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Tight sandstone reservoirs have extremely low porosity and permeability. Bedding-parallel fractures (BPFs) contribute prominently to the storage and seepage capability. However, the distribution of BPFs is remarkably heterogeneous, impeding the prediction and modeling of sweet spots. BPFs are controlled fundamentally by laminations, which are widely distributed in lacustrine tight reservoirs and provide most weakness planes. Based on core and thin section data, BPFs of the upper Triassic Chang 7 tight oil reservoir are characterized microscopically. The lamination combination unit, which is defined by distinctive lamination assemblage and relatively stable lamination thickness and space, is utilized as a homogeneous unit to measure the density of lamination and related BPFs. The influence of laminations on BPFs is discussed further. Results show that most bedding-parallel fractures are unfilled, with apertures generally <40 μιτι, mainly <10 μιτι. Larger apertures correlate with low filling degrees. The distribution of BPFs is intricately controlled by lamination type, density, and thickness. (1) BPFs tend to develop along different types by a priority sequence which reflects their mechanical strength. The development degree of BPFs also depends on the mechanical contrast with adjacent laminations; (2) When controlled by a single type of lamination, the density of BPFs increases with lamination density under a turning point and then decreases; (3) BPFs prefer to develop along the thinner lamination and are usually inside it, while controlled by thick lamination, BPFs tend to extend along the edge. The change in the thickness of laminations leads to a change in the development position of BPFs, indicating that the position of the weak plane controls the development position of BPFs; (4) When multiple types of lamination coexist, the type and thickness of laminations jointly influence the development of BPFs. Plastic thin laminations are conducive to the development of BPFs, while brittle thick laminations are not conducive. When the thickness of the plastic lamination is close to or less than that of the brittle, the influence of lamination type dominates BPFs, while the thickness of the plastic laminations is much larger than the brittle, the influence of lamination thickness will dominate. [ABSTRACT FROM AUTHOR]

Tight sandstone reservoirs have extremely low porosity and permeability. Bedding-parallel fractures (BPFs) contribute prominently to the storage and seepage capability. However, the distribution of BPFs is remarkably heterogeneous, impeding the prediction and modeling of sweet spots. BPFs are controlled fundamentally by laminations, which are widely distributed in lacustrine tight reservoirs and provide most weakness planes. Based on core and thin section data, BPFs of the upper Triassic Chang 7 tight oil reservoir are characterized microscopically. The lamination combination unit, which is defined by distinctive lamination assemblage and relatively stable lamination thickness and space, is utilized as a homogeneous unit to measure the density of lamination and related BPFs. The influence of laminations on BPFs is discussed further. Results show that most bedding-parallel fractures are unfilled, with apertures generally

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.

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.

The research on the storage and seepage properties of continental tight oil sandstone reservoirs is of great significance for formulating reasonable reservoir development plans. In this paper, taking the Chang 8 Member of the Yanchang Formation in the Fuxian area of the southeastern Ordos Basin as an example, the key elements in the evaluation of tight oil reservoir sweet spots, such as petrology, sedimentary facies, microscopic pore structures, physical properties and seepage characteristics of tight oil reservoirs were systematically investigated. The results show that the lithology of Chang 8 Member in the study area is mainly feldspar sandstone, followed by lithic feldspar sandstone. The Chang 8 Member is a delta front subfacies deposit, and its pore types include intergranular pores, intragranular pores, interstitial pores and micro-fractures. The Chang 8 reservoir has an average porosity of 8.48% and an average permeability of 0.207 mD, which is a low-porosity and ultra-low permeability reservoir. With the increase of porosity, the permeability has an increasing trend, but the trend shows irregularity. This shows that the permeability is affected by the microscopic pore structures in addition to the porosity. The factors affecting the physical properties of Chang 8 reservoir in this area include sedimentation, burial compaction, cementation and dissolution. The underwater distributary channel sand bodies of the delta front are good oil and gas reservoirs. There is a negative correlation between the content of detrital mica and porosity. The carbonate cement content in the Chang 8 reservoir in the study area is 1%-30%, with an average of 6.5%. The carbonate content is negatively correlated with the reservoir physical properties, the higher the carbonate content, the worse the reservoir physical properties. The secondary pores formed by dissolution account for 10%-40% of the total surface porosity, with an average of about 24%. Due to the high irreducible water saturation in the oil-water relative permeability curve of the Chang 8 reservoir group, the water saturation at the isotonic point is about 46%, with an average of 46.81%. In addition, the irreducible water saturation of Chang 8 water flooding experiment was 27.19%, the final oil displacement efficiency was 47.55%, and the water flooding recovery rate was high. This study can provide basic data for the formulation of efficient tight oil development plans. [ABSTRACT FROM AUTHOR]

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.

