Tight Oil Development Research Articles

Integrated Simulation for Microseismic Fracture Networks with Automatic History Matching in Tight Oil Development: A Field Case from Block Y2 in Ordos Basin, China

Integrated Simulation for Microseismic Fracture Networks with Automatic History Matching in Tight Oil Development: A Field Case from Block Y2 in Ordos Basin, China

Research on the Temperature Field Distribution Characteristics of Bottomhole PDC Bits during the Efficient Development of Unconventional Oil and Gas in Long Horizontal Wells

Unconventional tight oil and gas resources, including shale oil and gas, have become the main focus for increasing reserves and production. The safe and efficient development of unconventional oil and gas is a crucial demand for the energy development strategy. Deep tight oil and gas resource development generally adopts horizontal well drilling methods. During drilling, especially in long horizontal sections, the high temperature frequently causes failures of downhole drilling tools and rotary steering tools. The temperature rises sharply during rock breaking with the drill bit. Existing wellbore heat transfer models do not fully consider the impact of heat generated by the drill bit on the wellbore temperature field. This paper aims to experimentally study the temperature rise law of the cutting tooth of the bottom polycrystalline diamond compact (PDC) bit during rock breaking. A set of evaluation devices was developed to study the temperature field distribution characteristics at the bottom of the PDC bit during rock breaking under different experimental conditions. The results indicate that the flow rate of drilling fluid, bit rotation speed, and weight on bit (WOB) significantly affect the distribution of the temperature field at the well bottom. This experimental research on the temperature field distribution characteristics at the bottom of the PDC bit during rock breaking helps reveal the heat transfer characteristics of the long horizontal section wellbore, guide the optimization of drilling parameters, and develop temperature control methods. It is of great significance for the advancement of efficient development technologies for unconventional resources in long horizontal wells.

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

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

Research on the Diagenetic Facies Division and Pore Structure Characteristics of the Chang 63 Member in the Huaqing Oilfield, Ordos Basin.

In tight sandstone reservoirs, diagenesis has a significant impact on the development of reservoirs and pore structures. To clarify the effect of diagenesis on the pore structure of tight sandstone, 12 samples of the Yanchang Formation in the basin were studied based on experiments such as high-pressure mercury intrusion and low-temperature nitrogen adsorption. The diagenetic facies in the study area are divided into two categories: strong cementation facies of carbonate minerals and strong compaction facies of soft component minerals, which are relatively unfavorable diagenetic facies, and stable facies of felsic minerals and strong dissolution facies of feldspar minerals, which are dominant diagenetic facies. The pore structure of the Chang 63 reservoir in the study area has obvious fractal characteristics, with a fractal dimension D 1 greater than D 2 and a greater heterogeneity of large pore throats. Compared to compaction and cementation, dissolution has a stronger controlling effect on the pore structure of reservoirs. In tight sandstone reservoirs with low porosity and permeability, dissolution has a more important impact on reservoir transformation and development. The intensity of different types of diagenesis in the Chang 63 reservoir affects reservoir heterogeneity, and the level of the reservoir heterogeneity affects the complexity of reservoir pore structure. In tight sandstone reservoirs, cementation has a stronger controlling effect on the structural complexity of large pores, while dissolution has a stronger controlling effect on the structural complexity of small pores. The dissolution has a strong control effect on the physical properties of the reservoir. This study provides insights into the relationships among the diagenetic facies, reservoir quality, and pore structure of tight sandstone reservoirs. This study has reference significance for the exploration and development of tight oil in the research area.

