Tight Sandstone Oil Research Articles

The Saturation Calculation of NMR Logging Based on Constructing Water Spectrum Function

Tight sandstone oil reservoirs are characterized by complex structures, poor pore connectivity, and strong heterogeneity, with features such as low porosity and ultra-low permeability. Conventional methods for calculating saturation cannot accurately evaluate the hydrocarbon saturation of these reservoirs. To address this, a study was conducted from the perspective of non-electrical logging methods, focusing on the inherent nuclear magnetic resonance (NMR) characteristics of different fluids to develop a saturation calculation method that avoids the influence of the rock matrix, thus enabling precise saturation measurement in tight sandstone oil reservoirs. The traditional NMR porosity model was modified by segmenting it using the clay-bound water cutoff value, aiming to identify the distribution pattern of fluids in pores outside the clay-bound water zone. Through theoretical derivation and water spectrum function simulation, a water spectrum function and its parameter range suitable for the NMR T2 distribution in tight sandstone reservoirs were determined. Using core-sealed core saturation as a reference, the particle swarm optimization (PSO) algorithm was applied to optimize the parameter range and construct the final water spectrum function tailored to tight sandstone oil reservoirs. The accuracy and practicality of this method were validated by applying the derived water spectrum function to NMR logging in the exploration block, allowing for precise saturation calculations and the accurate evaluation of tight reservoir saturation.

Diagenesis Variation in Different Distributary Channels of Shallow Water Lacustrine Delta Deposits and Implication for High-Quality Reservoir Prediction: A Case Study in the Chang 8 Member in Caijiamiao Area, Sw Ordos Basin, China

Tight oil reservoirs are considered important exploration targets in lacustrine basins. High-quality reservoir prediction is difficult as the reservoirs have complex distributions of depositional facies and diagenesis processes. Previous research has found that the diagenesis process of tight oil sandstones varies greatly in different depositional facies. However, diagenesis variation in different depositional facies is still poorly studied, especially in distributary channels of shallow water delta deposits in lacustrine basins. Based on the description of core samples, the observation of rock slices, the interpretation of well logging data, and the analysis of porosity and permeability data, the differences in the lithofacies types, diagenesis processes, and pore structures of different distributary channels have been clarified. Ultimately, a model of diagenesis and reservoir heterogeneity distribution in the shallow-water delta of Chang 8 Member of the Yanchang Formation in the Caijiamiao area of the Ordos Basin has been established. This research indicates that the main distributary channels in the study area are dominated by massive bedding sandstone lithofacies, while the secondary distributary channels are primarily characterized by cross-bedding sandstone lithofacies. There are significant differences in the compaction, dissolution, and cementation of authigenic chlorite and carbonate among different parts of the distributary channels. Plastic mineral components, such as clay and mica, are abundant in sheet sands, and are more influenced by mechanical and chemical compaction. Influenced by the infiltration of meteoric water and hydrocarbon generation, dissolution pores are relatively well-developed in the underwater distributary channel reservoirs. A large amount of carbonate cementation, such as calcite and siderite, is found within the sandstone at the interface between sand and mud. The occurrence of authigenic chlorite exhibits a clear sedimentary microfacies zonation, but there is little difference in the kaolinite and siliceous cementation among different microfacies reservoirs. Finally, a model of diagenetic differences and reservoir quality distribution within dense sand bodies has been established. This model suggests that high-quality reservoirs are primarily developed in the middle of distributary channels, providing a theoretical basis for the further fine exploration and development of oil and gas in the study area.

Study of Pore–Throat Structure in Tight Triassic Sandstone: A Case Study on the Late Triassic Yanchang Formation, Southwestern Ordos Basin, China

