Search

Reservoir quality is one of the important geological factors controlling the development of tight oil in the Honghe oilfield, Ordos Basin, northwestern China. Analyses of core, well logging, mud logging and geophysical data as well as thin sections (casting and fluorescence) were combined with testing methods (such as grain size analysis, constant-rate mercury injection, and scanning electron microscopy) to characterize the micropore–throat development in reservoirs of the eighth member of Yanchang Formation in the oilfield. From the perspective of sedimentation and diagenesis, the mechanisms causing reservoir quality difference were explored and a method for characterizing reservoir quality difference and distribution was proposed. The results show that complex and diverse pore–throat configurations and multi-scale throat development are the microscale manifestations of reservoir quality differences in the member. Three types of pore–throat combinations are recognized, including intergranular pore-wide lamellar throat, intergranular and intragranular pore-wide lamellar throat, and intergranular/clustered micropore-wide lamellar throat. Different diagenesis processes and intensities under the control of sedimentary conditions determine the differential development of the reservoirs. Diagenetic facies are the indicators of reservoir quality. Diagenetic facies with chlorite cementation-moderate dissolution indicates reservoirs with the most ideal physical properties for hydrocarbon accumulation, while that with moderate calcite and kaolinite cementations are usually observed in reservoirs with less ideal physical properties. Reservoirs with the worst physical properties often correlate with diagenetic facies with strong calcite cementation and compaction facies. A multi-level constrained method under the control of sedimentation and diagenetic facies is proposed for characterizing tight reservoir quality difference in the member. The spatial distribution of sedimentary elements is analyzed through sedimentary configurations, the diagenetic facies distribution is constrained by sedimentary elements and the reservoir quality distribution is predicted with constraint of diagenetic facies. It suggests that the high-quality reservoirs in the member occur vertically in the middle of thick channel sandstone, while poor reservoirs occur in the upper or lower parts of the channel sandstone due to intensive compaction and cementation. Laterally, the quality of reservoirs enhances along the channels with a change in shape to lens or strips along the middle and downstream sections.

The prediction of “sweet spot” of multi-lithology composite tight oil and gas reservoirs within mixed siliciclastic-carbonate sequences is a hot topic in oil and gas exploration. There are mixed lacustrine carbonate-siliciclastic rocks in the Da'anzhai Member of Ziliujing Formation in the Eastern Slope of western Sichuan Depression. The reservoir lithology is complex, and the main factors controlling the development of high-quality reservoirs are yet to be known. Based on a large number of drilling, core and thin section observation, well log and seismic data, this paper systematically studies the characteristics and factors controlling the development of the mixed siliciclastic-carbonate reservoir. The results show that the reservoir is composed primarily of coquina, sandstone, breccia and shale in lithology, and its development is mainly controlled by sedimentary microfacies, diagenesis, tectonism (fracturing) and paleogeomorphology during the sedimentary period. The effective fractures in reservoirs of the low-energy shell shoal facies are well developed with relatively good physical properties. With the change of sedimentary microfacies from low-energy shoal to high-energy shoal to arenaceous shoal, the hydrocarbon production capacity worsens step by step. Diagenesis, such as dissolution and fracturing, has a certain effect on reservoir physical properties. The palaeogeomorphic highs and slopes had well-developed fractures during the sedimentary period which are conducive to constructive dissolution, and thus they are favorable zones for reservoir development. The development of structural fractures further amplifies the influence of dissolution; thus the fracture zones are also favorable for the development of high-quality reservoirs. The favorable sedimentary facies zone and fracture development degree serve as the core factors for the formation of high-quality mixed reservoirs. The muddy limestone with certain dissolved pores and structural fractures deposited under the low-energy shell shoal setting is of relatively high-quality reservoir in the Da'anzhai Member.

Tight sandstone reservoirs are widely developed in the Mesozoic Yanchang Formation of the Ordos Basin, China. There is a lack of understanding on the sedimentary setting, source-reservoir relationship and oil accumulation conditions in this area. In this study, through the comprehensive analysis of the distribution of tight oil, we evaluated the properties and petrological features of reservoir, geochemical characteristics of source rocks, the source-reservoir relationship, as well as the trapping, preservation and accumulation conditions of tight oil in the Chang 7 Member, and predicted the sweet spots of tight oil in the study area. The results show that the Chang 7 Member is a typical low-porosity and ultra-low permeability reservoir with great tightness, small pore throat and high capillary pressure, and must have been of near-source accumulation. The source rocks are mainly developed in the Chang 73 submember, and the reservoirs mainly occur in the Chang 71 and Chang 72 submembers, forming a combination mode of “lower source rock and upper reservoir”. Sandbodies with good connectivity and fractures being well developed in local areas are the main hydrocarbon transport systems. The abnormal high pressure caused by hydrocarbon generation and pressurization is the main driving force of tight oil accumulation. The mode of hydrocarbon transportation is dominated by the vertical or lateral migration from underlying source rocks or adjacent source rocks to reservoirs within a short distance. Following the integrated evaluation of lithology, physical properties and oil saturation of reservoirs and geochemical characteristics of source rocks, we grouped the sweet spots of Chang 7 Member into three types: Type I, Type II and Type III. Among others, the Type I sweet spots are the best in terms of porosity, permeability and source rock thickness and hydrocarbon enrichment which should be the focus of oilfield development. This study lays an important foundation for the economic and efficient development of tight oil in the Chang 7 Member of Heshui area, and has important implications on tight sandstone reservoirs in other regions of Ordos Basin in China.

The change of in situ viscosity in micro-scale of tight oil reservoir has great influence on the seepage process. Due to the imperfection of in situ viscosity model and measuring method, the prediction of development effect and scientific guidance is affected. Here, an in situ viscosity model of seepage fluid in tight reservoirs is established, and the main influencing factors are studied. The in situ viscosity changes linearly with the bulk viscosity; When the average pore radius less than 500 nm, the in situ viscosity increased sharply. The approximate properties of boundary fluid and heavy oil are verified by experiments, and a method for measuring boundary fluid viscosity based on nuclear magnetic resonance (NMR) is found. According to the viscosity property of boundary fluid, the experiment is designed to verify the measurement method of boundary fluid viscosity by NMR.

Understanding the micro-occurrence mechanism of tight oil has long been a daunting challenge in the exploration and development of unconventional resources. This article discusses the micro-occurrence mechanism of tight oil through continuous extraction by combining thin casting, fluorescent thin sections, environmental scanning electron microscope observations, physical property testing, and X-ray diffraction experiments. The results indicated that in the tight sandstone of the Chang 8 Formation in the Ordos Basin, the average tight oil content was 35.46% for microscale pores, 35.74% for nanoscale pores, and 28.79% for mineral surfaces. Six types of micro-occurrence states of tight oil were identified: emulsion, cluster, throat, star-like, isolation, and thin film forms. Although clay minerals and heavy components dominate the adsorption of tight oil on mineral surfaces, micro-occurrence is fundamentally an oil–rock interaction process. Hence, oil–rock interactions and occurrence states were combined in this study to identify tight oil’s micro-occurrence mechanism. The van der Waals forces of attraction between asphaltene molecules and a mineral surface play a critical role, and minerals with hydroxyl groups can also combine with carboxyl and hydroxyl groups present in tight oil. As a consequence of the adsorption of heavy components by minerals, tight oil components remain in microscale and nanoscale pores with a higher saturation, increased aromatic hydrocarbon content, and greater fluidity. The heterogeneity of the components due to adsorption influences the physical properties and mineralization framework of tight oil reservoirs. These findings suggest that tight oil occurrence results from the coupling of microscopic occurrence and component heterogeneity in microscale and nanoscale pores.

It is difficult to determine the main controlling factors of tight oil production. In addition to the problem of uncontrollable prediction accuracy, the numerical prediction model established by the main controlling factors will also make the correctly predicted low production samples lose the value of development. Applying the optimization algorithm with fast convergence speed and global optimization to optimize the controllable parameters in the high-precision numerical prediction model can effectively improve the productivity of low production wells with timeliness, and bring greater economic value while saving development cost. Using PCA-GRA method, the sample weight and the weighted correlation ranking results of parameters affecting tight oil production were obtained. Thereupon then the main controlling factors of tight oil production were determined. Then we set up a BP neural network model with by taking the main controlling factors as input and tight oil production as output. The prediction effect of the network was good and can be put into use. The results of sensitivity analysis showed that the network was stable, and the total fracturing fluid volume had the greatest impact on the production of tight oil. Finally, by using genetic algorithm, we optimized the fracturing parameters of all low production well samples in the field data. Combined with the fracturing parameters of all high production well samples and the optimized fracturing parameters of low production wells, the optimal interval of fracturing parameters was given, which can provide guidance for the field fracturing operation.