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

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

Pore throat distributions and movable fluid occurrences in different diagenetic facies of tight sandstone reservoirs in the Triassic Chang 6 reservoirs, Wuqi Area, Ordos Basin, China

The 6th member of the Triassic Yanchang Formation, hereafter referred to as Chang 6 reservoir, in the Wuqi area of the Ordos Basin presents formidable obstacles for efficient tight oil development. This reservoir is known for its tight lithology, strong heterogeneity, inadequate oil saturation, and abnormally low reservoir pressure, which collectively contribute to the highly differentiated mobility of tight oil within the formation. To overcome these challenges, a comprehensive understanding of the factors influencing oil mobility is essential. This study investigates the occurrence characteristics of movable fluids in different diagenetic facies and the corresponding influential factors by employing various microscopic experiments, including high-pressure mercury intrusion, constant-rate mercury intrusion, nuclear magnetic resonance test, scanning electron microscopy, pore-casted thin section analysis, and X-ray diffraction measurement. There is a weaker correlation between the pore-throat radius ratio and the movable fluid saturation in reservoirs of various diagenetic facies (R2 = 0.6104), whereas there is a stronger correlation between movable fluid saturation and throat radius (R2 = 0.9415). Among the seven types of diagenetic facies, chlorite membrane cementation-intergranular pore facies (Facies I) and chlorite and illite membrane cementation-intergranular pore facies (Facies II) have the best-developed throats and the highest coordination number. Illite cementation-intergranular pore facies (Facies III) and illite and chlorite membrane cementation-dissolution facies (Facies IV) demonstrate smaller pore-throat radii and moderate to poor reservoir connectivity. The other three facies, namely illite cementation-dissolution facies (Facies V), illite cementation facies (Facies VI), and carbonate tight cementation facies (Facies VII) exhibit underdeveloped pore structures and lower recovery rates. Pore-throat radius emerges as the principal factor influencing reservoir permeability and storage capacity. The distribution of favorable diagenetic facies is influenced by depositional environments, diagenetic processes, and microscopic pore-throat characteristics. This study significantly enhances our understanding of the differential occurrence characteristics of fluids in different diagenetic facies in the Chang 6 reservoir, providing valuable insights for future exploration and production endeavors aimed at optimizing oil recovery in tight sandstone reservoirs.

Geological characteristics and major factors controlling the high yield of tight oil in the Da’anzhai member of the western Gongshanmiao in the central Sichuan basin, China

The Da’anzhai Member limestone in the central Sichuan Basin holds significant importance as a tight oil-producing formation. Despite its crucial role, the intricate patterns of hydrocarbon enrichment and the elusive geological factors dictating high-yield production have impeded tight oil exploration and development in the Sichuan Basin. This study delves into the geological characteristics of tight oil and identifies key factors influencing high-yield production, utilizing comprehensive data derived from cores, thin sections, well logging, seismic studies, and production tests of the Da’anzhai Member in the western Gongshanmiao within the central Sichuan Basin. Our findings reveal that the primary productive strata for tight oil are the Da 1 (1st Submember of the Da’anzhai Member) and Da 3 (3rd Submember of the Da’anzhai Member) Submembers, characterized by high-energy and low-energy shell beach microfacies. The kerogen type is sapropelic, ranging from mature to highly mature, positioning it as a moderately good hydrocarbon source rock. The predominant lithology of the reservoir consists of coquina and argillaceous coquina, with secondary dissolved pores, fractures, and nano-scale micropores serving as the predominant reservoir spaces. The overall lithology represents a dense limestone reservoir of the pore-fracture type, featuring low porosity and permeability. Critical controlling factors for achieving high-yield production of tight oil encompass lithological composition, fracture development, tectonic position, and source-reservoir configuration. Notably, substantial coquina thickness, fracture development, and the strategic relationship between the lower reservoir and upper source rocks contribute significantly to unlocking high tight oil yields. Additionally, thin-layer coquina emerges as a potential area for realizing increased oil and gas production capacity during later stages of development. This comprehensive analysis sheds light on the intricate dynamics governing tight oil production in the Da’anzhai Member, offering valuable insights for advancing exploration and development strategies in the Sichuan Basin.