In order to better understand pore–throat structure characteristics, the coupling relationship between micropore–throat structure and macro reservoir quality and influencing factors caused by authigenic minerals were studied. Petrographic analyses, scanning electron microscopy (SEM), pressure-controlled mercury injection (PMI), nuclear magnetic resonance (NMR), and X-ray diffraction (XRD) were performed on a suite of tight reservoir samples from the Chang 8 Member of the Upper Triassic Yanchang Formation in the southwestern Ordos Basin, China. The results show that the pore–throat sizes obtained with the combination of PMI and NMR methods varied from nano- to microscale, revealing pore–throat sizes ranging from 0.001 μm to 70 μm, and showing that pore–throats with a radius larger than 1.0 μm are rare. Larger pore–throats with good connectivity (>rapex) account for a smaller part of the total pore volume, ranging from approximately 7.58% to 38.90% with an average of 22.77%, but account for more than 80% of contributions to permeability. The effective movable fluid porosity (φemp) measured by NMR, ranging from approximately 0.10% to 7.07% with an average of 2.56%, had a positive contribution to permeability. The contents of chlorite occurrence state, other than illite, are beneficial to pore–throat preservation. A new reservoir evaluation scheme of the Chang 8 reservoir is established. These research results provide a theoretical basis for the evaluation and development of tight sandstone oil and gas exploration.

Accumulation mechanism of multi-type unconventional oil and gas reservoirs in Northern China: Taking Hari Sag of the Yin’e Basin as an example

Abstract Many multi-types of unconventional oil and gas reservoirs have been found in some faulted basins in northern China, showing good exploration potential. However, the hydrocarbon accumulation mechanism in these areas is still unclear, which limits the understanding of the distribution of oil and gas. In this study, we took Hari Sag in Yin’e Basin as an example, conducted a systematic analysis on various types unconventional oil and gas reservoirs, and revealed its characteristics and accumulation mechanisms. The study showed that there were many types of unconventional oil and gas reservoirs in Hari Sag, such as biogas reservoirs, shale gas reservoirs, shale oil reservoirs, tight sandstone oil reservoirs, tight sandstone gas reservoirs, and volcanic gas reservoirs. These reservoirs generally had characteristics of “near/within source rocks accumulation,” “coexistence of oil reservoirs and gas reservoirs,” “shallow oil and deep gas,” and so on. Research on the mechanism of hydrocarbon accumulation showed that: the lack of effective hydrocarbon migration pathway was the main reason for “near/within source rocks accumulation” of oil and gas reservoirs; the differences in the thermal evolution degree of the main source rocks at different structural positions in the sag made the distribution characteristics of hydrocarbon as “coexistence of oil reservoirs and gas reservoirs” and “shallow oil and deep gas”; and the joint development of multi-type effective unconventional reservoirs created the situation of “coexistence of multi-type unconventional oil and gas reservoirs.” It is predicted that six types of unconventional oil and gas reservoirs have a cumulative area of 381 km2, indicating that the Hari Sag has great potential for unconventional oil and gas exploration. The research results can not only guide the unconventional oil and gas exploration in Hari Sag but also provide a theoretical basis for exploration research in similar blocks.

Development and influencing factors of middle‐deep tight sandstone reservoir ‘sweet spots’ in fault basin—Taking the Eocene Shahejie Formation in Suning area of Raoyang Sag in Bohai Bay basin as an example

This study takes the tight sandstone of the lower sub‐member of the first member of the Eocene Shahejie Formation (Es1x) in the Suning area, Raoyang Sag, Bohai Bay Basin. Furthermore, it determines the rock type of the middle‐deep tight sandstone through lithologic profiling, core observation and log data analysis. The genetic control factors of tight sandstone in the study area are analysed using conventional thin section, pore‐casted thin section and scanning electron microscope, and the characteristics and genetic control factors of tight sandstone reservoirs are summarized. The research results show that the tight sandstones in this area are primarily feldspathic sandstone and feldspathic lithic sandstone, with high quartz contents, around 61.50%. The average porosity of the reservoir in the study area is 4.69%, and the average permeability is 2.92 mD, which are characteristics of low‐porosity and low‐permeability reservoirs. Through research, it has been found that the distribution of sedimentary facies and diagenesis in the study area control the development and distribution of ‘sweet spots’. Both compaction and cementation reduce the physical properties of the reservoir, while dissolution can increase porosity, thereby increasing the physical properties of the reservoir; dissolution resulted in an increase of approximately 3.57%–3.69% in the porosity of the tight reservoir in the study area, with an average porosity increase of 3.63%, and is the main controlling factor for the development of ‘sweet spots’ in the reservoir. The results provide an important basis for guiding the exploration and development of tight sandstone oil and gas in the lower sub‐member of the first member of the Eocene Shahejie Formation (Es1x)in the Suning area.