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.

The fracturing and well pattern optimization of fractured reservoirs is a hot spot in petroleum engineering. In this study, taking the tight oil reservoirs of the Yanchang Formation in the Ordos Basin as an example, an optimized plan of hydraulic fracturing and well pattern deployment of the fractured tight reservoir were systematically studied using a fluid-solid coupling model. The results show that the Chang 6 Member of Yanchang Formation mainly develop feldspar sandstone. A large number of vertical fractures are developed in Chang 6 Member, and they have significant shearing properties. The target sandstone reservoir is in the mid-diagenetic A stage. Natural fractures have a significant effect on the extension of hydraulic fractures. When the fracturing direction is parallel to the main strike of natural fractures, the extension distance of the hydraulic fractures is long and the fracturing scale is large; however, when the fracturing direction is orthogonal or oblique to the main strike of natural fractures, the extension distance of the hydraulic fractures is limited. Statistics show that the average length of hydraulic fractures when fracturing parallel to natural fractures is 1.3 times of that when fracturing perpendicular to natural fractures. In addition, after optimization of fracturing parameters, we found that the displacement should be controlled at 2–3 cubic meters/min, and the sand ratio should be controlled at 25%. The smaller the horizontal minimum principal stress difference between the fracturing layer and the shielding layer, the lower the elastic modulus, and the easier it is to control the fracture height. Microseismic monitoring results show that the half-fracture length and fracture height are mainly distributed in 80–140 m and 15–25 m, respectively. The optimized fracture half-length was 120 m and the half-fracture height was 20 m. Finally, the well pattern of the target layer is optimized considering natural fractures. Through this study, we found that the reverse five-spot well pattern is suitable for the efficient development of tight oil reservoirs of the Chang 6 Member in this area.

An investigation of the Triassic Yanchang Formation, Ordos Basin, N. China, revealed that the diagenesis and quality of tight oil sandstone reservoirs (with an average porosity of 9.83% and an average permeability of 0.96 mD) were controlled by a closed diagenetic system. The carbonate cements observed in the sandstone were derived from decarboxylation of organic matter that occurred in the adjacent mudstones. These reactions supplied CO32−, which reacted with cations derived from grain dissolution in the sandstones. The average size of the diagenetic geochemical system with respect to carbonate cements was small (<6 × 10−2 m3), comprising sandstone and its adjacent mudstone(s). The carbonate cements tend to concentrate in the marginal sandstone, which is taken to indicate that the flux of CO32− into the sandstones limited the quantity of carbonate precipitated. In addition, the mass is near balance between the amount of feldspar dissolution and its by‐products in the central sandstone (distance to the sandstone/mudstone interface is mainly more than 1 m), where the permeability of sandstone will present a decreasing trend with the increase of feldspar dissolution pores. The pore space of central sandstone will be just redistributed, with primary intergranular pores converting to feldspar dissolution pores and clay mineral micropores. Thus, the best part of the sandstone reservoirs tends to be the central part of sandstone. In particular, sandstones that are more than 2 m thick could be the potential hydrocarbon reservoirs because they retain the best porosity (average of 13.6%) and permeability (average of 1.8 mD). The results of our study provide an important guide for the exploration of tight oil sandstones in other petroliferous basins over the world. [ABSTRACT FROM AUTHOR]