Summary Production forecasting is usually performed by applying a single model from a classical statistical standpoint (point estimation). This approach neglects: (a) model uncertainty and (b) quantification of uncertainty of the model’s estimates. This work evaluates the predictive accuracy of rate-time models to forecast production from tight-oil wells using Bayesian methods. We apply Bayesian leave-one-out (LOO) and leave-future-out (LFO) cross-validation (CV) using an accuracy metric that evaluates the uncertainty of the models’ estimates: the expected log predictive density (elpd). We illustrate the application of the procedure to tight-oil wells of west Texas. This work assesses the predictive accuracy of rate-time models to forecast production of tight-oil wells. We use two empirical models, the Arps hyperbolic and logistic growth models, and two physics-based models: scaled slightly compressible single-phase and scaled two-phase (oil and gas) solutions of the diffusivity equation. First, we perform Bayesian inference to generate probabilistic production forecasts for each model using a Bayesian workflow in which we assess the convergence of the Markov chain Monte Carlo (MCMC) algorithm, calibrate, and evaluate the robustness of the models’ inferences. Second, we evaluate the predictive accuracy of the models using the elpd accuracy metric. This metric provides a measure of out-of-sample predictive performance. We apply two different CV techniques: LOO and LFO. The results of this study are the following. First, we evaluate the predictive performance of the models using the elpd accuracy metric, which accounts for the uncertainty of the models’ estimates assessing distributions instead of point estimates. Second, we perform fast CV calculations using an important sampling technique to evaluate and compare the results of the application of two CV techniques: leave-one-out cross-validation (LOO-CV) and leave-future-out cross-validation (LFO-CV). While the goal of LOO-CV is to evaluate the models’ ability to accurately resemble the structure of the production data, LFO-CV aims to assess the models’ capacity to predict future-time production (honoring the time-dependent structure of the data). Despite the difference in their prediction goals, both methods yield similar results on the set of tight-oil wells under study. The logistic growth model yields the best predictive performance for most of the wells in the data set, followed by the two-phase physics-based flow model. This work shows the application of new tools to evaluate the predictive accuracy of models used to forecast production of tight-oil wells using: (a) an accuracy metric that accounts for the uncertainty of the models’ estimates and (b) fast computation of two CV techniques, LOO-CV and LFO-CV. To our knowledge, the proposed approach is novel and suitable to evaluate and eventually select the rate-time model(s) with the best predictive accuracy of models to forecast hydrocarbon production.

To determine the accumulation conditions and pattern of tight oil in oil shales in the Damintun Sag, Bohai Bay Basin, this study investigated the basic geological conditions of the source rocks and reservoirs in the sag using methods such as organic carbon analysis, whole-rock XRD analysis, and field emission scanning electron microscopy. The results show that: (1) The high-quality source rocks in the lower submember of the fourth member of the Shahejie Formation (E2S42) in the Damintun Sag have high organic matter abundance, favorable organic matter types, high hydrocarbon expulsion efficiency, and high fluidity. Therefore, they provide sufficient oil sources for tight oil accumulation.; (2) During the burial of organic-rich shales, the thermal degradation of organic matter produces large amounts of organic acids, which can dissolve carbonate minerals. In this way, secondary pores are formed.; (3) The special microscopic pore structure that connects fractures to pores is the key to the enrichment of tight oil is a key factor for the high oil saturation of pores in oil shales; (4) The breakthrough pressure (up to 100 MPa) and specific surface area of dolomitic mudstones in the E2S42 submember are significantly higher than those in other horizons. As a result, the dolomitic mudstones can effectively seal the underlying tight reservoirs; (5) Compared with the tight oil in tight sandstones, the tight oil in the oil shales in the study area has significantly superior geological conditions for reservoir formation, such as the favorable arrangement of hydrocarbon expulsion channels, low filling resistance, and the presence of reservoir spaces.

Vast reserves are locked up in nonconventional reservoirs. These include gas hydrates, tar sands, tight oil reservoirs, oil shales, shale gas, and coalbed methane. Plastic and solid hydrocarbons are common in sedimentary rocks of diverse ages in many parts of the world. They are distinct from crude oils; many of these hydrocarbons are viscous. The solid and heavy, viscous hydrocarbons occur as lakes or pools on the earth's surface and are disseminated in veins and pores in the subsurface. Two genetically distinct modes of occurrence are recognized: (1) inspissated deposits and (2) secondary deposits. Heavy, viscous oil deposits occur at or near the earth's surface in many parts of the world. The deposits have API (American Petroleum Institute) gravities of 50–150 and typically occur within highly porous sands, generally referred to as tar sands, or bitumen oil sands and heavy oil deposits. Vast reserves are contained within these beds. Two basic approaches have been developed to extract oil from tar sands: surface mining and processing (ex situ) and subsurface extraction (in situ). Two in situ methods to recover oil are cyclic steam injection and steam-assisted gravity drainage. Oil shale, also known as kerogen shale, is a fine-grained sedimentary rock that yields oil on heating. In oil shales, oil is contained within the complex structure of kerogen, from which it may be distilled. Oil shales are widely distributed around the globe and may contain locked within them more energy than in all presently discovered conventional oil reserves. The world's oil shales may contain 30 trillion barrels of oil. Extraction methods include surface mining and retorting and subsurface heating and extraction. The oil shale extraction industry has seen several “boom and bust” cycles. The reasons for the rise and fall of the oil shale extraction industry are twofold: economics and technology. Tight oil reserves consist of sapropelic organic-rich source beds and adjacent tight (low porosity and permeability) reservoirs and are located in the oil generation window in a sedimentary basin. Keys to production include the following: abnormal pressure; matrix and fracture porosity and permeability; low matrix water saturation (some oil wet systems); organic-rich, mature source rocks; brittle reservoir rocks; and pervasive oil saturation. The most successful low-permeability oil play to date is the Bakken Formation of the Williston Basin. Coalbed gas is now commercially produced from Pennsylvanian coal measures in Alabama, Cretaceous coals from the western interior basin of the United States. Most coals produce dry gas, methane rich. Coal acts as both a source rock and a reservoir rock for gas. Gas is retained in coalbeds as sorbed gas and free gas in fractures (or cleats). Most coalbed gas deposits go through a dewatering stage before significant gas production occurs. Shale gas production in the United States first occurred in 1821. Shale gas exploration and production has undergone a renaissance in the United States in the last 20 years. The revolution has been brought about by a combination of horizontal drilling, multistage hydraulic fracturing, and three-dimensional seismic surveys. Shale gas reservoirs are self-sourced. The shales are organic-rich, fine-grained sedimentary rocks. The shales may be thermally immature to postmature and contain biogenic or thermogenic gas. Gas is stored in shales as sorbed gas, free gas in fractures and intergranular porosity, and dissolved in bitumen or kerogen. Tight gas reservoirs (usually sandstones) can be subdivided into two types based on porosity and low permeability. These two types are referred to as high porosity (HP) reservoirs and low porosity (LP) reservoirs. The HP type is present in the northern Great Plains and eastern Plains region of the United States. The reservoirs are at shallow burial depths and consist of chalks, siltstones, and very fine-grained sandstones. Although these reservoirs have HP (10–40%), they have low in situ permeability (

В работе рассмотрен подход к разработке залежей трудноизвлекаемых запасов (ТРИЗ), характеризующихся сложным геологическим строением, низкой проницаемостью (менее 1 мД) и дифференциацией насыщенности по площади и разрезу. Применение стандартных подходов и технологий разработки для таких сложных коллекторов затрудняет получение высокой эффективности извлечения запасов. С целью выбора оптимальной технологии разработки проведена оценка применимости газовых методов увеличения нефтеотдачи (МУН) с использованием аналитических методик и расчетов на композиционной гидродинамической модели., The paper considers an approach to the development of deposits of tight oil, characterized by a complex geological structure, ultra-low permeability (less than 1 mD) and saturation differentiation. The use of standard approaches and development technologies for such complex reservoirs makes it difficult to obtain high efficiency of oil recovery. In order to choose the optimal development technology, the applicability of gas methods for enhanced oil recovery was evaluated using analytical techniques and calculations based on a compositional flow model.

