery initially increases rapidly and then gradually slows down as the reservoir quality index increases, and there is an obvious critical permeability (0.1 mD). The research findings are based on the mechanical analysis of porous media, delving into the laws governing fluid flow during infiltration. The derived infiltration model can be used to calculate the effective control radius and evaluate recovery rates, providing practical guidance for reservoir development.

Characteristics, Controlling Factors and Reservoir Quality Implications of Inner Fracture Zones in Buried Hills of Archean Covered Metamorphic Rock in Block 13-2, Bozhong Depression

Inner fracture zones play a decisive role in the formation of high-quality reservoirs in buried hill reservoirs in covered metamorphic rock. Based on core, sidewall core, thin section, seismic, logging and reservoir physical property data, the fracture development characteristics of the Bozhong 13-2 block buried hill reservoir are described in detail and the controlling factors and the influence on reservoir quality are discussed. The results showed: (1) three groups of tectonic fractures developed in the study area—near-EW-striking, ENE-striking and nearly N‒S-striking fractures—were controlled by the early Indosinian thrusting, the late Indosinian to early Yanshanian sinistral strike-slipping and the late Yanshanian late dextral strike-slipping in the Bohai Bay Basin, respectively. The ENE- and nearly-E-W-striking fractures are the most common, and the dip angles of the fractures are mostly between 35° and 75° and thus oblique. (2) The Indosinian-early Yanshanian was the main fracture-forming period, and the dextral strike-slip action in the late Yanshanian was the key to maintaining effective fractures. Imaging logging shows that 97.87% of the fractures are effective fractures. Based on thin section observation, 14.47% of the fractures are unmodified open fractures and 80.37% of the fractures are effective fractures due to reactivation. (3) The late Yanshanian strike-slip fault transformed the deformation adjustment zone formed by the early Indosinian thrust faulting and the core of the fold structure was more conducive to fracture development. The fracture density of a single well located within the deformation adjustment zone and at the core of the fold is between 0.93–1.49 m−1, the fracture density of a single well located only at the core of the fold is between 0.67–0.75 m−1 and that of a single well located at the wing of the fold is between 0.35–0.59 m−1. Diabase dike intrusions promoted the development of local fractures. (4) Fractures promote the migration and accumulation of oil and gas, and the fracture density in the oil layer is between 0.81–2.19 m−1. That in the nonoil layer is between 0.25–1.12 m−1. In addition, fractures not only provide storage space but also effectively improve the reservoir capacity of the inner fracture zones of buried hill reservoirs by concentrating dissolution.

Reactive transport modeling constraints on the complex genesis of a lacustrine dolomite reservoir: A case from the Eocene Qaidam Basin

Reactive transport modeling (RTM) is an emerging method used to address geological issues in diagenesis research. However, the extrapolation of RTM results to practical reservoir prediction is not sufficiently well understood. This paper presents a case study of the Eocene Qaidam Basin that combines RTM results with petrological and mineralogical evidences. The results show that the Eocene Xiaganchaigou Formation is characterized by mixed siliciclastic-carbonate-evaporite sedimentation in a semiclosed saline lacustrine environment. Periodic evaporation and salinization processes during the syngenetic-penecontemporaneous stage gave rise to the replacive genesis of dolomites and the cyclic enrichment of dolomite in the middle-upper parts of the meter-scale depositional sequences. The successive change in mineral paragenesis from terrigenous clastics to carbonates to evaporites was reconstructed using RTM simulations. Parametric uncertainty analyses further suggest that the evaporation intensity (brine salinity) and particle size of sediments (reactive surface area) were important rate-determining factors in the dolomitization, as shown by the relatively higher reaction rates under conditions of higher brine salinity and fine-grained sediments. Combining the simulation results with measured mineralogical and reservoir physical property data indicates that the preservation of original intergranular pores and the generation of porosity via replacive dolomitization were the major formation mechanisms of the distinctive lacustrine dolomite reservoirs (widespread submicron intercrystalline micropores) in the Eocene Qaidam Basin. The results confirm that RTM can be effectively used in geological studies, can provide a better general understanding of the dolomitizing fluid-rock interactions, and can shed light on the spatiotemporal evolution of mineralogy and porosity during dolomitization and the formation of lacustrine dolomite reservoirs.

Clarifying the contribution of multiscale pores to physical properties of Chang 7 tight sandstones: insight from full-scale pore structure and fractal characteristics

