Tight Sandstone Oil Reservoirs Research Articles

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.

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.

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.

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

Geological characteristics and models of fault-fold-fracture body in deep tight sandstone of the second member of Upper Triassic Xujiahe Formation in Xinchang structural belt of Sichuan Basin, SW China

In the second member of the Upper Triassic Xujiahe Formation (T3x2) in the Xinchang area, western Sichuan Basin, only a low percent of reserves has been recovered, and the geological model of gas reservoir sweet spot remains unclear. Based on a large number of core, field outcrop, test and logging-seismic data, the T3x2 gas reservoir in the Xinchang area is examined. The concept of fault-fold-fracture body (FFFB) is proposed, and its types are recognized. The main factors controlling fracture development are identified, and the geological models of FFFB are established. FFFB refers to faults, folds and associated fractures reservoirs. According to the characteristics and genesis, FFFBs can be divided into three types: fault-fracture body, fold-fracture body, and fault-fold body. In the hanging wall of the fault, the closer to the fault, the more developed the effective fractures; the greater the fold amplitude and the closer to the fold hinge plane, the more developed the effective fractures. Two types of geological models of FFFB are established: fault-fold fracture, and matrix storage and permeability. The former can be divided into two subtypes: network fracture, and single structural fracture, and the later can be divided into three subtypes: bedding fracture, low permeability pore, and extremely low permeability pore. The process for evaluating favorable FFFB zones was formed to define favorable development targets and support the well deployment for purpose of high production. The study results provide a reference for the exploration and development of deep tight sandstone oil and gas reservoirs in China.

Experimental Mechanism for Enhancing Oil Recovery by Spontaneous Imbibition with Surfactants in a Tight Sandstone Oil Reservoir

This study aims to investigate the mechanism behind surfactant enhanced oil recovery under reservoir conditions through experiments on spontaneous imbibition with surfactants. The tight sandstone samples are characterized using cast thin section (CTS), high-pressure mercury intrusion (HPMI), and nuclear magnetic resonance (NMR) to determine their clay mineral composition, pore size distribution, and fluid distribution. Spontaneous imbibition experiments are then conducted using formation water and surfactant solutions as imbibition liquids, with three different types of surfactants─dodecylbenzene sulfonate (DBS), sodium dodecyl sulfate (SDS), and ammonium bromide─at two different concentrations, each to examine the effect of surfactant type. Additionally, the interfacial tension (IFT) between crude oil and different imbibition solutions is measured, and the contact angles of an oil droplet on the core surface in air, formation water, distilled water, and surfactant solution are determined. Finally, the effects of IFT, rock wettability, formation water salinity, and core permeability on final oil recovery by spontaneous imbibition are analyzed. The results indicate that surfactant-assisted spontaneous imbibition primarily operates through IFT reduction, wettability alteration, and emulsification of crude oil. However, ultralow IFT may lead to low ultimate oil recovery. To increase the ultimate oil recovery of spontaneous imbibition, reducing the salinity of the surfactant solution and creating microfractures can be effective strategies.

“Double sweet spot” identification method via cluster analysis of petrophysical properties from well logg data: A case study of a tight sandstone reservoir