During hydraulic fracturing (HF) stimulation for unconventional reservoir development, seismic attenuation has a significant influence on high-frequency microseismic data. Attenuation also provides important information for characterizing reservoir structure and changes to it due to HF injections. However, the attenuation effect is typically not considered in microseismic analysis. We have adopted the spectral ratio and centroid-frequency shift methods to estimate the subsurface attenuation (the factor [Formula: see text]) in a tight oil reservoir in the Ordos Basin, China. The P- and S-wave attenuations are calculated using the 3C waveform data recorded by a single-well downhole geophone array during a 12-stage HF stimulation. Both methods provide similar results (with differences in [Formula: see text] of absolute values less than 0.010 for P- and S-waves). For individual events, their median [Formula: see text] values calculated from different geophones are selected to represent the average attenuation. Spatiotemporal variations in attenuation are obtained by investigating [Formula: see text] values along propagating rays linking different source–receiver pairs. The [Formula: see text] values derived at different HF stages reveal significant attenuation in the targeted tight sandstone layer (0.030–0.062 for [Formula: see text] and 0.026−0.058 for [Formula: see text]), and the attenuation is apparently increased by fluid injection activities. We explain the sudden decrease in attenuation near the geophone array as a result of high shale content using log data from a horizontal treatment well. The consistency between the [Formula: see text] values and horizontal well-log data, as well as the HF process, indicates the reliability and robustness of the attenuation results. By studying spatiotemporal variations in attenuation, the changes in subsurface structures may be quantitatively characterized, thereby creating a reliable basis for microseismic modeling and data processing and providing additional information on monitoring the HF process.

Tight reservoirs are a major focus of unconventional reservoir development. As a means to improve hydrocarbon recovery from tight reservoirs, imbibition has been received increasing attentions in recent years. This study evaluates how the changes in temperature and pressure affect imbibition through conducting experimental tests under various conditions on samples from the Yan Chang formation, a tight reservoir in Ordos Basin. The fluid distribution is compared before and after imbibition in core samples by nuclear magnetic resonance method. The results show that the imbibition recovery is significantly improved through increasing temperature and pressure. A high temperature facilitates molecular thermal movements, increasing oil-water exchange rate. The core samples are characterized with nano-mesopores, which is followed by nano-macropores, micropores, mesopores, and nano-micropores. Comparative analysis of nuclear magnetic resonance shows that the irreducible water saturation increases after imbibition and is mainly distributed in nano-pores. Increasing pressure increases the amount of residual water in nano pores, with the relatively more significant increase in the amount of residual water in nanomacro-pores compared with other types of pores. Cited as: Liang, Y., Lai, F., Dai, Y., Shi, H., Shi, G. An experimental study of imbibition process and fluid distribution in tight oil reservoir under different pressures and temperatures. Capillarity, 2021, 4(4): 66-75, doi: 10.46690/capi.2021.04.02

Summary A common approach to forecast production from unconventional reservoirs is to extrapolate single-phase flow solutions. This approach ignores the effects of multiphase flow, which exist once the reservoir pressure falls below the bubble/dewpoint. This work introduces a new two-phase (oil and gas) flow solution suitable to extrapolating oil and gas production using scaling principles. In addition, this study compares the application of the two-phase and the single-phase solutions to estimates of production from tight-oil wells in the Wolfcamp Formation of west Texas. First, we combine the oil and the gas flow equations into a single two-phase flow equation. Second, we introduce a two-phase pseudopressure to help linearize the pressure diffusivity equation. Third, we cast the two-phase diffusion equation into a dimensionless form using inspectional analysis. The output of the model is a predicted dimensionless flow rate that can be easily scaled using two parameters: a hydrocarbon pore volume and a characteristic time. This study validates the solution against results of a commercial simulator. We also compare the results of both the two-phase and the single-phase solutions to forecast wells. The results of this research are the following: First, we show that single-phase flow solutions will consistently underestimate the oil ultimate recovery factors (URFs) for solution gas drives. The degree of underestimation will depend on the reservoir and flowing conditions as well as the fluid properties. Second, this work presents a sensitivity analysis of the pressure/volume/temperature (PVT) properties, which shows that lighter oils (more volatile) will yield larger recovery factors for the same drawdown conditions. Third, we compare the estimated ultimate recovery (EUR) predictions for two-phase and single-phase solutions under boundary-dominated flow (BDF) conditions. The results show that single-phase flow solutions will underestimate the ultimate cumulative oil production of wells because they do not account for liberation of dissolved gas and its subsequent expansion (pressure support) as the reservoir pressure falls below the bubblepoint. Finally, the application of the two-phase model provides a better fit when compared with the single-phase solution. The present model requires very little computation time to forecast production because it only uses two fitting parameters. It provides more realistic estimates of URFs and EURs, when compared with single-phase flow solutions, because it considers the expansion of the oil and gas phases for saturated flow. Finally, the solution is flexible and can be applied to forecast both tight-oil and gas condensate wells.

After single-gas (SG) injection operations in tight oil reservoirs, a significant amount of oil is still unrecovered. To increase productivity, several sequencing gas injection techniques have been utilized. Given the scarcity of research on multiple-gas alternating injection schemes, this study propose an optimized triple-alternating-gas (TAG) injection for improved oil recovery. The performance of the TAG process was demonstrated through numerical simulations and comparative analysis. First, a reservoir compositional model is developed to establish the properties and composition of the tight oil reservoir; then, a suitable combination for the SG, double alternating gas (DAG), and TAG was selected via a comparative simulation process. Second, the TAG process was optimized and the best case parameters were derived. Finally, based on the oil recovery factors and sweep efficiencies, a comparative simulation for SG, DAG, and TAG was performed and the mechanisms explained. The following findings were made: (1) The DAG and TAG provided a higher recovery factor than the SG injection and based on recovery factor and economic advantages, CO2 + CH4 + H2S was the best choice for the TAG process. (2) The results of the sensitivity analysis showed that the critical optimization factors for a TAG injection scheme are the injection and the production pressures. (3) After optimization, the recovery factor and sweep efficiency of the TAG injection scheme were the best. This study promotes the understanding of multiple-gas injection enhanced oil recovery (EOR) and serves as a guide to field design of gas EOR techniques.

Conventional oil reserves in Colombia are depleted. The country´s reserve-to-production ratio is estimated as 5 years. Therefore, the search for new resources and their conversion into proven reserves are essential. In this case, the production of unconventional reservoirs is an option in Colombia. This work evaluates the technical and economic feasibility of the production of a Tight Oil source rock reservoir, considering parameters such as fracture shape factor, fracture propagation, fracture pressure, international oil price, petrophysical characteristics, fluid properties, drilling cost, completion, and fiscal regime. The methodological development of the work allowed concluding that this reservoir located in the middle Magdalena Valley basin has production potential and those factors such as the type of completion, drilling technique, and cost of lifting the resource have a significant impact on the viability of the project. Resumen Las reservas de petróleo proveniente de reservorios convenvionales en Colombia son escazas, la relación reserva/producción en el país es de 5 años. De esta manera, la búsqueda por nuevas reservas y producción de nuevos recursos son imprescindibles. Así, la producción de yacimientos no convencionales es una salida a la escasez de producción de crudo. Este trabajo evalúa la factibilidad técnica y económica de la producción de un yacimiento de roca generadora Tight Oil, fueron considerados parámetros como factor de forma de la fractura, propagación de la fractura, presión de fracturamiento, precio internacional del petróleo, características petrofísicas, propiedades de los fluidos, costo de perforación, completamiento y el régimen fiscal. El desarrollo metodológico del trabajo permitió concluir que este yacimiento ubicado en la cuenca del valle medio del magdalena tiene potencial de producción y que factores como el tipo de completamiento, técnica de perforación y costo del levantamiento del recurso tienen un impacto significativo en la viabilidad del proyecto.

The release of dissolved gas during the development of gas-bearing tight oil reservoirs has a great influence on the effect of development. In this article, the high-pressure mercury intrusion experiment was carried out in cores from different regions and lithologies of the Ordos Basin and the Sichuan Basin. The objectives are to study the microscopic characteristics of the porous throat structure of these reservoirs and to analyze the porous flow resistance laws of different lithology by conducting a resistance gradient test experiment. A mathematical model is established and the oil production index is corrected according to the experiment results to predict the oil production. The experimental results show that for tight reservoirs in the same area and lithology, the lower the permeability under the same back pressure, the greater the resistance gradient. And for sandstone reservoirs in different areas, the resistance gradients have little difference and the changes in the resistance coefficients are similar. However, limestone under the same conditions supports a much higher resistance gradient than sandstone reservoirs. Furthermore, the experimental results are consistent with the theoretical analysis indicating that the PVT (pressure–volume-temperature) characteristics in the nanoscale pores are different from those measured in the high-temperature, high-pressure sampler. Only when the pressure is less than a certain value of the bubble point pressure, the dissolved gas will begin to separate and generate resistance. This pressure is lower than the bubble point pressure measured in the high-temperature and pressure sampler. The calculation results show that the heterogeneity of limestone reservoirs and the mismatch of fluid storage and flow space will make the resistance, generated by the separation of dissolved gas, have a greater impact on oil production.