Pore throat structure is a significant factor controlling the properties of reservoir. Evaluation of the pore throat structure is also important for the exploration and development of tight oil. In order to determine the micro-structure of pore throat, the high pressure mercury intrusion experiments (HPMI) were performed on the tight oil sandstone samples of Chang 7 member in Xin’anbian Block, Ordos Basin, China. HPMI were conducted to obtain the microscopic parameters of the pore throat structure, such as pore-size distribution, pore connectivity, and pore space topology. The pore throat network of the tight oil sandstone mainly consists of micropores, transitional pores, and mesopores. The mesopores of the Chang 7 tight reservoirs is the dominant factor affecting the pore throat structure. Mesopores development positively influences the maximum pore radius, median radius, sorting coefficient, skewness, maximum mercury saturation, and efficiency of mercury withdrawal, indicating that with the development of mesopores, the properties of percolation, storage, pore throat connectivity, and oil recovery would become better. Fractal theory was used to quantitatively characterize the complex and irregular pore throat structure of the reservoir. The fractal dimensions of mesopores, transitional pores and micropores (D 1 , D 2 , and D 3 ) were calculated through the slopes of the trendlines of each segment obtained from the curve of log (1-S H ) versus log (Pc). The total fractal dimension (D) was obtained, based on the weighted average of porosity of mesopores, transitional pores, and micropores. D ranging of 2.2520–2.7875 indicates that the pore throat structure of Chang 7 tight reservoir is complex and has a strong heterogeneity. D 1 , D 2 , and D 3 have obvious negative correlations with porosity of the corresponding pores and only D 1 has an obviously negative correlation with permeability. D has a downward trend, with the increasing porosity, but no correlation with permeability. D 1 has better correlations with the parameters of pore throat structure than D 2 and D 3 . The heterogeneity and surface roughness of mesopores mainly influence the property of pore throat structure, especially percolation and storage space of the reservoir. The development of mesopores is a main factor affecting the pore throat structure of the Chang 7 tight oil sandstone. The fractal characteristic of mesopores reflects how well the pore throat structure for the exploration and development of Chang 7 tight oil. [ABSTRACT FROM AUTHOR]

In order to evaluate the displacement effect of four kinds of injection media in tight oil sandstone, water, active water, CO2, N2 flooding experiments were carried out in laboratory. Online Nuclear Magnetic Resonance (NMR) spectrometers combine the advantages of NMR technology and core displacement experiments. In the displacement experiment, NMR data of different injection volumes were obtained and magnetic resonance imaging (MRI) was carried out. The results showed that micro and sub-micropores provided 62–97% of the produced crude oil. The enhanced oil recovery ratio of active water flooding was higher than that of conventional water flooding up to 10%. The recovery ratio of gas flooding in micro and sub-micropores was 60–70% higher than that of water flooding. The recovery ratio of CO2 flooding was 10% higher than that of N2 flooding. The remaining oil was mainly distributed in pores larger than 0.1 μm. Under the same permeability level, the remaining oil saturation of cores after gas flooding was 10–25% lower than water flooding. From MRI images, the displacement effects from good to bad were as follows: CO2 flooding, N2 flooding, active water flooding, and conventional water flooding.

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 (S apex) is discussed. Multiple linear regression and support vector machine (SVM) methods were used for S apex predictions. The results show that the S apex values increase as the porosity/permeability increase and then show a decrease. For the flow zone indicator (FZI), S apex first decreases as the FZI increases and then a slight increase. High S apex values can be present in nearly all lithofacies, except within some small-scale bedding structures. Increased oil saturations may increase the S apex, but some rocks with no oil shows still have high S apex values. High S apex 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 S apex using multiple linear regression and SVM methods indicate that SVM regression is a good method because of the two high S apex rock types. The production data from wells with different S apex values show that the S apex has a large effect on fluid flow properties. • Abundant capillary pressure curves were used to obtain the well-connected pore-throat volumes (S apex). • S apex does not show good linear relationship with porosity, permeability and FZI. • High S apex exist in most all the lithofacies except for small-scale bedding structures. • Rocks with either good or bad oil show may have high S apex values. • S apex can be well estimated from the conventional well logs using SVM regression. [ABSTRACT FROM AUTHOR]