In recent years, interest in unconventional resource plays has grown substantially due to horizontal drilling and hydraulic fracturing techniques. However, the high cost of drilling, choosing the right locations for perforation intervals during hydraulic fracturing is a crucial issue. Therefore, identifying so called “sweet spot” with high potential for hydrocarbon production plays an important role in oil and gas industry. In this study a new “double sweet spot” identification method using cluster analysis of well-logged petrophysical properties of facies is presented. Firstly, an engineering sweet spot identification method based on geophysical responses parameters (brittleness index and permeability) is introduced to classify the target zone. Triaxial compression tests are performed to obtain the static Young's modulus and Poisson's ratio of the rock samples. To calculate dynamic Young's modulus and Poisson's ratio, a novel model for determining interval transit time of S-wave is proposed based on the multiple linear regression theory according to well logging data. By performing the cluster analysis, an intersection diagram of permeability and calculated normalized Rickman's brittleness is built and then engineering sweet spots in target zone are characterized based on well-logged petrophysical properties of facies. By plotting the intersection diagram of porosity and oil saturation based on the cluster analysis theory, geological sweet spots in target zone were characterized and four types of rock petrophysical facies are divided: Sandstone A (So＞48%, 8＜φ＜19%); Sandstone B (31＜So＜48%, 6＜φ＜18%); Sandstone C (18＜So＜31%, 8＜φ＜20%) and Sandstone D (0＜So＜18%, 8＜φ＜17%). Secondly, target formation classification is carried out using a proposed geological sweet spot identification method based on reservoir physical parameters (oil saturation and porosity). The relationship between core electrical resistivity and water saturation is determined by traditional Archie's formula and then an oil saturation prediction model in target reservoir is established. Based on the experimental porosity and permeability measurements of 47 core samples and well logging data, a porosity interpretation model is proposed. By plotting the intersection diagram of porosity and oil saturation based on the cluster analysis theory, geological sweet spots in target formation are characterized and four types of rock petrophysical facies are given: Sandstone A (K＞0.1mD, BI＞38); Sandstone B (K＞0.1mD, 33＜BI＜38); Sandstone C (K＞0.1mD, BI＜33) and Sandstone D (0.01＜K＜0.1mD, 10＜BI＜60). The integrated “double sweet spot” identification results of Well 1 in Daqing tight sandstone oil reservoir are given. Rock AA is the most favorable type of petrophysical rock facies and rock DD is the worst favorable type of petrophysical rock facies. Finally, an integrated “double sweet spot” identification method proposed in this study was applied to screen proper interval candidates during refracturing operation in a tight sandstone oil reservoir in China. After refracturing operation a gradually increase of average oil production in well group was found from 1.10 t/d to 5.63 t/d. This novel “double sweet spot” identification method has applicability in other tight oil reservoirs around the world.

Insights into the Effect of Micropore Structure and Mineralogy on Adsorbed Tight Oil in the Huaqing Area, Ordos Basin, China

There is great potential for tight oil as an alternative to conventional fossil fuels throughout the world. Adsorption, mineralogy, and pore structure of tight sandstone are very important factors for the efficient development of adsorbed tight oil from tight sandstone oil reservoirs. In this study, the occurrence morphology of tight oil adsorbed to varying pore structures was examined, as well as the relationship between adsorption content and occurrence morphology. X-ray energy dispersive spectra, environmental scanning electron microscope observations, and thin fluorescence sections were used to describe the occurrence morphology of adsorbed tight oil in tight sandstone reservoirs. It was found that adsorbed tight oil can be classified into five types: emulsion, cluster, throat, thin-film, and isolation, with average contents of 34.9%, 14.5%, 3.1%, 42.7%, and 4.7%, respectively. In addition, a Soxhlet extraction was developed with four pore structures to describe the geological effects of adsorbed tight oil in reservoirs. The adsorption content of tight oil ranges from 4.015 mg/g to 16.987 mg/g, with an average of 10.115 mg/g. The order of adsorption content for different occurrence morphologies is as follows: emulsion form > throat form > cluster form > isolation form > thin-film form. It is the size and connectivity of the porous throat that determines the desorption efficiency of tight oil. An important outcome of this study can be the introduction of rational development plans and the improvement of oil recovery efficiency for tight oil reservoirs.

Quantitative evaluation of reservoir quality of tight oil sandstones in chang 7 member of Ordos Basin

In order to establish a quantitative evaluation system for reservoir quality suitable for tight oil sandstones, in this study, taking the Chang 7 Member in the Maling area of the Ordos Basin as an example, the nuclear magnetic resonance, clay mineral analysis, high pressure mercury injection analysis and logging interpretation technology have been used to carry out a comprehensive evaluation of the pore structures, sand body structures and oil-bearing properties of tight oil sandstone reservoirs. The results show that the pseudo-capillary pressure curves transformed by the NMR T2 spectra are consistent with the capillary pressure curves measured by the core experiments. This method can be used for accurate characterization of the pore structures of the reservoir. The pore structure parameters calculated based on the pseudo-capillary pressure curves can accurately reflect the pore structures of the reservoirs such as micropores-thin throats and complex tortuosity. At the same time, the smoothness feature of conventional logging curves is used to evaluate the sand body structures and heterogeneity of the reservoir, and the apparent energy storage coefficient is introduced to quantitatively evaluate the oil-bearing properties of tight oil reservoirs. The evaluation results are in good agreement with the actual production situation. The larger the apparent energy storage coefficient, the higher the initial output of the oil wells. The evaluation results of the reservoir quality of the tight oil sandstones constructed in this paper are highly consistent with the production status, so the method has broad application prospects.