Multistage hydrofracturing of horizontal wells is one of the key technologies for deep tight oil and gas resource exploitation. The stable and parallel propagation of multiple fractures formed by m...

Determination of the lower limit of flowing porosity for oil recovery from tight oil reservoirs is the key to promoting scientific and economic development of tight oil reservoirs. This study performed a comprehensive analysis based on pore-throat radius distribution measurements, low-temperature nitrogen adsorption measurements, and centrifugation and nuclear magnetic resonance measurements to establish a method for calculating the bound water film thickness and, in turn, the lower limits of pore-throat radius and permeability. The method was applied on rock samples from typical tight oil reservoirs in the Daqing and Changqing oil regions in China. The results indicated that for a given reservoir, bound water film thickness tends to be constant. With decreasing permeability, bound water film thickness showed an L-shaped distribution curve due to the changes in the pore-throat structure and the impact of molecular forces. The flat segment of the distribution curve corresponded to the lower limit of pore-throat radius, while the curve inflection point corresponded to the lower limit of permeability. The pore-throat radius and permeability limits were 22 nm and 0.08 mD for the Daqing tight oil reservoir and 18 nm and 0.03 mD for the Changqing tight oil reservoir, respectively.

Microfractures can obviously improve physical properties and connectivity of tight reservoir, which is an important factor to control the exploration and development of tight oil and gas. However, there is little quantitative research on microfracture, thus, its reservoir mechanism is not clear. Taking the Cretaceous tight reservoir in the Liuhe Basin as an example, the microstructure characteristics of fractures were discussed on micron and nanometer scale respectively, and their contribution to physical properties was revealed in this paper. The results show that a small number of intercrystalline pores, intergranular pores and dissolution pores are developed in the Cretaceous tight reservoirs, and microfractures are the main reservoir space. The width of nano-sized fracture is mainly in the range from 2 nm to 300 nm, in which the proportion of fractures with larger width increases obviously with the increase of buried depth, and its contribution to pore volume is also greater. The width of micron-sized fracture is mainly in the range from 2.95 μ m to 114 μ m, and micron-sized fracture is much more developed with the increase of burial depth. Although the distribution frequency of micron-sized fracture is much smaller than that of nano-sized microfracture, it makes a greater contribution to permeability.

In this paper, three different scenarios were experimentally investigated to compare carbon dioxide based enhanced oil recovery methods. These methods are continuous carbon dioxide (immiscible injection), water alternating gas, and cyclic carbon dioxide injection were investigated. In scenario A, the maximum oil recovery factor for water flooding is about 19% when there is no oil production. The maximum oil recovery at miscibility stage is about 46%. The reason for this low value of oil recovery factor might correspond to the sufficient interaction time between oil and dissolved gas. In scenario B, the total oil recovery factor is about 60% when the water alternating gas injection was performed in the system. In scenario C, after cyclic carbon dioxide injection, final oil recovery factor reached to 62%. The maximum oil recovery after miscibility stage is about 78%. In scenario B and C, regarding the more oil volume production, there are more void spaces that can be a good place for carbon dioxide storage. However, for scenario B, as the injection pattern has been changed alternatively, the void spaced had been occupied by water and this is why the carbon storage capacity was being decreased for this scenario rather than other two scenarios.

Owing to the problems of guar gum fracturing fluid and conventional slickwater fracturing fluid systems in hydraulic fracturing of tight oil reservoirs, such as bad fracture network capacity, high damage, and low sand-carrying performance, researchers are actively looking for new alternative fracturing fluids. This study takes four commonly used additives for hydraulic fracturing of tight oil and gas reservoirs in western China, including the conventional polyacrylamide friction reducer EM30S, bioglue, thickener CHS-1, and high-viscosity friction reducer HVFR-1. By testing the water solubility, rheological properties, drag reduction, sand-carrying performance, imbibition oil displacement effect, and residue content of the four additives, the best additives suitable for hydraulic fracturing of tight oil and gas reservoirs were selected, and a set of indoor evaluations and the experimental method of screening hydraulic fracturing additives for tight oil and gas reservoirs were established. The research results show that the high-viscosity slickwater system composed of CND + HVFR-1 is more suitable for hydraulic fracturing of tight oil and gas reservoirs. Compared with the other three types of additives, CND + HVFR-1 fracturing fluid has good water solubility, and the dissolution time is less than 30 s. Therefore, in order to save construction time, the CND + HVFR-1 high-viscosity slickwater system is first recommended for field application. The research results of rheological properties show that although the apparent viscosity of high-concentration HVFR-1 + CND is low, the cross value of G′ and G″ is the smallest (0.006 Hz) and the elastic modulus is the largest (4.554 Pa) corresponding to 1 Hz. HVFR-1 + CND has better sand-carrying performance when used as a sand-carrying liquid. CND + HVFR-1 not only achieves a friction reduction rate of more than 60% but also has the effect of imbibition oil displacement to improve oil recovery; it can easily break gels, and its low residue content can ensure rapid flowback after construction is completed, and the lower residue content also causes the least damage to the reservoir. At the same time, the establishment of this evaluation method provides a certain reference for other researchers who select fracturing fluids for tight oil and gas reservoirs.

In order to understand the exploration and development potential of tight oil in the oil field exploration and development stage, the reservoir characteristics of Chang 6 oil formation in Ansai area of Ordos Basin were studied. In this paper, the reservoir characteristics are studied by using aseries of experimental data, such as cast sheet, cathodoluminescence, electron probe, conventional mercury injection, constant rate mercury injection experiment, scanning electron microscope, etc. The results show that the lithologic characteristics of Chang 6 reservoir group in Ansai area are mainly feldspathic sandstone, accounting for 64.57%, followed by lithic feldspathic sandstone accounting for 31.36%, the sum of the two accounting for 95.93%. Pores are most developed in Ansai area, and the interstitial materials are mainly chlorite, kaolinite and illite. Primary intergranular pores are mainly developed in this area. Besides primary intergranular pores, there are also some feldspar dissolved pores in Ansai region. There are many laumontite dissolved pores in this region. The reservoir type in Ansai region is “low porosity and ultra low permeability”, but the Chang 6 member reservoir in Ansai region is very well characterized by “low porosity and ultra low permeability”.

The low oil productivity of tight oil reservoirs is mainly caused by poor reservoir physical properties such as low porosity and permeability, a small pore and throat ratio, and bad well connectivity, which lead to bad water injection capability and rapid pressure decline for the reservoir. In this paper, an enhanced oil recovery technique for tight oil reservoirs is proposed by combination of horizontal well volume fracturing and CO2 huff-n-puff to improve the reservoir physical properties and increase the flow capability of crude oil. In the initial reservoir development stage, the precise horizontal well trajectory and reservoir volume fracturing scale are designed by analyzing the distribution of sand body thickness and the oily sedimentary facies. The micro-seismic tracking technique is also used to monitor the fracture elongation. When the reservoir energy cannot satisfy the economic limit of oil productivity, the CO2 huff-n-puff technique is applied to increase the reservoir energy quickly. After the precise fracturing technique is used in tight oil Block X, the average oil production rate of six fractured horizontal wells increases by 5 ton (1 ton = 7.33 bbl) at the initial production stage, and the effective oil production increase life lasts for 32 months. When the reservoir energy is supplemented using the CO2 huff-n-puff technique, the oil production rate of pilot experiment well SP-1 increases from 1.9 to 12.8 ton with a cumulative oil increase of 1333.8 ton.

Whether oil emplacement and diagenetic sequences provoke, deteriorate, or have no effect on pore network evolution, as implied by recent tests and theoretical analysis, are critical factors in forecasting hydrocarbon exploration and development potentials. Therefore, a systematic investigation on the effect of oil emplacement of tight sandstones is conducted to study the importance of this behavior on the pore evolution path. This study evaluated the role played by oil emplacement and diagenesis in the pore network evolution of Upper Triassic tight sandstones in the Ordos Basin. To help provide a comprehensive understanding, we have used a multidisciplinary method including physical properties, casting thin section, scanning electron microscope, X-ray diffraction, fluorometric, and inclusion analysis. The results demonstrate that the sandstones could be divided into four groups based on new criteria: calcareous sandstone, high soft component sandstone, low soft component sandstone with continual oil emplacement, and low soft component sandstone with intermittent oil emplacement. The physical properties of those types of sandstones were gradually reduced. Quartz cement captured hydrocarbon, carbonate captured hydrocarbon, free hydrocarbon, and adsorbed hydrocarbon were the four main kinds of hydrocarbons. The maturity of those sandstones was decreased progressively, indicating that the formation time of those hydrocarbons was favorable to maturity. Four stages of oil emplacement happened, and large-scale emplacement mainly occurred in the late Jurassic and early Craterous. The evidence demonstrated that tight sandstones’ high porosity could be attributed to positive diagenetic contributions with a complex interplay of chemical compaction, early formed clays, and large-scale oil emplacement. This work would provide new sights for a better understanding of the tight oil accumulation modes, and the findings could be applied in the hydrocarbon exploration and development field.