Analyzing the Microscopic Production Characteristics of CO2 Flooding after Water Flooding in Tight Oil Sandstone Reservoirs Utilizing NMR and Microscopic Visualization Apparatus

The microscopic pore structure of tight sandstone reservoirs significantly influences the characteristics of CO2 flooding after water flooding. This research was conducted using various techniques such as casting thin sections, high-pressure mercury injection, scanning electron microscopy, nuclear magnetic resonance (NMR) testing, and a self-designed high-temperature and high-pressure microscopic visualization displacement system. Three types of cores with different pore structures were selected for the flooding experiments and the microscopic visualization displacement experiments, including CO2 immiscible flooding, near-miscible flooding, and miscible flooding after conventional water flooding. The characteristics of CO2 flooding and the residual oil distribution after water flooding were quantitatively analyzed and evaluated. The results show the following: (1) During the water flooding process, the oil produced from type I and type III samples mainly comes from large and some medium pores. Oil utilization of all pores is significant for type II samples. The physical properties and pore types have a greater impact on water flooding. Type I and II samples are more suitable for near-miscible flooding after water flooding. Type III samples are more suitable for miscible flooding after water flooding. (2) In CO2 flooding, oil recovery increases gradually with increasing pressure for all three types of samples. Type II core samples have the highest recovery. Before miscibility, the oil recovered from type I and type II samples is primarily from large pores; however, oil recovery mainly comes from medium pores when reaching miscibility. As for the type III samples, the oil produced in the immiscible state mainly comes from large and medium pores, and the enhanced oil recovery mainly comes from medium and small pores after reaching the near-miscible phase. (3) It can be seen from the microscopic residual oil distribution that oil recovery will increase as the petrophysical properties of the rock model improve. The oil recovery rate of near-miscible flooding after water flooding using the type II model is up to 68.11%. The oil recovery of miscible flooding after water flooding with the type III model is the highest at 74.57%. With increasing pressure, the proportion of flake residual oil gradually decreases, while the proportion of droplet-like and film-like residual oil gradually increases. Type II samples have a relatively large percentage of reticulated residual oil in the near-miscible stage.

Charging dynamic, resistance and accumulation process of tight sandstone oil of the paleogene Es3 member in linnan sag, jiyang depression

The study of the coupling relationship between the dynamic and resistance of oil charging is the key to revealing the process of tight oil accumulation. The Paleogene Es3 member of Linnan sag, Jiyang Depression was taken as an example, basin simulation, fluid inclusion analysis, and porosity inversion were comprehensively utilized to recovery the residual fluid pressure and charging resistance during the critical oil accumulation periods. Combined with the physical modeling of tight oil charging, the charging process and characteristics of tight oil under dynamic and resistance coupling were reproduced and the effects of dynamic and resistance on the oiliness of tight reservoirs were analyzed. The comprehensive analysis indicates that there were early and late periods of oil accumulation in early Dongying period and late Guantao-Quaternary period. The reservoirs had not been densified during the early oil accumulation period. The residual pressure of the formation was between 1.0–4.4 MPa and the reservoir charging resistance was generally small, so that the dynamic was generally greater than the resistance. But the oil saturation of the reservoirs was low due to the small amount of hydrocarbon generation. During the late oil accumulation period, the source rocks entered the peak period of hydrocarbon generation and expulsion and the residual pressure of the formation was between 4.2–12.1 MPa. The reservoirs had been close to or completely densified. The dynamic, resistance and dynamic and resistance difference all increased significantly. Under the stronger dynamic, the oil saturation of reservoirs rapidly increased, ultimately achieving tight oil enrichment. The results of this study provide insights into the dynamic process of tight oil accumulation and the distribution of oil in tight reservoirs.

Prediction of Oil Production in a Tight Sandstone Reservoir: Triassic Chang 9 Member, Jiyuan Area, Ordos Basin, NW China