Optimization of volume fracturing technology for shallow bow horizontal well in a tight sandstone oil reservoir

The physical property of Chang 6 reservoir in Yanchang oilfield is poor, and the heterogeneity is strong. Multistage fracturing of horizontal wells is easy to form only one large horizontal fracture, but it is difficult to control the fracture height and length. The new mining method of “bow horizontal well + multistage horizontal joint” can effectively increase the multistage horizontal joint’s spatial position, which improves the drainage area and stimulation efficiency of oil wells. Due to the reservoir’s low permeability and strong heterogeneity, the single well mode of “bow horizontal well + multistage horizontal fracture” cannot effectively produce Chang 6 reservoir. To improve the production degree of the g 6 reservoir, the fracture model is established using equivalent conductivity and the multigrid method. The pressure response functions of horizontal wells and volume fracturing horizontal wells are established by using the source function, and the relationship between reservoir permeability and starting pressure gradient in the block is calculated. On this basis, the reservoir productivity equation of the block is established, which provides a basis for optimizing the fracturing design parameters of horizontal wells. It is proposed that the flow unit should be considered in the design of fracturing parameters of horizontal fractures, the number of fractures should comprehensively consider whether the fractures can make each flow unit be used, and have large controlled reserves, and the scale of fracturing should comprehensively consider the output and cost. The fracture network model is established by using equivalent conductivity and multi-gridthod, and the volume fracturing design parameters of horizontal wells are optimized, considering the seepage characteristics of the flow unit. The fracturing design parameters of the horizontal section are further defined, which provides a theoretical basis for the efficient development of shallow tight reservoirs.

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

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

Implication of interfacial tension reduction and wettability alteration by surfactant on enhanced oil recovery in tight oil reservoirs

Tight oil reservoir is usually characterized by poor physical properties with oil recovery less than 10%. The objective of the study is to investigate the effect of 4 different types of surfactants to change rock surface tension and interfacial tension as well as its impact on enhanced oil recovery (EOR) in tight oil reservoirs. Results shows that the fluoride FC-1 and GS surfactant has more potential for wettability alteration and interfacial tension reduction respectively. The interfacial tension decreased from 6.072 mN/m to 2.04 mN/m, 0.03 mN/m, 0.1 mN/m, and 0.04 mN/m under the action of FC-1, GS surfactant, FC-2, and FC-3, respectively. FC-1 made the wettability changed from original hydrophilic or oil-hydrophilic to hydrophobic and oil-phobic. While the effect of wettability modification by other three was not so obvious and the contact angle was no more than 45 degrees. So, the GS and FC-1 was selected for displacement tests to investigate the effect in augmenting injection and enhancing oil recovery. The average reduction rate of injection pressure by fluoride and Gemini surfactant was 32.4% and 14.2%, respectively. Under the action of fluoride and GS surfactant, the water-phase permeability increased by 36.8% and 29.9%, respectively. The improvement of recovery mainly occurred in primary water flooding, while the amount of oil displaced by surfactant solution and secondary water flooding was little or even no, with the recovery efficiency improved by 0–8.4%. The effect of fluoride was more obvious, revealing that changing rock wettability is more favorable than reducing the interfacial tension for oil recovery in tight sandstone oil reservoirs.

Comprehensive evaluation and reservoir classification in the Quan 3 Member of the Cretaceous Quantou Formation in the Fuxin Uplift, Songliao Basin

Continental tight oil sandstone reservoirs are developed in the Cretaceous Quentou Formation in the Songliao Basin, China. At present, there is still a lack of research on the reservoir microstructures, reservoir physical properties, and the division scheme of reservoir types in the Quan 3 Member of the Quanzhou Formation. Therefore, in this paper, taking the Quan 3 Member in the Fuxin Uplift Belt of the Songliao Basin as an example, the microscopic pore structure characteristics of tight oil sandstones have been systematically studied, and the classification standard of tight sandstones has been formulated. Furthermore, the sweet spots of the main production layers are predicted. The results show that the I sandstone group in the Quan 3 Member in the study area belongs to shallow water delta facies. Feldspar lithic fine sandstones are developed in the target layer, and calcareous sandstone is locally developed. Moreover, the mian pore types of the target layer include dissolved intergranular and intragranular pores, followed by primary intergranular pores, while micro-fractures are occasionally seen. According to the mercury intrusion test results, the pore-throat structures of the reservoir in the Quan 3 Member are divided into four types: 1) small-pore medium-throat type (point bar and delta distributary channel), 2) small-pore micro-throat type (point bar), 3) small-pore micro-throat type (natural levee), 4) micro-pore micro-throat type (river floodplain and inter-tributary bay). The lower limits of the physical properties of the effective reservoirs in the Quan 3 Member has been determined: the porosity is 10% and the permeability is 0.1 mD. Finally, combined with the study of the mercury intrusion curves, the physical properties and the sedimentary facies, the classification standard of the Quan 3 Member reservoirs was formulated. For the I sandstone group, the sweet spots of the Type I reservoirs are mainly developed in the Fuyu Oilfield in the southeast areas. The sandstones in this area suffered less compaction, and primary and secondary pores suffered from late dissolution are mainly developed.