The Paleogene upper Xiaganchaigou Formation (E32) is the most important source rock and reservoir in the Qaidam Basin. However, there are few studies on the processes of hydrocarbon accumulation in this formation; therefore, its hydrocarbon resource potential has not been estimated reasonably. This paper evaluates the hydrocarbon generation properties in light of an improved hydrocarbon generation and expulsion potential model. According to the geochemical characteristics of source rocks and the petrological features of reservoirs, the potentials of different resource types, including conventional oil, tight oil and shale oil, are quantified by combining the buoyancy-driven hydrocarbon accumulation depth (BHAD) and the lower limit for movable resource abundance. The results show that the source rocks are characterized by a large thickness (more than 1000 m), moderate organic matter content, high marginal maturity and a high conversion rate (50% hydrocarbons have been discharged before Ro = 1%), which provide sufficient oil sources for reservoir formation. Moreover, the reservoirs in the Qaidam Basin consist mainly of low-porosity and low-permeability tight carbonates (porosity of 4.7% and permeability less than 1 mD). The maximum hydrocarbon generation, expulsion, retention and movable retention intensities at present are 350 × 104 t/km2, 250 × 104 t/km2, 130 × 104 t/km2 and 125 × 104 t/km2, respectively. The thresholds of hydrocarbon generation, expulsion and BHAD were 0.46% Ro, 0.67% Ro and 0.7% Ro, respectively. Moreover, the dynamic evolution process of hydrocarbon accumulation was divided into three evolution stages, namely, (a) initial hydrocarbon accumulation, (b) conventional hydrocarbon reservoir and shale oil accumulation and (c) unconventional tight oil accumulation. The conventional oil, tight oil and movable shale oil resource potentials were 10.44 × 108 t, 51.9 × 108 t and 390 × 108 t, respectively. This study demonstrates the good resource prospects of E32 in the Qaidam Basin. A comprehensive workflow for unconventional petroleum resource potential evaluation is provided, and it has certain reference significance for other petroliferous basins, especially those in the early unconventional hydrocarbon exploration stage.

Based on the microscopic pore-throat characterization of typical continental tight reservoirs in China, such as sandstone of Cretaceous Qingshankou and Quantou formations in Songliao Basin, NE China sandy conglomerate of Baikouquan Formation in Mahu area and hybrid rock of Lucaogou Formation in Jimusaer sag of Junggar Basin, NE China the theoretical lower limit, oil accumulation lower limit, effective flow lower limit and the upper limit of tight oil reservoirs were defined by water film thickness method, oil bearing occurrence method, oil testing productivity method and mechanical balance method, respectively. Cluster analysis method was used to compare the differences in pore-throat structure of different tight reservoirs, determine the grading criterion of tight reservoirs, and analyze its correlation with the limit of reservoir formation. The results show that the boundary between tight reservoir and conventional reservoir corresponds to the upper limit of physical properties, the boundary of class II and class III tight reservoirs corresponds to the lower limit of effective flow, the boundary of class III and class IV tight reservoirs corresponds to the lower limit of reservoir forming, and the theoretical lower limit of tight reservoir corresponds to the boundary between tight reservoir and non-reservoir. Finally, the application results of the grading evaluation criterion show that the tight oil productivity is highly controlled by the type of tight reservoir, and class I and class II tight reservoirs are the favorable sections for high production of tight oil.

Zero-dimensional carbon nanomaterials show intriguing potential in the field of unconventional oil resource development for reducing injection pressure and enhancing oil recovery. However, the complicated synthesis procedure, necessity for surfactant and limited understanding of the mechanism impede their practical applications. In this study, novel high-hydrophilic carbon dots (hh-CDs) with an average particle size of 2.54 ± 0.016 nm were facilely synthesized through an electrochemical approach by employing cost-effective petroleum coke as the carbon source, followed by treating with ozone for further oxidation. The abundant surface functional groups render hh-CDs superior hydrophilicity, dispersibility and stability. Core flooding tests show 0.20 wt% hh-CDs nanofluid delivers a prominent pressure-reducing rate of 23.81% and an enhancement in oil recovery of 26.38% without any surfactant. Analytical results of atomic force microscope (AFM) with hydrophobic probe reveal hh-CDs can adsorb on the rock surface to alter the micro-scale wettability from oil-wet to homogeneous water-wet. The hh-CDs can also efficiently reduce the core surface roughness and afford excess disjoining pressure for oil displacement, accounting for the impressive performance. This work provides a feasible oil systemic circulation for the synthesis of versatile surfactant-free carbon dots for boosting injection pressure reduction and enhancing oil recovery in tight oil reservoirs.

Xin'anbian Oilfield is the large tight oilfield to be first exploration discovery in china. The production of tight oil increased significantly in recent years,. It shows great exploration potential of Chang7 tight oil. But the physical property and hydrocarbon enrichment characteristics of Chang 7 tight oil reservoirs were rarely studied, The forming conditions of tight oil reservoirs are systematically summarized and analyzed through the study of hydrocarbon generation, sedimentary reservoirs and hydrocarbon migration and accumulation based on production and core experimental data. The result shows that, The porosity of the Chang 72 reservoir mainly distributed in 5.0–11.0%, average at 7.9%, The permeability mainly distributed in 0.04–0.18 × 10−3 μm2, average at 0.12 × 10−3 μm2, The pore diameters of the tight oil reservoir distributed in 2–8 μm. The high-quality Chang 73 source rocks and the micropsammite of Chang 72 subaqueous distributary channel were widely distributed in the study area. The lenticular or banded sand bodies are distributed among mudstone or hydrocarbon source rocks and have the advantage of migration distance for hydrocarbon accumulation. The reservoir space is composed of micro-nanometer porosity and throat. It is formed in the process of increasing pressure during hydrocarbon generation and hydrocarbon accumulation. The Chang 7 tight oil was generated in the early Cretaceous and injected into the sand of the subaqueous distributary channel driven by continuous hydrocarbon generation supercharging. The formation and accumulation of tight oil reservoirs are mainly controlled by source rocks, sedimentary microfacies and reservoirs of good quality.

As an important part of carbon dioxide capture, utilization and storage (CCUS), the progress of injecting CO2 into oil reservoirs could increase the recovery rate and achieve large-scale carbon storage. It has become one of the most important carbon storage methods around the world. This paper selected the tight sandstone of the fourth member of the Quantou Formation in the southern Songliao Basin to carry out a CO2 storage physical simulation experiment. Representative samples were collected at 24 h, 72 h, 192 h and 432 h to study the CO2 water-rock interaction and to analyze the mineral composition, pore structure and the evolutionary characteristics of physical reservoir properties over time. Physical property analysis, Ion analysis, X-ray diffraction mineral analysis, QEMSCAN mineral analysis, scanning electron microscopy and high-resolution CT scanning techniques were adopted. The main points of understanding were: (i) It shows a differential evolution of different minerals following the storage time of CO2, and carbonate minerals are mainly dissolved with ankerite as a typical representation; a small amount of calcite is formed in 24 h, and dissolved in the later period; feldspar and quartz were partially dissolved; clay mineral precipitation blocked the pores and gaps; (ii) The evolution in mineral variation leads to the complexity of pore structure evolution, following a trend of “small pores decreasing and large pores increasing” with extending storage time. The final porosity and permeability ratios gradually increase from 4.07% to 21.31% and from 2.97% to 70.06% respectively; (iii) There is a negative correlation between the increasing ratio and the original physical properties of the tight stones due to the dissolution of ankerite. Relevant research could provide scientific guidance and technical support for the geological storage of CO2 in lacustrine tight continental sandstones and the development of CCUS technology.