Vertical fracture patterns are mapped in the outcrops to analyze the impact of mechanical stratigraphy on vertical fractures in the relatively undeformed Upper Triassic tight oil sandstones of the Yanchang Formation along Yanhe River in the east Ordos Basin, China. The relationship between natural fractures and different bounding interfaces are analyzed based on rock relative strength measurement by N-type Schmidt Hammer, fracture and facies description in the outcrops. According to the probability of the bounding interface terminating natural fractures being more than 20%, seven types of mechanical interfaces terminating fracture longitudinal propagation are identified, namely 1) the interface of laminae-set or laminae co-sets, 2) bedding surface interface, 3) accretionary interface, 4) mudstone interbed, 5) mudstone barrier, 6) calcareous barrier and 7) depositional scour interface. According to fracture sizes and the mechanical interfaces which constrain fracture propagation, the vertical fractures are divided into micro-scale, small-scale, meso-scale and macro-scale ones. Three possible vertical fracture patterns in various sedimentary microfacies of the shallow water delta deposits are discussed based on field outcrop observation, the restriction capacities of different mechanical interfaces and the temporally changing tectonic stress. Finally, the application of vertical fracture patterns for subsurface fracture prediction is carried out in the Ansai Oilfield in the eastern Ordos Basin, China. The predicted fractures in wells are consistent with the fractures obtained from cores and conventional logs. This study links sedimentary stratigraphy, mechanical stratigraphy and natural fractures in the tight oil sandstones within a relatively undeformed setting, meanwhile unravels the vertical fracture patterns in different sedimentary microfacies of the shallow water delta deposits in the study area. The results will thus guide subsurface fracture prediction between wells in the tight oil sandstones of the eastern Ordos Basin. • Fracture hierarchy are divided based on mechanical stratigraphy and fracture size. • Vertical fracture patterns in different microfacies of the shallow water delta deposits are discussed in the study area. • Natural fractures are linked with sedimentary stratigraphy and mechanical stratigraphy. [ABSTRACT FROM AUTHOR]

Tight oil sandstones have large oil reserves but low waterflooding efficiency and oil recovery. The movable oil saturation (MOS) is a critical parameter for evaluating oil recovery in water-driven tight oil sandstone reservoirs. However, its controlling factors in tight oil sandstones are still not well understood. In this study, the tight/low-permeability sandstones in the Chang 8 and Chang 9 Members of the Honghe Oil Field in the Ordos Basin (China) provide an opportunity to determine the effects of pore structure on the MOS. Porosity, permeability, thin sections, scanning electron microscopy (SEM), large field-of-view SEM imaging method (MAPS technique), high-pressure mercury intrusion (MICP), and micro-CT scanning were systemically conducted to analyze the pore structure analysis. MOS values were obtained from the relative permeability tests. The results show that porosity, pore-throat size, and the sorting coefficient have no evident relationship with the MOS. Many of the higher-permeability samples even show lower MOS values. Moreover, analysis of micro-CT images before and after waterflooding indicates that the lower-permeability samples tend to swept larger areas than the higher-permeability samples, resulting in greater oil-displacement efficiencies and MOS values. Instead, the cumulative mercury saturation at the apex of the mercury injection hyperbola curve (S apex), the ratio of the maximum pore-throat radius and the medium pore-throat radius (R max /R 50), and movable fluid saturation (MFS) show a good linear relationship with the MOS. The displaced oil is primarily from intergranular pores and partly from intragranular pores. The micropores that are widely distributed at the grain-grain contact display low original oil saturation and low oil displacement efficiency. It is proposed that the volume of the well-connected pores that contribute to permeability is the key factor controlling the MOS regardless of the type of rock. • Rock typing was conducted based on pore types and pore-throat distribution. • Abundant relative permeability experiments were used to estimate MOS. • The volume and sorting of the pore-throats that contribute permeability control MOS. • Water-wet sandstones show higher MOS than the oil-wet sandstones with the same MFS. • CT scan was done before and after the waterflooding process. [ABSTRACT FROM AUTHOR]