Prediction of ORF for Optimized CO2 Flooding in Fractured Tight Oil Reservoirs via Machine Learning

Tight reservoirs characterized by complex physical properties pose significant challenges for extraction. CO2 flooding, as an EOR technique, offers both economic and environmental advantages. Accurate prediction of recovery rate plays a crucial role in the development of tight oil and gas reservoirs. But the recovery rate is influenced by a complex array of factors. Traditional methods are time-consuming and costly and cannot predict the recovery rate quickly and accurately, necessitating advanced multi-factor analysis-based prediction models. This study uses machine learning models to rapidly predict the recovery of CO2 flooding for tight oil reservoir development, establishes a numerical model for CO2 flooding for low-permeability tight reservoir development based on actual blocks, studies the effects of reservoir parameters, horizontal well parameters, and injection-production parameters on CO2 flooding recovery rate, and constructs a prediction model based on machine learning for the recovery. Using simulated datasets, three models, random forest (RF), extreme gradient boosting (XGBoost), and light gradient boosting machine (LightGBM), were trained and tested for accuracy evaluation. Different levels of noise were added to the dataset and denoised, and the effects of data noise and denoising techniques on oil recovery factor prediction were studied. The results showed that the LightGBM model was superior to other models, with R2 values of 0.995, 0.961, 0.921, and 0.877 for predicting EOR for the original dataset, 5% noise dataset, 10% noise dataset, and 15% noise dataset, respectively. Finally, based on the optimized model, the key control factors for CO2 flooding for tight oil reservoirs to enhance oil recovery were analyzed. The novelty of this study is the development of a machine-learning-based method that can provide accurate and cost-effective ORF predictions for CO2 flooding for tight oil reservoir development, optimize the development process in a timely manner, significantly reduce the required costs, and make it a more feasible carbon utilization and EOR strategy.

A technique for enhancing tight oil recovery by multi-field reconstruction and combined displacement and imbibition

A seepage-geomechanical coupled embedded fracture flow model has been established for multi-field coupled simulation in tight oil reservoirs, revealing the patterns of change in pressure field, seepage field, and stress field after long-term water injection in tight oil reservoirs. Based on this, a technique for enhanced oil recovery (EOR) combining multi-field reconstruction and combination of displacement and imbibition in tight oil reservoirs has been proposed. The study shows that after long-term water flooding for tight oil development, the pressure diffusion range is limited, making it difficult to establish an effective displacement system. The variation in geostress exhibits diversity, with the change in horizontal minimum principal stress being greater than that in horizontal maximum principal stress, and the variation around the injection wells being more significant than that around the production wells. The deflection of geostress direction around injection wells is also large. The technology for EOR through multi-field reconstruction and combination of displacement and imbibition employs water injection wells converted to production and large-scale fracturing techniques to restructure the artificial fracture network system. Through a full lifecycle energy replenishment method of pre-fracturing energy supplementation, energy increase during fracturing, well soaking for energy storage, and combination of displacement and imbibition, it effectively addresses the issue of easy channeling of the injection medium and difficult energy replenishment after large-scale fracturing. By intensifying the imbibition effect through the coordination of multiple wells, it reconstructs the combined system of displacement and imbibition under a complex fracture network, transitioning from avoiding fractures to utilizing them, thereby improving microscopic sweep and oil displacement efficiencies. Field application in Block Yuan 284 of the Huaqing Oilfield in the Ordos Basin has demonstrated that this technology increases the recovery factor by 12 percentage points, enabling large scale and efficient development of tight oil.

Comprehensive Study on Microscopic Pore Structure and Displacement Mechanism of Tight Sandstone Reservoirs: A Case Study of the Chang 3 Member in the Weibei Oilfield, Ordos Basin, China