Primary objective of the paper is to represent the functionality of nanotechnology in Enhanced Oil Recovery (EOR). Nanoparticles can resist high temperature and pressure in subsurface oil reservoir system and exhibit different properties compared to same fine or bulk molecules. Due to small in size, it increases surface area and it creates massive diffusion driving force at higher pressure and temperature. In small surface area, it contains much higher concentration of atoms. Nanoparticles are used to modify optical, specific, thermal, interfacial properties of tight oil reservoir with 5–50 μm size pore diameter which consists trapped oil in place. Study reveals that by controlling nano mineral complexes can increase recovery of oil in oil field due to capillary hysteresis value change and specific behavior of clay mineral. Nanoparticles boost the oil recovery by mechanism of reduction in mobility ratio which reduces viscosity of heavy oil and interfacial tension and increase in fault lines permeability. Nanoparticles like silane treated silicon oxides, aluminium oxides in brine can be used. They have tendency of displacement of water and magnifies flow of oil in well. Some nanoparticles performance depends upon its operational condition for EOR process. In modern oil and gas domain by using EOR technique have oil recovery factor magnitude of 0.3–0.5; but by using nanotechnology there will be growth in oil & gas recovery efficiently and guarantying oil recovery factor range up to 0.5 to 0.6. It is not possible to know all application of nanotechnologies; but some experimental results and advanced technologies deduce that there is reduction in cost of hydrocarbon production for its market use by application of nanotechnology in EOR. Further advancement in nanotechnologies can increase more recovery of oil & gas.

The key to the efficient development of a tight reservoir is its accurate evaluation. In this study, the pore throat structure characteristics of sandstone samples in the study block were analyzed by high-pressure mercury injection technology. According to the characteristics of the capillary pressure curve, the sandstone samples in the study block were divided into three types: the first type has a reservoir permeability greater than 0.7 mD and a core mercury injection saturation of 96% with a good reservoir quality; the second type has a reservoir permeability ranging from 0.4 to 0.7 mD and a core mercury injection saturation of 80% with a moderate reservoir quality; and the third type has a reservoir permeability between 0.1 and 0.4 mD and a core mercury injection saturation of 50% with a poor reservoir quality. Also, high-resolution synchrotron radiation imaging and scanning electron microscopy were used to observe the pore throat structure, connectivity, and microscopic heterogeneity of sandstone samples, showing an increasing level of pore disconnection, serious microscopic heterogeneity, and poor reservoir performance as reservoir permeability declines. As mineral composition tests show, the lithology of the tight sandstone in the target block is mainly medium-grained and fine-grained feldspar lithic sandstone and the longitudinal heterogeneity of lithology and mineral components of tight sandstone is relatively weak at above the centimeter level. Besides, based on the high-pressure mercury injection test data, fractal theory is applied to calculate the fractal dimensions of the three types of reservoirs. The result shows a gradual increase in fractal dimensions with the decrease of reservoir quality, in which the closer the fractal dimension is to 3, the more serious the microscopic heterogeneity is, and the stronger the roughness of the pore surface is. As a result, the more heterogeneous the tight reservoir gets, the more likely the injected fluid is to flow along the developed and connected pore regions.

A tight conglomerate reservoir is a kind of unconventional reservoir with strong heterogeneity, and CO2 injection is an economical and environmentally friendly method to enhance tight oil recovery. Supercritical CO2 is a very promising fluid medium for unconventional reservoir development due to its gas-liquid dual properties. In this study, the production effects of supercritical CO2 and non-supercritical CO2 in tight conglomerate reservoirs were quantitatively analyzed by huff and puff simulation experiments conducted under reservoir conditions (formation pressure 37 MPa, temperature 89 °C). Also, the influencing factors of CO2 huff and puff production, including injection volume, soaking time, and throughput cycles, were investigated. The results showed that supercritical CO2 improves the recovery by 4.02% compared with non-supercritical CO2. It could be seen that supercritical CO2 plays a positive role in improving tight conglomerate reservoirs. The optimal injection volume, soaking time, and throughput cycles were determined to be 0.50 PV, 2 h, and 3 cycles, respectively. This paper provides an important basis for the study of supercritical CO2 production in tight conglomerate reservoirs.

Hydraulic fracturing technology has become an effective technical method of developing tight oil reservoirs, such as an oilfield in Mahu, China. However, numerical simulation of the actual fracture seam network remains problematic. In this paper, we have simulated hydraulic fractures in the Urho Group of the Mahu target layer and analyzed the characterization of the rock mechanics parameters. The results show that Young’s modulus of the Wuerhe domain ranges between 18 and 58.5 GPa, with an average of 32.4 Gpa, the Poisson’s ratio is between 0.21 and 0.38, with an average of 0.31, the brittleness index is between 21.0 and 89.0, with an average of 44.3, and the hydraulic fracturing can form a multi-branch crack modification. The designed direction of horizontal wells in the area is north-south, and the horizontal stress difference is between 4.2 and 9.8 MPa, which facilitates easy fracturing of the reservoir and reforming of a complex seam network. Simulation of the artificial seam network helps to optimize the reasonable parameters of fracturing and the development parameters of horizontal wells in the Mahu 1 well area.

CO2 fracturing is a promising technology for oil field development in tight, continental deposits, with potential advantages of enhanced oil recovery (EOR), CO2 sequestration, and water conservation. Compared with CO2-EOR techniques, such as CO2 huff and puff and CO2 flooding, CO2 can interact with reservoir rock and fluid under higher pressure conditions during fracturing, resulting in CO2 stimulation and sequestration effects that differ from those that occur during conventional CO2-EOR. In this paper, the CO2 interactions between CO2 and reservoirs in continental tight oil reservoirs under fracturing conditions are systematically studied through laboratory experiments. The results show that under high pressure, CO2 effectively changes the pore structure through the extraction of hydrocarbons, dissolution of the rock matrix, and migration of minerals. CO2 dissolution of the rock matrix can significantly increase the number and complexity of fractures. Furthermore, CO2 has a higher solubility in formation fluid under high-pressure conditions. Given the higher pressures, CO2 forms a miscible phase with crude oil, diffuses more deeply into the formation, and reacts fully with the reservoir minerals and fluid during CO2 fracturing. Accordingly, CO2 can improve the permeability of the reservoir and flowability of crude oil significantly. Hence, CO2 fracturing can enhance oil recovery and CO2 sequestration more effectively. Core displacement experiments indicate that oil recovery of CO2 soaking process after CO2 fracturing is 36%, which is 12% and 9% higher than those of CO2 huff and puff and CO2 flooding with 5 pore volume, respectively. Field tests show that average oil production after CO2 fracturing is 1.42 times higher than that after CO2 flooding, which further validates the advantage of CO2 fracturing and demonstrates its huge application potential.

CO2 huff and puff experiments of different injection parameters, production parameters and soaking time were carried out on large-scale cubic and long columnar outcrop samples to analyze dynamic characteristics and influencing factors of CO2 huff and puff and the contribution of sweeping mode to recovery. The experimental results show that the development process of CO2 huff and puff can be divided into four stages, namely, CO2 backflow, production of gas with some oil, high-speed oil production, and oil production rate decline stages. The production of gas with some oil stage is dominated by free gas displacement, and the high-speed oil production stage is dominated by dissolved gas displacement. CO2 injection volume and development speed are the major factors affecting the oil recovery. The larger the injected CO2 volume and the lower the development speed, the higher the oil recovery will be. The reasonable CO2 injection volume and development speed should be worked out according to oilfield demand and economic evaluation. There is a reasonable soaking time in CO2 huff and puff. Longer soaking time than the optimum time makes little contribution to oil recovery. In field applications, the stability of bottom hole pressure is important to judge whether the soaking time is sufficient during the huff period. The oil recovery of CO2 huff and puff mainly comes from the contribution of flow sweep and diffusion sweep, and diffusion sweep contributes more to the oil recovery when the soaking time is sufficient.

Fluid mobility has been important topic for unconventional reservoir evaluation. The tight sandstones in Chang 7 Member of the Ordos Basin has been selected to investigate the fluid mobility based on the application of core flooding-NMR combined method and core centrifugation-NMR combined method, and the porous structure is studied using optical microscope, field emission scanning electron microscope (FE-SEM), CT and mercury injection. Our results include: (i) Feldsparrock fragments dissolution pores, calcite dissolution pores, clay mineral dissolution pores, intergranular dissolution expansion pores, inter-granular pores, intra-kaolinite pores, and intra-illite/smectite mixed layer pores are developed in Chang 7 tight sandstones; 3D CT pore structure shows that the pore connectivity is positively related to physical properties, and the overall storage space is connected by the throat with diameter between 0.2 and 0.3 µm. The percentage of storage space connected by throats with diameter less than 100 nm can reach more than 35%. (ii) Movable fluid saturation of Chang 7 tight sandstones is between 10% and 70%, and movable oil saturation is between 10% and 50%. Movable fluid saturation may cause misunderstanding when used to evaluate fluid mobility, so it is recommended to use movable fluid porosity in the evaluation of fluid mobility. The porosity ranging from 5% to 8% is the inflection point of the fluidity and pore structure. For samples with porosity less than 8%, the movable fluid porosity is generally less than 5%. Moreover, the movable fluid is mainly concentrated in the storage space with a throat diameter of 0.1 to 1 µm. For samples with porosity greater than 8%, the porosity of the movable fluid is more than 5%, and the movable fluid is mainly concentrated in the storage space with a throat diameter of 0.2 to 2 µm. (iii) The movable fluid saturation measured by core flooding-NMR combined method is generally higher than that measured by core centrifugation-NMR combined method. The former can evaluate the mobility of the oil-water two-phase fluid in samples, while the latter can better reflect the pore structure and directly evaluate the movable fluid in the pore system controlled by different throat diameters. All these results will provide valuable reference for fluid mobility evaluation in tight reservoirs.