The pore structure and its heterogeneity of tight reservoirs are key factors affecting the storage and percolation of crude oil. The pore system of Chang 7 tight sandstone has multi-scale and multi-type characteristics. However, the contribution of different pore types and pore sizes to the physical properties of Chang 7 tight sandstone is still unclear. In this paper, we collected a suite of Chang 7 tight sandstones to investigate the full-scale pore structure and fractal characteristics by casting thin section, field emission scanning electron microscope, two-dimensional multi-scale backscattered scanning electron microscopy, N2 adsorption (NA) and NMR. The pore diameters of Chang 7 tight sandstone are usually distributed between 0.001 and 20 μm. Intercrystalline pores are mainly distuibuted <500 nm. Dissolution pores vary from 100 nm to 100 μm. Residual intergranular pores range from 1 μm to 40 μm. Based on the fractal characteristics, pore system is divided into macropores (mainly >300 nm), mesopores (mainly 7–300 nm), and micropores (mainly <7 nm). Micropores are adsorb-fluid pores that do not contribute to the storage and percolation but contribute significantly to contrasting specific surface area. Mesopores represent bound-fluid pores and only contribute to total porosity but not to permeability. Macropores represent movable-fluid pores, contributing to both porosity and permeability. The content and heterogeneity of macropores control the quality of Chang 7 tight sandstone. When macropore volume is >12×10−3 mL/g, the continuous percolation network consists entirely of macropores, resulting in higher porosity and permeability of the reservoir. Moreover, reservoir physical properties show excellent correlation with macropore heterogeneity. These results demonstrate that the content and heterogeneity of macropores are key indicators indicating the quality of the Chang 7 tight sandstones.

Lithofacies Characteristics of Gulong Shale and Its Influence on Reservoir Physical Properties

The lithofacies characteristics of the Qingshankou Formation (K2qn) shale in the Gulong Depression are crucial for oil exploration and development. This study investigates the K2qn shale lithofacies characteristics and their impact on reservoir physical properties using scanning electron microscopy (SEM), high-pressure mercury injection (HPMI), and logging quantification. The results indicate that the main minerals in K2qn shale are quartz, plagioclase, and clay. The sedimentary structures are classified into three types: laminated, layered, and massive. The K2qn shale lithofacies can be categorized into 12 types based on a combination of lithology and sedimentary structure. The main types are laminated clayey shale, layered clayey shale, and layered felsic shale. The larger the average pore size of the K2qn lithofacies, the stronger the heterogeneity of pore size distribution in space and the better the pore-to-throat connectivity. The impact of K2qn shale lithofacies on reservoir physical properties is mainly due to differences in lithology, complemented by variations in the sedimentary structural model. Under certain diagenetic or tectonic conditions, a layered sedimentary structural model of lithofacies may not increase reservoir permeability. Generally, felsic and carbonate rocks in tidal flat environments promote the development of shale with high permeability and porosity, while lithofacies deposited in static water environments below the wave base in lake basins typically exhibit low permeability and porosity. The physical properties of a reservoir are primarily influenced by the differences in pore throat characteristics resulting from variations in lithology.

Diagenetic alterations and deep high-quality reservoirs within deltaic distributary channel facies: a case study from the Permian Shihezi formation in the Hongde area, southwestern Ordos basin, China

Deep tight gas reservoirs are considered important hydrocarbon exploration targets. High-quality reservoir prediction is critical for successfully exploring and developing deeply buried tight sandstone gas. Previous research has found that the reservoir quality of deeply buried tight sandstones is controlled by diagenesis and sedimentary facies. However, the variation of diagenetic alterations in different facies is still poorly studied on deltaic tight gas sandstone. In this study, core analysis, wireline log data, and 3D seismic were studied for the characterization of diagenetic alterations and sedimentary facies. The tight sandstones were formed in braided river delta deposits. Gravel-bearing coarse-grained sandstone facies and cross-bedded sandstone facies developed in tight sandstones. The Gravel-bearing coarse-grained sandstone is formed in the mid-channel bar of deltaic distributary channels. The major diagenetic processes developed in the tight sandstone include compaction, cementation, and dissolution. Constructive diagenesis can generate secondary pores, mainly including dissolution and kaolinite metasomatism, which can effectively improve reservoir physical properties. Through the diagenesis alterations linked to different lithofacies in cored wells, there are obvious diagenesis variations in different lithofacies. Despite strong compaction, the reservoirs in coarse sandstone facies have developed internal dissolution. After compaction, cementation, and dissolution to increase porosity, the reservoir retains intergranular and secondary pores and forms relatively high-quality reservoirs. The fine sandstone facies with cross-bedding are strongly compacted, with internal ductile particles being compacted and deformed, and the particle orientation is clearly arranged. The reservoir is tight, and the development of dissolution in the reservoir is weak, resulting in poor reservoir quality. In addition, reservoirs located at the interface between sandstone and mudstone are often affected by diagenesis, resulting in the development of calcareous cementation, leading to poor reservoir quality. Therefore, high-quality reservoirs are mostly distributed in coarse sand lithofacies, mainly distributed in the mid-channel bar of distributary channel deposits. Sedimentary facies control the original physical properties of the reservoir with different content and texture; the quality of the original reservoir is subject to diagenetic alteration in different ways. The points in this study could offer insights better to predict deep tight reservoir quality in continental basins.

Characteristics and control factors of feldspar dissolution in gravity flow sandstone of Chang 7 Member, Triassic Yanchang Formation, Ordos Basin, NW China

To clarify the formation and distribution of feldspar dissolution pores and predict the distribution of high-quality reservoir in gravity flow sandstone of the 7th 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.