With the continuous growth in global energy demand, research and development of unconventional oil and gas reservoirs have become crucial in the field of energy. This study focuses on the Chang 3 reservoir of the Yanchang Formation in the Ordos Basin, Weibei Oilfield, China. This reservoir is a typical tight sandstone reservoir, and its microscopic pore structure and displacement mechanism are essential for the efficient development of tight oil. However, the reservoir faces challenges such as complex microscopic pore structures and unclear displacement mechanisms, which hinder the efficient development of tight oil. In light of these challenges, through various studies including core observation, high-pressure mercury injection tests, water flooding experiments, oil-water two-phase relative permeability measurements, and stress sensitivity experiments, it was found that the Chang 3 reservoir exhibits strong microscopic heterogeneity. The pore-throat distribution characteristics mainly present two types: single peak and double peak, with the double peak type being predominant. The reservoir was classified and evaluated based on these characteristics. The improved injection ratio and properties enhance oil displacement efficiency, but an increase in irreducible water saturation has a negative impact on efficiency. The stress sensitivity of the reservoir fluctuates between weak and strong, with permeability being sensitive to net confining pressure. It is recommended to pay particular attention to the stress-sensitivity characteristics during reservoir development. The research results provide a scientific basis for the optimized development of tight oil reservoirs in this region, promote the sustainable development of unconventional oil and gas resources, and have significant theoretical and practical implications.

Scenario analysis to evaluate the economic benefits of tight oil resource development in China

Evaluating the economic benefits of tight oil resources is necessary for China to increase its tight oil production and reserves. This study systematically analyzes the uncertainties in tight oil development in China, the factors affecting the tight oil economy, and the coevolution of the economic development of tight oil resources from the technology and market perspectives. The results indicate that a positive market environment and technological progress are important for realizing the economic development of tight oil. Four potential scenarios for the development of tight oil resources in China are also identified (i.e., the current scenario, limited scenario, efficient development scenario, and inefficient development scenario), each associated with different internal rates of return (8 %, 14 %, 20 %, and 6 %, respectively).

The flooding mechanism and oil recovery of nanoemulsion on the fractured/non-fractured tight sandstone based on online LF-NMR experiments

Hydraulic fracturing and water/nanoemulsion flooding technology are effective stimulation measures for tight oil production. The complex pore structure of ultra-low permeability sandstone greatly affects oil recovery. At present, scholars have done a lot of research on the characteristics of oil-water flow in micro-nano pores of ultra-low permeability sandstone reservoirs. However, few scholars have comprehensively studied the whole process of ultra-low permeability sandstone reservoirs from hydraulic fracturing to enhanced oil recovery. In this paper, the whole process from fracturing to production of ultra-low permeability sandstone reservoirs is comprehensively studied at the laboratory scale by combining triaxial fracturing, CT scanning, online LF-NMR and other technologies, aiming to promote the understanding of tight oil development. The results show that the high confining pressure (45 MPa) inhibits the propagation of fractures in the rock samples more than the low confining pressure (15 MPa) during the triaxial fracturing process. The oil recovery of the rock sample with high fracture volume (1213.42 mm3) is 16.32 % higher than that of the rock sample with low fracture volume (674.22 mm3). Whether it is fractured rock or non-fractured rock, nanoemulsion can further improve the oil recovery of micropores on the basis of water flooding, with a maximum increase of 28.21 %. The oil recovery of the nanoemulsion with a concentration of 0.3 wt% was 25.34 % higher than that of the nanoemulsion with a concentration of 0.05 wt%. Confining pressure conditions have an important impact on oil recovery. The oil recovery of non-fractured rock samples with initial confining pressure of 5 MPa is 8.15 % lower than that of non-fractured rock samples with initial confining pressure of 30 MPa. At the same time, we propose a new T1-T2 map region division scheme based on sandstone to better characterize oil displacement behavior at the pore scale. The research results can guide the exploitation of ultra-low permeability sandstone reservoirs.

Tectonic movements of the Yanshan-Himalayan period in the northern Longmenshan and their impact on tight gas accumulation of the Shaximiao formation in the Qiulin structure, China