In recent years, production from tight oil reservoirs has increasingly supplemented production from conventional oil resources. Oil-wet formations account for a considerable proportion of tight oil reservoirs. Surfactant can change wettability and reduce interfacial tension, thus resulting in a better oil recovery. In this manuscript, a nonionic surfactant was introduced for tight oil-wet reservoirs. The oil recovery in the oil-wet sandstone due to spontaneous imbibition was 8.59% lower than that of the water-wet sandstone due to surfactant. The 0.1% surfactant solution corresponded to the highest imbibition recovery rate of 27.02% from the oil-wet sample. With the surfactant treatment, the treated core quickly changed from weakly oil-wet to weakly water-wet. The capillary force acted as the driving force and promoted imbibition. The optimal surfactant adsorption quantity in the oil-wet sandstone was observed in the sample at concentrations ranging from 0.1% to 0.3%, which also corresponded to the highest oil recovery. Analysis of the inverse Bond number N B − 1 suggested that the driving force was gravity for brine imbibition in the oil-wet cores and that it was capillary force for surfactant imbibition in the oil-wet cores. When the surfactant concentration was lower than the critical micelle concentration, the surfactant concentration was negatively correlated with the inverse Bond number and positively correlated with the oil recovery rate. When the surfactant concentration was higher than the critical micelle concentration, the oil recovery increased with a smaller interfacial tension. Nuclear magnetic resonance suggested that the movable pore and pore throat size in the oil-wet sample decreased from 0.363 μm in the untreated rock to 0.326 μm with the surfactant treatment, which indicated that the surfactant improved the flow capacity of the oil. The findings of this study can help to better understand the adsorption impact of surfactants on the characteristics of the oil/water and solid/liquid interfaces. The imbibition mechanism in oil-wet tight sandstone reservoirs was further revealed. These systematic approaches help to select appropriate surfactants for better recovery in oil-wet tight sandstone reservoirs through imbibition.

Natural fractures, as the main flow channels and important storage spaces, have significant effects on the migration, distribution, and accumulation of tight oil. According to outcrop, core, formation micro image (FMI), cast-thin-section, and scanning electron microscopy data from the tight reservoir within the Permian Lucaogou Formation of the Junggar Basin, tectonic fractures are prevalent in this formation mainly on micro to large scale. There are two types of fractures worth noticing: diagenetic fractures and overpressure-related fractures, primarily at micro to medium scale. The diagenetic fractures consist of bedding fractures, stylolites, intragranular fractures, grain-boundary fractures, and diagenetic shrinkage fractures. Through FMI interpretation and Monte Carlo method evaluation, the macro-fractures could be considered as migration channels, and the micro-fractures as larger pore throats that function as storage spaces. The bedding fractures formed earlier than all tectonic fractures, while the overpressure-related fractures formed in the Middle and Late Jurassic. The bedding fractures and stylolites function as the primary channels for horizontal migration of tight oil. The tectonic fractures can provide vertical migration channels and reservoir spaces for tight oil, and readjust the tight oil distribution. The overpressure-related fractures are fully filled with calcite, and hence, have little effect on hydrocarbon migration and storage capacity. The data on tight oil production shows that the density and aperture of fractures jointly determine the productivity of a tight reservoir.

SummaryFracturing is the necessary means of tight oil development, and the most common fracturing fluid is slickwater. However, the Loess Plateau of the Ordos Basin in China is seriously short of water resources. Therefore, the tight oil development in this area by hydraulic fracturing is extremely costly and environmentally unfriendly. In this paper, a new method using supercritical carbon dioxide (CO2) (ScCO2) as the prefracturing energized fluid is applied in hydraulic fracturing. This method can give full play to the dual advantages of ScCO2 characteristics and mixed-water fracturing technology while saving water resources at the same time. On the other hand, this method can reduce reservoir damage, change rock microstructure, and significantly increase oil production, which is a development method with broad application potential.In this work, the main mechanism, the system-energy enhancement, and flowback efficiency of ScCO2 as the prefracturing energized fluid were investigated. First, the microscopic mechanism of ScCO2 was studied, and the effects of ScCO2 on pores and rock minerals were analyzed by nuclear-magnetic-resonance (NMR) test, X-ray-diffraction (XRD) analysis, and scanning-electron-microscope (SEM) experiments. Second, the high-pressure chamber-reaction experiment was conducted to study the interaction mechanism between ScCO2 and live oil under formation conditions, and quantitively describe the change of high-pressure physical properties of live oil after ScCO2 injection. Then, the numerical-simulation method was applied to analyze the distribution and existence state of ScCO2, as well as the changes of live-oil density, viscosity, and composition in different stages during the full-cycle fracturing process. Finally, four injection modes of ScCO2-injection core-laboratory experiments were designed to compare the performance of ScCO2 and slickwater in terms of energy enhancement and flowback efficiency, then optimize the optimal CO2-injection mode and the optimal injection amount of CO2 slug.The results show that ScCO2 can dissolve calcite and clay minerals (illite and chlorite) to generate pores with sizes in the range of 0.1 to 10 µm, which is the main reason for the porosity and permeability increases. Besides, the generated secondary clay minerals and dispersion of previously cemented rock particles will block the pores. ScCO2 injection increases the saturation pressure, expansion coefficient, volume coefficient, density, and compressibility of crude oil, which are the main mechanisms of energy increase and oil-production enhancement. After analyzing the four different injection-mode tests, the optimal one is to first inject CO2 and then inject slickwater. The CO2 slug has the optimal value, which is 0.5 pore volume (PV) in this paper.In this paper, the main mechanisms of using ScCO2 as the prefracturing energized fluid are illuminated. Experimental studies have proved the pressure increase, production enhancement, and flowback potential of CO2 prefracturing. The application of this method is of great significance to the protection of water resources and the improvement of the fracturing effect.

Exploring the tightness mechanism through a quantitative analysis of the pore evolution process is the research hotspot of tight oil reservoirs. The physical characteristics of Chang 6 (Ch-6) sandstones in the western Jiyuan area have the typical features of a tight oil reservoir. Based on the reservoir physical property, lithological characteristics, diagenetic types and sequence, and burial and thermal evolution history, this study analyzes the factors leading to reservoir tightness and establishes the model of the pore evolution process. The results show that the sedimentary microfacies type controls the reservoir detrital material and further affects its physical properties. The high content of feldspar and rock fragments and the fine grain size are the material cause for the reservoir tightness. The sandstones of the main underwater distributary channel are the dominant sedimentary bodies for the development of a high-quality reservoir. In terms of diagenesis, compaction is the primary cause for reservoir tightness, and the porosity reduction by cementation is weaker than that by compaction. Meanwhile, the quantitative calculation results indicate that the porosity losses by compaction, carbonate cementation, kaolinite cementation, chlorite coatings, and siliceous cementation are 23.5, 3.1, 3.8, 3.0, and 0.8%, respectively. In addition, dissolution is significant to improve the reservoir physical property, and the increase of dissolved porosity is around 3.2%. More significantly, this study uses a detailed and systematic method for analyzing the tightness mechanism and the pore evolution process of the Ch-6 sandstones in the western Jiyuan area, Ordos Basin, China.