Tight sandstone oil reservoirs in the Upper Triassic Yanchang Formation of the Ordos Basin are the most promising exploration and development fields owing to their huge production potential. Even though they have received considerable attention in recent years, common productivity prediction methods were not well applied during pre-development owing to their strong internal heterogeneity. In this study, the factors influencing oil production of the Chang 9 Member in the Jiyuan area were investigated and summarized based on drill cores, such as sediment characteristic analysis, lithofacies analysis, other analytical tests, and conventional logging curves. The findings show that fine-sandstone reservoirs with smooth sand body architectures are the main types of tight sandstone commercial oil reservoirs. Furthermore, having high porosity and oil content are prerequisites for commercial oil reservoirs, and the cumulative thickness of effective reservoirs serves as a crucial resource base for them. Through the analysis of logging curves, the relative center of gravity, deviation root of variance, petrophysical index, effective reservoir thickness, and evaluation indicator were used to predict daily oil production, thereby establishing the identification criteria for the ranking of tight sandstone oil reservoirs using logging. Then, the productivity of each reservoir in a single well was predicted by processing the log data from each well using the proposed method, and the productivity prediction results agreed well with the tested results of the perforated interval. This approach highlights the integrated influence of geological factors, physical properties, and the thickness scale of an effective reservoir, thereby improving the predictive capacity of logging curves. Additionally, the proposed methods significantly reduce the need for reservoir parameters better than previous ones, streamline operations, and improve practical applications.

Diagenetic evolution of tight sandstone and the formation of an effective reservoir in the lower member 3 of the Shahejie Formation, Bohai Bay Basin, East China

Heterogeneity in the physical properties of tight sandstones is mainly caused by complex diagenetic interactions in various combinations during the burial process. The tight sandstone oil in the Linnan Sag of Bohai Bay Basin has great development potential but it is unclear how effective reservoirs were formed, and this is a significant reason why exploration in the deep reservoir is so difficult. Here we studied the diagenetic evolution of the tight sandstone of Lower Member 3 of the Shahejie Formation, Linnan Sag, Bohai Bay Basin, by using cores, thin sections, XRD, SEM, grain-size analysis, high-pressure mercury intrusion porosimetry, fluid inclusions, and carbon and oxygen stable isotopes. Compaction, replacement, cementation and dissolution diagenesis are identified; all four processes mainly occur in the A phase of mesodiagenesis. The interaction of formation burial, thermal evolution of organic matter and dehydration of gypsum leads to the alternating presence of three stages of alkaline fluids and two stages of acidic fluids. The average dissolution porosity of the dissolution sandstone facies is greater than the lower limit of the porosity for the effective reservoir in the study area, which is key to the formation of effective reservoirs. By determining differential diagenetic evolution sequences of tight sandstone reservoirs under the constraints of different lithologies where sandstone is interbedded with mudstone, we are able to elucidate the formation of the effective reservoir as follows: (1) In the eodiagenetic stage, a large amount of early carbonate cement developed in the sandstone adjacent to the mudstone, filling the primary pores and forming a cementation sandstone facies. Smaller amounts of early carbonate cement developed in the interior of the sandstone, which “fixed” the primary pores, and has a positive effect on the formation of a large number of secondary pores in the dissolution stage. (2) In the early stage of mesodiagenesis (A1), due to the filling of primary pores, it is difficult for acidic fluids to enter the cementation sandstone facies adjacent to mudstone, and the dissolution is weak. But dissolution within the sand body was strong, producing a large number of dissolution pores and forming a dissolution sandstone facies that clearly enhanced the physical properties. (3) In a second early stage of mesodiagenesis (A2), dissolution still played a dominant role in the dissolution sandstone facies, due to the development of dissolution pores in the previous stage (it is easy for acidic fluids to enter the dissolution sandstone facies). The physical properties of the dissolution sandstone facies were once again enhanced and an effective reservoir gradually began to form. (4) At the end of mesodiagenesis stages A1 and A2 (26.2–24.6 Ma; 7.5–2.8 Ma), the reservoir experienced two phases of petroleum charging. The charging of the cementation sandstone facies developed at the margins of the sandstones was difficult due to the filling of primary pores. The dissolution sandstone facies are oil-bearing, with higher porosity, which indicates an effective reservoir. By coupling the thermal evolution of organic matter and the dehydration of gypsum with differential diagenetic evolution and the porosity evolution of reservoir, we are able to establish a reservoir genetic model that involves alternating seepage of organic acids and alkaline brines.