The Jurassic strata constitute a focal area for recent exploration and development of tight gas reservoirs in the western Sichuan Basin. This study investigates the Jurassic Shaximiao Formation in the northern Longmenshan in the Western Sichuan basin, focusing on tight gas reservoirs. The research integrates core and outcrop observations, seismic interpretations, and burial history analyses to understand hydrocarbon source rocks, sedimentation, reservoir characteristics, and structural characteristics. The impact of Yanshan-Himalayan tectonic movements on tight gas reservoir accumulation in the Shaximiao Formation is dissected, primarily around the Qiulin structure. The Western Sichuan Depression basin’s formation is influenced by gravitational gliding tectonics, which can be classified into the ‘Three Zones and One Belt,’ with Longmenshan in the frontal belt. Burial history analysis reveals distinct processes in the foreland belt and the depression basin. In the Qiulin area, gas reservoirs in the Shaximiao Formation are mainly charged by source rocks from the Xujiahe Formation. Tectonic movements play a significant role in creating favorable reservoirs and conditions for hydrocarbon migration and preservation. Natural gas accumulation is primarily controlled by fault connectivity to hydrocarbon sources and effective reservoir thickness. Gravitational sliding tectonics have shaped a fluvial-lacustrine environment for the Shaximiao Formation, with fluvial sand bodies acting as favorable reservoir zones. Small-scale normal faults formed by tectonic movements serve as conduits for natural gas migration. The research findings are of significant guidance for the exploration and development of tight oil and gas resources in western Sichuan basin.

Progress and Suggestions for Fracturing Technologies of Tight Oil in Daqing Oilfield

Daqing oilfield is rich in tight oil reserves, and it’s a realistic field for increasing the efficiency of Daqing oilfield. After 11 years of technical exploration and practice, based on the idea of integration of geological engineering, Daqing oilfield has formed two technical series, which are volumetric fracturing with tight spacing in horizontal well and network fracturing in vertical well, and realizes three-dimensional reservoir transformation. However, with the exploration and development, the reservoir physical properties gradually deteriorate, and there are some problems such as unclear stimulation mechanism and difficult production improvement in fracturing stimulation. Therefore, based on the introduction of the progress of tight oil fracturing technology in Daqing oilfield, the challenges faced by tight oil fracturing in Daqing oilfield are analyzed. According to the geological characteristics of tight oil reservoir in Daqing oilfield, three concepts are proposed, which respectively are horizontal well fracturing changing from further close cutting to uniform fracture initiation and balanced distribution of sand fluid,vertical well fracturing changing from large displacement, large seam fracturing to moderate displacement, moderate scale multi-branch seam fracturing, fracturing concept changing from “trading initial production for benefit” to “cumulative production for benefits”. And it puts forward 5 relevant technical research directions. It has certain guiding significance for assisting the efficient development of tight oil in Daqing oilfield.

Fractured Zone Detection Using Petrophysical Logs by Rescaled Windowed R/S Analyses and Discrete Fracture Network (DFN) of Yanchang Formation in Mahuangshan-Hongliugou Area, Ordos Basin, China

Structural fractures generally develop in the upper crust strata and are usually distributed in a convergent pattern, forming structural fracture zones with a specific strike. Fracture zones control the reservoir seepage system and seriously affect the migration and accumulation of oil and gas in tight sandstone reservoirs. Therefore, characterizing the characteristics of the fracture zones for tight oil exploration and development effectively is essential. In this paper, the variable scale fractal method is introduced to calculate the petrophysical log, and a new curve H is built. An intensity log is to characterize the intensity of structural fracture development. The H curve is in a good linear relationship with the intensity curve after the comparison of the H curve and intensity curve in 32 wells. A quantitative relationship between H and the intensity curve is established. Based on the parameters obtained from the core and image logs, the discrete fracture network model was established using H curves from more than 300 wells, and the structural fracture zone was analyzed. The model shows that the fracture zones formed by structural fractures are in S-N and NW-SE directions in the study area. The orientation of the structural fracture zone is consistent with that of the fractured fault zone and fault, and the development of the fractured zone is consistent with the regional tectonic evolution characteristics. The characteristics of the fracture zone explain the distribution law of oil accumulation and groundwater salinity in the study area.