To explore the source and reservoir characteristics of Chang 6 tight oil in the Zhangjiagou area, we have extracted a suite of Chang 6 tight sandstones and the source rocks from the seventh to ninth members of the Upper Cretaceous Yanchang Formation in the Ordos Basin, China, respectively, using chloroform. We examined group components by fractionations of extracted organic matter. Using low-pressure gas adsorptions and gas chromatography-mass spectrometry, respectively, we analyzed the pore structure of the studied samples before and after extraction and the oil source of the separate saturated hydrocarbon components. The results indicate that the porosity of the Chang 6 tight sandstone is mainly distributed in the 8%–14% range, averaging 10.5%, the permeability of the studied reservoir is only approximately 0.16 × 10−3 μm2, and the pore-throat radius is mainly less than 2 μm. The major type of pores of the reservoir includes the residual intergranular pore, secondary intergranular dissolved pore, and intragranular dissolved pore. The micropore volume of the Chang 6 tight sandstone is in the range of 0.0071–0.0092 cm3/g, and the mesopore volume of the Chang 6 tight sandstone is in the range of 0.0237–0.0343 cm3/g. The micropore volume and micropore surface area significantly increased after chloroform extractions, and soluble hydrocarbons could be stored in micropores of the Chang 6 tight sandstone. The three sets of source rocks from the seventh to ninth members of the Upper Cretaceous Yanchang Formation are high quality by the evaluation of source rocks, and the Chang 7 has the highest value of source rocks, followed by Chang 9 and Chang 8. The pentacyclic triterpene characteristics (Ts-C30H-C30*) of Chang 6 crude oil are similar to those of Chang 7 source rock, and the tight oil of the Chang 6 member in the Zhangjiagou area originated from Chang 7 source rocks.

Distributed temperature sensing (DTS) has been used for fracture parameter diagnosis and flow profile monitoring. In this paper, we present a new model for predicting the temperature profile of two-phase flow multistage fractured horizontal wells in the tight oil reservoirs. The homogeneous reservoir flow/heat transfer model is extended to the tight oil reservoir-fracture-wellbore coupled flow/thermal model. The influence of SRV area on reservoir and wellbore is considered, and the Joule-Thomson effect, heat convection, heat conduction, and other parameters are introduced into the improved model. The temperature distributions of reservoir and wellbore with different production times, water cut, and locations of water entry are simulated. The simulated results indicate that the Joule-Thomson effect will cause wellbore temperature to rise; the temperature of fractures with more water production is significantly lower than that of other fractures, and the water outlet location can be judged according to the temperature change of the wellbore. By using the improved temperature prediction model, the DTS monitoring data of two-phase flow multistage fractured horizontal well in the tight reservoir has been calculated and analyzed, and the accurate production profile has been obtained.

High-temperature thermal stimulation (HTS) can effectively remove the damage caused by water phase trapping during the drilling and completion of tight oil and hydraulic fracturing of gas reservoirs. Since HTS induces new rock fracture, the permeability of a reservoir will be increased to a certain extent. However, there are no standardized methodologies for pretreatment, experimental procedures, or evaluation indicators for HTS rock samples. Taking the Longmaxi Formation shale from the Sichuan Basin as the research object, an experimental process for evaluating the impact of HTS on permeability was established. The temperature increased at a rate of 5 °C/min, considering the conditions of dry and water-bearing rock samples. Three variables are included in the evaluation index for HTS of shale reservoirs: threshold temperature, raise multiples of permeability in 4 MPa confining pressure, and in-situ conditions. The results show that the threshold temperature of the dry shale is 650–700 °C, while the water-bearing shale has two threshold temperatures. Furthermore, the low temperature is 100–150 °C, while the high temperature is 450–500 °C. The permeability increase ratio of drying shale samples is 1.5–10.0 after HTS under in-situ effective stress, while that of water-bearing shale samples reach 20–50. This research has shown that using the HTS method to reduce water phase trapping damage and drastically improves well production are being conducted in a shale gas reservoir with horizontal wells and staged hydraulic fracturing. Our recommended experimental methods and evaluation indicators are effective in establishing the HTS potential of a shale reservoir.

After more than 20 years of technological advancements, the novel field of oil and gas production from source rock strata, which comprise tight and shale oil and gas reservoirs, has become the major contributor to the increase in unconventional oil and gas reserves in China. Accordingly, this field has gradually entered a new stage of revolutionary development. The oil and gas production in China from source rock strata will achieve sustainable development in the future. Different types of source rock strata present distinct challenges and require diverse development paths. Based on the geological conditions of source rock strata in China, this study focuses on identifying the “sweet areas” among hydrocarbon accumulations. It specifically analyzes the key development issues of tight oil, tight gas, shale oil, shale gas, and coal-bed methane, while proposing potential solutions and identifying the possible directions for future development. This study aims to provide a reference for scientists concerned with the development of unconventional oil and gas reserves in China. Cited as : Li, J., Yang, Z., Wu, S., Pan, S. Key issues and development direction of petroleum geology research on source rock strata in China. Advances in Geo-Energy Research, 2021, 5(2): 121-126, doi: 10.46690/ager.2021.02.02

The successful development of unconventional hydrocarbons has significantly increased global hydrocarbon resources, promoted the growth of global hydrocarbon production and made a great breakthrough in classical oil and gas geology. The core mechanism of conventional hydrocarbon accumulation is the preservation of hydrocarbons by trap enrichment and buoyancy, while unconventional hydrocarbons are characterized by continuous accumulation and non-buoyancy accumulation. It is revealed that the key of formation mechanism of the unconventional reservoirs is the self-sealing of hydrocarbons driven by intermolecular forces. Based on the behavior of intermolecular forces and the corresponding self-sealing, the formation mechanisms of unconventional oil and gas can be classified into three categories: (1) thick oil and bitumen, which are dominated by large molecular viscous force and condensation force; (2) tight oil and gas, shale oil and gas and coal-bed methane, which are dominated by capillary forces and molecular adsorption; and (3) gas hydrate, which is dominated by intermolecular clathration. This study discusses in detail the characteristics, boundary conditions and geological examples of self-sealing of the five types of unconventional resources, and the basic principles and mathematical characterization of intermolecular forces. This research will deepen the understanding of formation mechanisms of unconventional hydrocarbons, improve the ability to predict and evaluate unconventional oil and gas resources, and promote the development and production techniques and potential production capacity of unconventional oil and gas.

Stimulated Reservoir Volume (SRV) fracturing is a key technology of unconventional oil and gas exploration and development. To gain a deeper understanding of tight sandstone reservoirs and draw on the development experience of hydraulic fracturing, the authors conduct a large number of detailed investigations of geological characteristics in the regions that have implemented SRV fracturing. Based on the data of rock mechanics parameters, in-situ stress characteristics, brittleness characteristics and natural fractures, the influencing factors of SRV fracturing in tight oil reservoirs were analyzed. The results show that the SRV fracturing is suitable for geological reservoirs with the characteristics of medium to high elastic modulus, low to medium Poisson's ratio, low stress difference, medium to high brittleness and naturally fractured reservoirs, where natural fractures have a significant impact. Region A, a tight sandstone region, has moderate elastic modulus, low Poisson's ratio, low ground stress difference and medium brittleness, and has the feasibility of volume fracturing. The field case of the Y325 well shows that SRV fracturing technology has obvious effect on increasing production. This technology is applicable to the Region A.

Lucaogou formation in Jimsar sag is host to large quantities of bedding fractures which are known to play a critical role in the enrichment, accumulation, and efficient development of tight oil. In this paper, we examine and finely characterize the development of the bedding fractures found in the upper and lower sweet spots of Lucaogou formation of tight oil reservoir through field outcrop and core observation, cast thin section analysis, and imaging log recognition and investigate the factors affecting their differentiated oil-bearing by means of inclusion temperature measurement, TOC testing, physical property testing, high-pressure mercury injection, and physical simulation experiment. By comparison with the linear density, bedding fractures are more developed in the lower sweet spot. These fractures occur in parallel to the formation boundary and have small aperture. Most of bedding fractures are unfilled fractures. Among the few types of fractures found there, bedding fractures have the best oil-bearing property, but the oil-bearing can differ from one bedding fracture to another. The factors affecting the differentiated oil-bearing of bedding fractures include the temporal coupling of the formation of these fractures with the hydrocarbon generation of the source rocks and the spatial coupling of the bedding fractures with the source rocks. In terms of temporal coupling, mass hydrocarbon generation in Jimsar sag began in Late Jurassic. Inclusion temperature measurement indicates that the bedding fractures there formed in or after Early Cretaceous. Hence, by matching the mass hydrocarbon generation period of the source rocks with the formation period of the bedding fractures, we discovered that the bedding fractures formed within the mass hydrocarbon generation period, which favored the oil-bearing of these fractures. The spatial coupling is manifested in TOC, porosity, permeability, and pore throat, with TOC being the main controlling factor. For TOC, the higher the formation TOC, the better the oil-bearing property of the bedding fractures. For porosity, subject to the TOC level, if the TOC is adequate, the larger the porosity, the larger the chloroform asphalt “A,” accordingly the higher the oil content of the formation, and the better the oil-bearing property of the bedding fractures developed therein. In this sense, in terms of spatial coupling, TOC constitutes the main controlling factor of the oil-bearing property of bedding fractures.