Calcite cement is a typical product of fluid–rock interaction in petroleum reservoirs, and its migration has a major impact on reservoir heterogeneity. A case study of a closed diagenetic system was carried out on the Upper Triassic Yanchang Formation of Ordos Basin, China—the most successful exploration region for tight sandstone oil in China. The investigated sandstones are mainly lithic arkoses (Q 31 F 42 L 27). Three occurrences of calcite cement are the most important diagenetic minerals affecting reservoir quality: early calcite completely filling intergranular volumes; late calcite filling pores after chlorite coating, distributed in oil layers, or locally replacing feldspar; and crystal-stock calcite typically distributed in dry layers. δ13C values of the sandstones are in the range −9.69‰ to −2.05‰, indicating that calcite is derived mainly from thermodynamic decarboxylation of organic matter. Dark mudstone interbedded with sandstone and hydrocarbon emplacement are the two crucial sources of organic fluid, providing sufficient Ca2+, Mn2+, Fe2+, and Mg2+ for calcite precipitation through interaction with feldspar and other silicates, such as dissolution and replacement together with transformation of smectite to illite. Manganese was continuously enriched in calcite during burial diagenesis. Driven by compaction of interbedded mudstone and fluid overpressure, calcite migrated widely into calcite-cemented zones (CCZs) where fluid–rock interaction was strong, such as in the margins of sandstone bodies, intrastratal sandstones with original high-permeability zones, and thin sandstones, thereby forming an important organic CO 2 sink. Potential high-quality reservoirs are distributed mainly in the central part of the closed system, restricted by calcite-cemented zones, and are an exploration target. Our data suggest that frequently alternating sandstone and mudstone sequences comprise a complete organic CO 2 source/sink system, controlling the migration of calcite cement in a closed diagenetic system and reservoir heterogeneity by fluid–rock interaction. • Three occurrences of calcite cement were identified in the Chang 8 sandstone reservoirs. • Two organic fluids sourced from interbedded dark mudstone and hydrocarbon emplacement. • Fluid-rock interaction provided adequate Ca, and Mn was continuously enriched into calcite. • Calcite migrated into the marginal sandstone bodies, intrastratal dry layer and thin sandstones. • Alternating sandstone and mudstone sequences controlled the migration of calcite cement. [ABSTRACT FROM AUTHOR]

Understanding the reservoir quality and heterogeneity of tight oil sandstone reservoirs is essential for their exploration and production. An integration of lithological, diagenetic and hydrocarbon emplacement factors was analyzed to understand the reservoir quality difference in Chang 8 and Chang 9 sandstones of Yanchang Formation, Honghe Oil Field, Ordos Basin, using core, well logs, casting thin sections, SEM, cathode luminescence images and x-ray diffraction data. The results show that Chang 8 and Chang 9 sandstones are mainly fine to medium-grained feldspathic litharenites and lithic arkose with moderately well to well sorting, from braided-delta front subaqueous distributary channel facies. The average porosity and permeability of Chang 8 and Chang 9 sandstones are 8.52%, 0.27mD and 12.96%, 2.86mD, respectively. The main diagenesis types are mechanical compaction, authigenic chlorite, calcite cement, and dissolution. The Chang 8 and Chang 9 sandstone reservoir quality difference is mainly a result of the oil charging and diagenetic environment change. The Chang 8 sandstones that close to the source rock have a high content of feldspar and lithic dissolution and grain collapse from the acidic fluids injection, which dramatically decrease porosity and permeability. Whereas, the Chang 9 sandstones far from the NW-SE direction faults have a small amount of oil charging and acidic fluid injection, which result in high content of chlorite that narrow the throats and reduce permeability, but slightly reduce porosity. Only the sandstones at the bottom of Chang 8 or close to the NW-SE direction faults in Chang 9 Member have a small amount of acidic dissolution, medium content of chlorite, which lead to the relatively high porosity and permeability. High calcite cement contents are mainly observed at the top or bottom of the sandbody, which is not the main factor that leads to the Chang 8 and Chang 9 sandstone reservoir quality difference. • Higher average porosity and permeability in the Ch9 than the Ch8 sandstones. • High chlorite content reduce permeability and inhibit the oil charging. • Dissolution heterogeneity lead to the Ch8 and Ch9 reservoir quality difference. [ABSTRACT FROM AUTHOR]

In order to evaluate the displacement effect of four kinds of injection media in tight oil sandstone, water, active water, CO2, N2 flooding experiments were carried out in laboratory. Online Nuclear Magnetic Resonance (NMR) spectrometers combine the advantages of NMR technology and core displacement experiments. In the displacement experiment, NMR data of different injection volumes were obtained and magnetic resonance imaging (MRI) was carried out. The results showed that micro and sub-micropores provided 62–97% of the produced crude oil. The enhanced oil recovery ratio of active water flooding was higher than that of conventional water flooding up to 10%. The recovery ratio of gas flooding in micro and sub-micropores was 60–70% higher than that of water flooding. The recovery ratio of CO2 flooding was 10% higher than that of N2 flooding. The remaining oil was mainly distributed in pores larger than 0.1 μm. Under the same permeability level, the remaining oil saturation of cores after gas flooding was 10–25% lower than water flooding. From MRI images, the displacement effects from good to bad were as follows: CO2 flooding, N2 flooding, active water flooding, and conventional water flooding. [ABSTRACT FROM AUTHOR]