Characteristics of Hydrocarbon-Generating Pressurization in Shale Series of Fengcheng Formation in the West and South of Mahu Sag, the Junggar Basin, China

Formation overpressure is an important controlling factor for the formation of high-yield oil reservoirs in the shale series of the Permian Fengcheng Formation in the west and south of Mahu Sag, the Junggar Basin. Hydrocarbon-generating pressurization (HGP) is an important cause of overpressure in the shale series of Fengcheng Formation, but the evidence for this viewpoint is insufficient. There is still no systematic study on the quantitative calculation and distribution characteristics of HGP in the Fengcheng Formation shale series. The control effect of HGP on the formation of high-pressure and high-yield reservoirs is still unclear. Therefore, by using the data of mudstone logging and measured formation pressure, the causes of overpressure in the Fengcheng Formation shale series are clarified. The predicted organic matter abundance, the predicted maturity and thickness of source rocks, and the statistical ratios of mudstone thickness to formation thickness in each section of Fengcheng Formation are used for HGP of shale series. Combined with the physical characteristics of reservoir rocks and the geochemical characteristics of oil, the control effect of HGP on the formation of high-pressure and high-yield reservoirs is analyzed. The results indicate the following: (1) The organic matter abundance and the thickness of source rocks predicted by the logging data gradually decrease from the eastern lake basin area to the western slope area. (2) The HGP of shale series in Fengcheng Formation is related to the hydrocarbon generation capacity and the overpressure preservation conditions of the source rocks. The HGP can be quantitatively predicted by comprehensively using the organic matter abundance, the maturity, the thickness of source rocks, and the ratios of mudstone thickness to formation thickness. (3) The HGP in the Fengcheng Formation shale series also gradually decreases in distribution characteristic from the eastern lake basin area to the western slope area. (4) The oil accumulation mode of the Fengcheng Formation shale series is that, with the drive of overpressure, the oil migrates slightly within the layer, and finally accumulates to form the oil reservoir. The research results are helpful to understand the distribution characteristics of HGP and the formation mechanism of high-pressure and high-yield reservoirs in the shale series of Fengcheng Formation in the west and south of Mahu Sag, and are of great significance to guide the exploration and development of shale oil and tight oil.

Mathematical Model of Imbibition Replacement and Optimization of Soaking Time for Massively Fractured Tight Oil Reservoirs.

Due to the small pore throat characteristics of tight oil reservoirs, their strong capillary pressure makes imbibition replacement an effective development method. Field data has indicated that only a little fracture fluid can flow back and that there is an enhancement in oil recovery with shut-in periods after volume fracturing. A large number of scholars have carried out core-scale experiments on imbibition characteristics, but there has been limited research on the quantitative characterization of the differential pressure and imbibition replacement during counter-current imbibition. At the same time, there was also controversy on the calculation method of the optimal soaking time. In this paper, a mathematical model of oil-water two-phase flow is first established. Then, a mathematical model representing differential pressure and imbibition replacement in tight reservoirs is derived with a diversion function. Based on the saturation equation, Corey relative-permeability curve, and J function, the model is simplified to a mathematical model of spontaneous imbibition in the shut-in periods after volume fracturing. Second, based on the finite difference method, a dynamic solution method for the flow field considering the dynamic capillary force was established, and the variation law of the pressure field and the water saturation field during the soaking time was revealed. The simulation results show that imbibition characteristics are the core of flow field reconstruction, and the differential pressure action can ensure the advancing distance of the fracturing fluid; both of them are not a linear superposition on tight oil development but complement each other and promote each other. Third, according to the growth rate of the imbibition replacement between fractures and the matrix during the soaking time, the calculation method of optimal soaking time was established. Taking the development parameters of the volume fracturing development case in the Ordos Basin into account, a reasonable soaking time was optimized. Finally, we analyzed the optimal soaking time under different conditions, and a chart of optimal soaking time for different initializations was plotted. Such a chart has profound reference significance for engineers, and they can make quick and accurate decisions regarding development and adjustment.