Numerical simulation of the dynamic migration mechanism and prediction of saturation of tight sandstone oil

Numerical simulation of the dynamic migration mechanism and prediction of saturation of tight sandstone oil

Concise extraction and characterization of the pore-throat network in unconventional hydrocarbon reservoirs: A new perspective

In this study, a new image-based method for the extraction and characterization of pore-throat network for unconventional hydrocarbon storage and exploitation is proposed. “Pore-throat solidity”, which is analogous to particle solidity, and a new method for automatic identification of pores and throats in tight sandstone oil reservoirs are introduced. Additionally, the “pore-throat combination” and “pure pore” are defined and distinguished by drawing the cumulative probability curve of the pore-throat solidity and by selecting an appropriate cutoff point. When the discrete grid set is recognized as a pore-throat combination, Legendre ellipse fitting and minimum Feret diameter are used. When the pore and throat grid sets are identified as pure pores, the pore diameter can be directly calculated. Using the new method, the analytical results for the physical parameters and pore radius agree well with most prior studies. The results comparing the maximum ball and the new model could also prove the accuracy of the latter's in micro and nano scales. The new model provides a more practical theoretical basis and a new calculation method for the rapid and accurate evaluation of the complex processes of oil migration.

Formation damage induced by working fluids sequentially interacting with tight sandstone oil reservoirs

Drilling fluid loss is a frequent downhole incident in the process of deep well drilling and completion. Drilling fluid will damage the formation permeability and affect well production, but some wells with high volume drilling fluids loss can have high production. To investigate the mechanism of drilling fluid loss damage in tight sandstone oil reservoirs, this study selects some core plugs and the working fluids from X field in Ordos Basin, China, conducts the evaluation experiments of drilling fluid damage and working fluid sequential contact damage, and analyzes the well history and well production performance data. Results show that the permeability recovery rate decreases continuously, after different fluid displacement. The permeability recovery rate of rock sample after drilling fluid displacement is 46.21–67.14%, and the permeability recovery rate after different working fluid displacement is 22.92–61.45%. Then well history and production fluctuations are analyzed. It shows the incompatibility of working fluid will cause superimposed damage to hydraulic fractures. The main damage mechanism caused by drilling fluid loss is incompatibility damage and particle invasion. Loss of drilling fluid will improve damage risk of the subsequent stimulation operations, though it doesn't show damage features in initial stage. Formation damage degree is related to the storage space type of reservoir. The results serve as a guide for the drilling fluid design of oil in tight sandstone formation.

Effects of Pore Water Content on Stress Sensitivity of Tight Sandstone Oil Reservoirs: A Study of the Mahu Block (Xinjiang Province, China)

Traditional stress sensitivity experiments are typically conducted under dry conditions, without considering the reservoir’s water content. In reality, the presence of water within pores significantly influences the extent of stress sensitivity damage in tight sandstone oil formations, subsequently affecting the determination of stress sensitivity coefficients during experimentation. By investigating sandstone samples from wells in the Mahu Block of China’s Xinjiang province, we observed that increasing water saturation reduces the stress sensitivity of tight sandstone. By conducting stress sensitivity experiments under varying water content conditions, we found that the stress sensitivity coefficient is not a constant value but decreases as water saturation increases. Based on experimental comparisons, an optimized power-law model for stress-sensitive damage assessment was refined. By conducting stress-sensitive damage assessment experiments under different water content conditions and integrating the concept of comprehensive compression coefficient, an improved stress-sensitive power-law model was established allowing for the influence of water content. The accuracy of this improved model was increased by 46.98% compared to the original power-law model through experimental validation. The research outcomes can enhance the accuracy of permeability and productivity evaluation, providing valuable guidance for unconventional oil and gas development.

Pore-Throat Structure in the Chang 7 Subformation Influencing the Differential Accumulation of Tight Sandstone Oil: Insight from SEM, Rate-Controlled Mercury, and High-Pressure Mercury Results

Pore-Throat Structure in the Chang 7 Subformation Influencing the Differential Accumulation of Tight Sandstone Oil: Insight from SEM, Rate-Controlled Mercury, and High-Pressure Mercury Results

Study on Brittleness Characteristics and Fracturing Crack Propagation Law of Deep Thin-Layer Tight Sandstone in Longdong, Changqing