Study on the development options of tight sandstone oil reservoirs and their influencing factors

The research area of tight sandstone oil reservoirs was selected, a numerical model of the oil reservoir was developed, and a study of the development options and influencing factors was carried out to analyze the influence of different development methods, physical and engineering parameters on the development dynamics. Study shows that the two main factors limiting the efficient development of tight sandstone reservoirs are reservoir properties and formation energy. Fractured horizontal well injection huff and puff development can effectively improve reservoir physical properties and timely replenish formation energy, which is suitable for the development of such oil reservoirs. In dense sandstone reservoirs, its impact on production capacity is also relatively small when the permeability ratio is small. Due to both gravity and reservoir physical properties, the permeability ratio increases, the cumulative oil production of positive rhythm reservoirs decreases and that of reverse rhythm reservoirs increases, and the location of high-quality reservoirs in the upper part of producing wells is conducive to increasing the final recovery rate. A lower oil to water viscosity ratio can significantly increase the swept volume and improve development effect. Hydrophilic reservoirs can reduce the injection pressure and increase the spread range, effectively improving the problem of inability to inject, and improving reservoir hydrophilicity through surface activators can increase reservoir recovery. The water injection rate determines the recovery rate of formation energy. Generally, the faster the rate, the higher the cumulative oil production. Therefore, the rate of water injection should be increased as much as possible, taking into account construction conditions and economic evaluation. Additionally, the effect of water injection on the development effect is different at different stages, so the appropriate timing of water injection is very important to the water injection huff and puff development effect, and the use of early water injection in this research area is not conducive. Soaking can promote pressure and fluid redistribution and improve water injection huff and puff development effect, but soaking for a long time can lead to reservoir contamination and reduce crude oil production, so the preferred time for a soaking is about 20 days.

Controlling factors and predictions of well-connected pore-throat volumes in tight oil sandstones

Oil production from tight oil sandstone reservoirs has achieved success with the aid of hydraulic fracturing and horizontal well drilling technologies. However, approximately 90% of the oil in these reservoirs remains in place, and reservoir evaluation methods are essential for effective enhanced oil recovery. Well-connected pore throats constitute the connections between fractures and micropores in tight oil reservoirs and lead to high oil recovery levels when using enhanced oil recovery (EOR) methods. In this study, geological factors, such as reservoir quality, lithofacies, and oil charging extent, have been investigated, and their relationships with the well-connected pore-throat volume (Sapex) is discussed. Multiple linear regression and support vector machine (SVM) methods were used for Sapex predictions. The results show that the Sapex values increase as the porosity/permeability increase and then show a decrease. For the flow zone indicator (FZI), Sapex first decreases as the FZI increases and then a slight increase. High Sapex values can be present in nearly all lithofacies, except within some small-scale bedding structures. Increased oil saturations may increase the Sapex, but some rocks with no oil shows still have high Sapex values. High Sapex values are mainly present in two cases: (1) Rocks located close to source rocks with high acidic dissolution levels resulting in secondary porosity and authigenic clay contents. (2) Rocks located far from source rocks that have no oil shows and high contents of chlorite cement, which mainly indicate alkaline diagenetic environments. Predictions of Sapex using multiple linear regression and SVM methods indicate that SVM regression is a good method because of the two high Sapex rock types. The production data from wells with different Sapex values show that the Sapex has a large effect on fluid flow properties.

Micro-Scale Pore-Throat Heterogeneity of Tight Oil Sandstone Reservoirs and Its Influence on Fluid Occurrence State