Numerical Simulation Study of Pressure Transfer Based on the Integration of Fracturing, Shut-in and Production in Tight Reservoirs

As an important replacement resource for conventional oil and gas, tight oil and gas are quite abundant. Long horizontal wells and multi-stage fracturing have become key technologies for developing tight oil and gas, and reasonable shut-in measures can improve the utilization efficiency of fracturing fluid. Therefore, it is especially critical to master the pressure transfer law during the shut-in process in tight reservoirs to further improve the energy efficiency of fracturing fluid. However, many studies have mostly focused on the separate design of fracturing, shut-in and production, and have not yet revealed the pressure transfer law during shutting in well based on the integration of fracturing, shut-in and production, which makes it difficult to realize the efficient development of tight oil and gas. Taking the tight oil reservoir in Block M as an example, the geological model of the target block was established using an integrated fracturing development software platform, on which the simulation of fracture extension, well shut-in and production was carried out. The changes in the reservoir pressure field during shutting in well were analyzed, and the influence law of fracturing fluid volume, shut-in time, reservoir original formation pressure and fracture network complexity on the effect of well shut-in were studied to optimize the shut-in system. It was found that the retained fluid increases, the pore pressure of the near-fracture matrix increases, and the diffusion distance of fracturing fluid to the distant matrix increases. The tight oil production increased after shutting in well, and the optimal retained fluid volume of 9600 m3 was actually preferred based on the model. The pore pressure of the near-fracture matrix decreases as the shut-in time increases, the diffusion distance of fracturing fluid to the distant matrix increases, and the pore pressure decreases with an increase in diffusion distance. The tight oil production increased after shutting in well, and the optimal shut-in time was actually preferred to be 90 days based on the model. The increase in formation pressure on abnormal low pressure formation is larger, and the production can be significantly improved after shutting in well. The more complex the fracture network is, the more obvious the non-uniform variation in matrix pore pressure during shutting in well. The research is of great significance for the optimal design of a shut-in system for tight reservoirs and the sustainable development of oil and gas resources in China.

Evaluation of the Geological Characteristics and Exploration Potential of Tight Oil in the Neogene Upper Ganchaigou Formation in the Zhahaquan Area, Qaidam Basin.

The study of the geochemical characteristics of source rocks is an important part of tight oil evaluation. The Zhahaquan area of the Qaidam Basin is a new area for tight oil exploration in China. During the sedimentary period of the Neogene Upper Ganchaigou Formation (N1) in the Zhahaquan area, a set of source rocks of semideep lake and deep lacustrine facies as well as a set of thin, interbedded fine sandstone and argillaceous limestone was deposited, providing favorable conditions for the formation of tight oil. However, the study on the geochemical characteristics of source rocks in this area is relatively weak. The geochemical characteristics of the source rocks in the Zhahaquan area were determined via the experimental analysis of parameters such as vitrinite reflectance (Ro), chloroform bitumen "A", total organic carbon (TOC), group components, kerogen types, rock pyrolysis, and aromatic compounds of crude oil. The following results were obtained: the Zhahaquan area had II1-type hydrocarbon source rock organic matter, and the TOC was 0.32%-1.32%. The type index (TI) was 48.70-72.23, the chloroform bitumen "A" content was 0.0034%-0.1133%, Ro was 0.810%-1.265%, and the cracking hydrocarbon peak temperature (Tmax) was distributed in the temperature range of 362-444 °C. The hydrocarbon generation conversion rate was 0.89%-10.0%. The reservoir mainly had intergranular pores, dissolution pores, and microfractures. The average porosity was 8.0%, and the average permeability was 0.861 × 10-3 μm2. The average oil saturation was 30.0%, and the average water saturation was 21.6%. From a comprehensive analysis of the results, the following inferences were derived. The parent material of the source rocks in the Zhahaquan area mainly originated from algae and other phytoplankton in the lake basin, which was a good source rock for oil exploration. The source rocks of this area have entered the threshold of hydrocarbon generation and are in the peak oil-generation stage. They have potential as industrial oil and gas resources. The oil test results of YD103 and seven other wells showed that the daily oil index per meter ranges from 0.38 to 6.5 m3/d·m, indicating that the source rocks have the ability to form industrial oil. Analysis of the geochemical characteristics of source rocks and study of reservoir geological characteristics will provide theoretical support and reference for tight oil exploration and development in Zhahaquan.

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

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