Tight-sandstone oil and gas resources are the key areas of unconventional oil and gas resources exploration and development. Because tight-sandstone reservoirs usually have the characteristics of a low porosity and ultralow permeability, large-scale hydraulic fracturing is often required to form artificial fractures with a high conductivity to achieve efficient development. The brittleness of rock is the key mechanical factor for whether fracturing can form a complex fracture network. Previous scholars have carried out a lot of research on the brittleness characteristics of conglomerate and shale reservoirs, but there are few studies on the brittleness characteristics of sandstone with different types and different coring angles in tight-sandstone reservoirs and the fracture propagation law of sandstone with different brittleness characteristics. Based on this, this paper carried out a systematic triaxial compression and hydraulic fracturing experiment on the tight sandstone of Shan 1 and He 8 in the Longdong area of the Changqing oilfield. Combined with CT scanning cracks, the brittleness characteristics and fracturing crack propagation law of different types and different coring angles of sandstone under formation-confining pressure were clarified. The results show that there are great differences between different types of sandstone in the yield stage and the failure stage. The sandstone with a quartz content of 100% has the highest peak strength and a strong brittleness. Sandstones with a high content of natural fractures and dolomite have a lower peak strength and a weaker brittleness. There are also differences in the peak strength and fracture morphology of sandstone with different coring angles due to geological heterogeneity. The sandstone with a comprehensive brittleness index of 70.30 produces a more complex fracture network during triaxial compression and hydraulic fracturing than the sandstone with a comprehensive brittleness index of 14.15. The research results have important guiding significance for on-site fracturing construction of tight-sandstone reservoirs.

Research on Fractal Characteristics and Influencing Factors of Pore-Throats in Tight Sandstone Reservoirs: A Case Study of Chang 6 of the Upper Triassic Yanchang Formation in Huaqing Area, Ordos Basin, China

In recent years, tight sandstone oil and gas have been an important area for unconventional oil and gas exploration and development in China. It is of great significance to clarify the pore-throat structure characteristics of tight sandstone reservoirs to guide production practices. This study takes the tight sandstone of the sixth member of the Yanchang Formation in the Huaqing area, Ordos Basin, as an example, based on experimental methods such as high-pressure mercury intrusion, cast thin sections and scanning electron microscopy. At the same time, the pore-throat structure of tight sandstone reservoirs is divided into three types using the tube-bundle and spherical fractal models. The corresponding pore and throat radius distribution, pore-throat combination mode and influencing factors of various pore-throats are studied. The results show that the fractal dimension of type I pore-throats is the smallest, and the distribution of their pore-throat radii is the most uniform. They are dominated by intercrystalline pores and dissolution pores with tube-bundle throats and small pores with small throats. Type II pore-throats have the largest fractal dimension and the worst pore-throat uniformity. They are dominated by residual primary intergranular pores with necked throats and large pores with small throats. The type III pore-throat fractal dimension is in the middle, mainly composed of residual dissolved intergranular pores with pore-reduced throats, sheet-like and curved sheet-like throats, and large pores with large throats. The influence of different pore-throat combinations on the reservoir is reflected in the different characteristics of mercury injection parameters. The main influencing factors for the differences in the fractal dimensions of different pore-throats are diagenesis, rock composition and pore-throat combination type. Diagenesis and rock composition, in turn, affect the type and development degree of pore-throats, as well as the combination of pore-throats. The purpose of this study was to clarify the internal connection modes of different homogeneous pore-throats and their influencing factors, enrich the theoretical basis for the study of tight sandstone reservoirs and provide theoretical guidance for their exploration and development.

Microscopic Production Characteristics of Huff-n-Puff after CO2 Flooding in Tight Oil Sandstone Reservoirs

Microscopic Production Characteristics of Huff-n-Puff after CO₂ Flooding in Tight Oil Sandstone Reservoirs

Influence of fractures in tight sandstone oil reservoir on hydrocarbon accumulation: A case study of Yanchang Formation in southeastern Ordos Basin