Quantitatively characterizing the micro-scale heterogeneity of pore throats in tight sandstone reservoirs is the key to accurately describing the influence of pore structures on fluid occurrence characteristics. In this study, taking the Chang 6 Member of the Yanchang Formation in the Huaqing area of the Ordos Basin as an example, the pore-throat heterogeneity of tight sandstone reservoirs and its influence on the fluid occurrence state have been systematically studied using cast thin section, scanning electron microscope, X-ray diffraction, constant velocity mercury intrusion, and nuclear magnetic resonance tests. The main types of pores developed in the target layer were intergranular pores, followed by feldspar dissolution pores. The radius distribution of the intergranular pores is between 5.0 and 210 μm, with an average value of 50.27 μm. In addition, the pore combination types with the best petrophysical properties are the intergranular pore type, the intergranular-dissolution pore type, and the dissolution-intergranular pore type; the average permeability and porosity are 0.62 mD, 0.40 mD, 0.44 mD, and 12.0, 12.3, 12.3%, respectively. The target sandstones contain four typical T2 relaxation time types. The large-pore-fine-throat combination reservoir has the best petrophysical properties. The larger the pore-throat uniformity value, the more uniform the pore-throat radius, and the greater the reservoir permeability. Therefore, the uniformity of throat development controls the seepage capacity of the tight reservoirs. The movable fluid saturation of different pore types has obvious differences. The movable fluid saturations at the 0.1 and 0.5 μm pore diameters of the macro-pore-fine-throat and macro-pore-micro-throat reservoirs both show an obvious inflection point, and the movable water saturation is higher with a larger throat radius.

Coupling relationship between current in-situ stress and natural fractures of continental tight sandstone oil reservoirs

We have integrated rock mechanics and acoustic experiments, full-wave array acoustic testing, formation microscanner image logging, and hydraulic-fracturing data to evaluate the coupling relationship between current in-situ stress and natural fractures. We used the data of the Yanchang Formation in the DL block of the western Ordos Basin, China, as an example. Our results find that the Yanchang Formation mainly develops high-angle fractures and vertical fractures. Furthermore, the in-situ stress state of the target sandstone strata satisfies [Formula: see text]. Nearly vertical and high-angle fractures are formed in the environment when [Formula: see text] is the maximum principal stress. Therefore, the current in-situ stress state of the target layer matches the induced fractures (longitudinal tensile-induced fractures) and natural fractures. As the buried depth increases, the difference between the horizontal maximum and minimum stresses ([Formula: see text]) has a tendency to first decrease and then increase, and its conversion depth is approximately 2000 m. Natural fractures are not developed in the distributary bay (the lowest horizontal stress area) and the thick sand area in the middle of the main river channel (the largest horizontal stress area). Natural fractures are mainly developed on the two wings of the main channel, and their horizontal stress is approximately 2–4 MPa lower than the central part of the main channel. We determined a correlation between fractures and sedimentary facies, and we have an important reference value for improving the drilling success rate of tight oil reservoirs. Furthermore, our study provides insights into the prediction of fractures and sweet spots for further exploration and hydraulic fracturing activities in the studied area and elsewhere in continental tight sandstone reservoirs.

Comprehensive Evaluation of Rock Mechanical Properties and in-situ Stress in Tight Sandstone Oil Reservoirs

Comprehensive research on reservoir rock mechanics and in-situ stress properties combined with petrophysical experiments, logging models and numerical simulation is an important means to achieve efficient development of tight sandstone oil reservoirs. In this study, a large number of rock mechanics and acoustic experiments, full-wave train array acoustic wave tests, hydraulic fracturing data and three-dimensional finite element simulations were used to study the rock mechanical properties and in-situ stress characteristics of continental tight oil reservoirs in the Yanchang Formation. The results show that under uniaxial conditions, the tight sandstone samples mainly suffer from tensional ruptures. With the increase of confining pressure, the tight sandstone samples undergo obvious shear ruptures. When the confining pressure is loaded to 35 MPa, a typical vertical shear fracture will be formed. The hydraulic fracturing calculation results show that the in-situ stress state of the target layer satisfies σv (vertical principal stress)>σH (maximum horizontal principal stress)>σh (minimum horizontal principal stress). Based on the results of rock mechanics and acoustic tests, we have constructed the dynamic and static mechanical parameter conversion models of tight oil reservoirs and the logging interpretation model of current in-situ stress. Furthermore, the finite element method is used to simulate the three-dimensional structural stress field of the target layer. The simulations show that the horizontal principal stress distribution in the work area is consistent with the applied environmental stress. The σH of the target layer is mainly distributed in 32–50 MPa, and the σh is mainly distributed in 20–34 MPa. Both σH and σh are relatively high in the southern uplift of the work area; among them, σH is usually greater than 44 MPa, and σh is usually greater than 24 MPa. The northern part of the study area developed several grooved areas with relatively low stress values. The regions with high stress values are often distributed in bands, which may be related to the compression caused by the deformation of the strata. For shear stress, left-handed and right-handed regions usually alternate with each other. However, the extent of the left-handed area in the southern uplift area is larger than that of the right-handed area, indicating that the tight oil reservoirs in the study area are mainly affected by left-handed activities.