Abstract The southwestern Ordos Basin is located at the junction of several stable plates, where faults and fractures are relatively developed, and the influence of fractures on the distribution of tight oil reservoirs in the Yanchang Formation is not clear. To solve this problem, the characteristics of fracture development of the Yanchang Formation, southwestern Ordos Basin and its control on hydrocarbon accumulation have been systematically studied using the core, thin section, well logging, productivity, fault and sand body distribution data. The results show that vertical and horizontal bedding fractures are much more developed in the Chang 8 Member compared with the Chang 6 and 7 Members. For horizontal bedding fractures, they are mainly developed in fine sandstone, followed by siltstone, while no horizontal bedding fractures are observed in medium sandstone. This is because horizontal bedding fractures are more common in fine-grained sediments. For vertical fractures, they are also mainly developed in fine sandstone. The controlling factors of fractures include lithology, sand body thickness, sedimentary microfacies and fault–fracture coupling relationship. Fractures are well developed in the fine-grained sandstone of the wing parts of the main river channel due to small compacted space. In the area where multiple river channels intersect, the sand is pure and easy to break. Based on the comprehensive study of sedimentation, structure and fracture, the classification criteria of sweet point reservoir of the Yanchang Formation are determined: sedimentary microfacies of the main river channel and its wing, tectonic location within 1.5 km from the main fault, plane arrangement of right-lateral and right-order faults and developed fractures. The sweet point reservoir can be identified effectively using the developed sweet point screening criteria.

A new method for the characterization of microcracks based on seepage characteristics

Microcracks are the main seepage channels and reservoir space for oil and gas in dense sandstone reservoirs, and the degree of development dominates the reservoir’s high and stable production capacity. A new method has been devised to address the lack of quantitative identification and characterization methods for microcrack networks. The method is based on core stress sensitivity, permeability anisotropy, and two-phase seepage rule testing. By improving upon the traditional black oil model, this method can accurately calculate the impact that microcracks of varying degrees of development have on the capacity of tight oil reservoirs. The study shows that 1) the higher the degree of microcrack development, the stronger the reservoir stress sensitivity and the greater the permeability anisotropy. As the degree of microcrack development increases, the irreducible water saturation decreases, the residual oil saturation gradually increases, and the oil–water two-phase co-infiltration zone becomes more extensive and smaller. The degree of microcrack development in tight reservoirs can be characterized based on the seepage characteristic parameters; 2) a microcrack characterization method and classification criteria have been established. It is based on stress sensitivity coefficients, permeability anisotropy parameters, and phase seepage characteristics in cores with different microcrack development degrees. For the first time, the method enables a macroscopic-level description of microcrack seepage; 3) numerical calculations show that the degree of microcrack development significantly affects the reservoir’s oil production and water production. The higher the degree of microcrack development, the higher the reservoir’s initial oil production and cumulative oil production. However, when the degree of microcrack development is too high, the microcracks are connected, thus exhibiting the nature of large fractures. This strengthens the bypassing communication effect and causes the microscopic inhomogeneity to strengthen, the oil production decreases rapidly, and water production increases quickly at the later stage. This research result enriches the reservoir microcrack characterization and evaluation system, which has essential theoretical guidance and practical significance for the rational and effective development of tight oil and tight sandstone gas.

Determining the present-day in-situ stresses of tight-oil sandstones by conventional logs: An approach in the Triassic Yanchang Formation, southern Ordos Basin

The present-day in-situ stresses affect the drilling design, well pattern deployment, well completion modification, hydraulic fracturing and water injection of tight-oil sandstones. The measurement data of these stresses are commonly unavailable because of their high costs and limited core samples, therefore employing conventional logs for these stress determination is imperative for tight-oil sandstones. Firstly, the suitable calculation models for the present-day in-situ stress calculation by conventional logs were selected according to the geological characteristics of the sixth member of the Yanchang Formation (Chang 6) in Heshui area of the southern Ordos Basin, China. Then, the dynamic rock mechanical parameters were determined by conventional logs, and corrected by the static rock mechanical parameters obtained from the triaxial rock mechanical tests. Moreover, the pore fluid pressure was determined by the empirical formula method. Finally, the maximum and minimum horizontal compressive stresses (σH and σh), and the vertical stress (σv) of six wells were calculated according to the selected models of these stresses, respectively. The present-day in-situ stresses, determined by the proposed method in the paper, were verified by those obtained from acoustic emission tests and finite-element numerical simulations with the relative errors of less than 10%. The results show that the magnitudes of σH, σh and the horizontal differential stress (σH−h) in the study area mainly range from 32 to 43 MPa, 23 to 37 MPa and 5 to 8 MPa, respectively. The magnitude of the three-dimensional present-day in-situ stress increases with the increase of depth. The average gradients of σH, σv and σh are 0.018, 0.014 and 0.015 MPa/m, respectively, that is σH>σv>σh. In this stress state, the hydraulic fractures, with a trend of little expansion towards multiple directions, are commonly developed at a small angle intersecting with the direction of σH in the study area.