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This study presents an in-depth analysis of a refractured tight oil well, focusing on both the initial and subsequent refracturing operations. After refracturing, daily oil production surged from 0.8 to 15.0 tons. The well sustained natural flow for 100 days before transitioning to pump-assisted production, resulting in an additional cumulative oil production of 1412 tons. Leveraging distributed temperature sensing (DTS), high-resolution temperature monitoring was performed, revealing key insights into the behavior of both newly created and existing fractures. Older perforation stages outperformed newer ones, with average daily oil production of 4.66 m3 for older stages and 3.49 m3 for newer stages under a 2 mm choke size. Moreover, CO2 pre-fracturing significantly enhanced oil production, with the stages receiving CO2 injection achieving a median daily oil output of 4.04 m3, compared to 3.55 m3 for non-CO2 stages. These results demonstrate the effectiveness of integrating advanced monitoring techniques and innovative fracturing methods to optimize refracturing strategies, ultimately enhancing hydrocarbon recovery in tight oil reservoirs. [ABSTRACT FROM AUTHOR]

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The article analyzes resilience factors of tight oil and gas production in the USA. The US is the only country in the world that currently produces shale hydrocarbons on a commercial scale, though other petroleum states try to emulate their success in this sphere. The American shale revolution became possible due to a massive application of hydrofracking in combination with horizontal drilling to produce tight oil and gas. Therefore, the mighty technological potential of the American petroleum sector became the key success factor of the US shale revolution. However, technological breakthroughs are necessary, but not sufficient for ensuring a stable development of the shale industry. Of particular importance is the institutional framework of the US shale sector that is characterized by an efficient system of subsurface use, a powerful financial and industrial base, a long-term strategy of the state support for R&D, a reasonable fiscal policy, a transparent regulation, as well as a competitive and diversified structure of the shale sector. This unique combination of factors will be extremely difficult to replicate in other countries. When constructing long-term scenarios of oil and gas production, the US Energy Information Administration proceeds from the key assumptions of resource availability and rates of improving production technologies. The analysis of the shale phenomenon permits to conclude that these two factors are interconnected – the continuous technological progress of the sector ensures the enhanced oil and gas recovery ratio. As a result, the production growth is accompanied by the growth of resource availability. The limits to this trend are not visible yet, and, therefore, it means that the upside potential of shale production is not exhausted.

Fine characterization of oil plane distribution in highly heterogeneous tight sandstone is a prerequisite for efficient reservoir development. This study systematically evaluated the distribution characteristics of tight oil in the Chang 7 Member of the Western Ordos Basin using a large number of experimental tests, logging interpretation, and 3D modelling methods. The logging interpretation models of shale content, porosity, permeability, and oil saturation were constructed, and the effective reservoir was identified by establishing the intersection identification pattern of reservoir acoustic wave time difference and deep lateral resistivity. The 3D numerical simulation results showed that the tight oil is distributed between injection and production wells. The areas with high tight oil content are mainly distributed along the WE direction, and a series of high remaining oil zones are formed locally. Under the influence of long-term injection and production, a high permeability zone will be formed between wells, which is similar to a high-speed channel and will be flooded quickly, and a banded remaining oil retention zone will be formed around it. For the horizontal well flooding area, the water flooding range of the water injection well is small, and a large amount of remaining oil is enriched between water injection wells. Finally, the classification standard of the remaining oil in the Chang 72 sub-member of the study area is proposed, and then, the strategy of adopting different development and adjustment schemes according to different types of reservoirs is formed.

To elucidate the development patterns and influencing factors of natural fractures in deep-buried tight oil reservoirs, a comprehensive evaluation was conducted using a large amount of core samples, thin section, physical property data, imaging and conventional logging, water injection pressure testing and other data. The focus was on the tight oil reservoirs within the Ⅱ-Ⅵ oil layers of the third member of the Paleogene Hetaoyuan Formation in the southeastern An'peng area of the Biyang Depression, Nanxiang Basin. These oil formations, deposited in fan-delta front environment, are characterized by a high content of rock debris, indicating proximal deposition. A strong positive correlation between reservoir porosity and permeability was observed. Among the various sandstone lithologies, fractures predominantly developed in fine sandstone, followed by siltstone, while gravelly sandstone generally lacked fractures. High-angle and vertical fractures were predominant, constituting 87.8% of the total, while low-angle oblique and horizontal fractures accounted for 7.3% and 4.9%, respectively. The main controlling factors for fracture development in these tight reservoirs included lithology, depositional microfacies, and local structures. Thin and fine-grained single or composite sand bodies typically had more deve-loped fractures, particularly in front channel, channel flank, mouth bar, and outer edge of distal bars. Conversely, fractures were less developed in sheet sands or delta front microfacies. Moreover, fractures primarily formed at structural inflection points, predominantly at the tops and wings of forward structures and were primarily oriented along the WE and NE directions, followed by the NW direction. These fractures predominantly formed during the Neogene depression period (late Himalayan). Fractures significantly influence water channeling in tight oil reservoirs, necessitating enhanced dynamic and static monitoring of the degree, extent, and orientation of fracture development.

Abstract Fluid movability in tight sands may not be accurately characterized by pore size-based classification methods solely because of the complex pore structure and heterogeneity in pore size. In this study, on the basis of casting thin slices and scanning electron microscope observation, pore structure was analyzed using mercury injection, NMR, and micron CT to classify and evaluate the tight oil reservoir. The experiment suggest that the quality of tight reservoir is determined by its pore structure, particularly the throat radius, with the microthroat being an essential factor in permeability. Uniquely, we divide the reservoir by Q-cluster with throat radius, displacement pressure, permeability and other parameters. Based on reservoir classification, this study proposed a method for studying the pore size classification of samples on the T2 spectrum by combining CT scanning with mercury intrusion and a NMR experiment. Pore fluids are generally classified into movable fluid and irreducible fluid by one or two NMR T2 cut-offs. The pore size distributions and capillarity boundaries are converted from T2 and mercury injection capillary pressure (MICP). We categorized pores into micropores (T2 10, with T2 > 300 as fractures), and medium pores (the rest). The saturation of movable fluid and the percentage of micro-fractures can characterize the seepage characteristics of tight reservoirs, which is of great significance for the later periods of oilfield development.

The latest researches reveal that studies on unconventional clastic oil reservoirs in China generally lag far behind those in other countries in respect of content and methodology. This study presents the definition and classification of unconventional oil reservoirs and analyzes the problems in the fine description of unconventional oil reservoirs. The key content of the fine description of unconventional oil reservoirs is summarized from four aspects: fine fracture characterization based on fine structure interpretation, reservoir architecture characterization based on sedimentary facies, characteristics of nanoscale microscopic pore structure of reservoir, and evaluation of source rock and “sweet spot zone”. Finally, this study suggests that development of fine description of unconventional clastic oil reservoirs in the future should focus on rock brittleness analysis and fracture modeling, geophysical characterization of unconventional clastic oil reservoirs, fluid description of tight reservoirs, and physical/numerical simulation experiments of unconventional oil reservoirs.

Despite the abundance of shale-oil and tight-oil reserves in the Fengcheng Formation within the Mahu Sag, exploration and development efforts for both types of reservoir are still in their early stages. A comprehensive examination and comparison of the pore structures of these reservoirs can establish rational classification and evaluation criteria. However, there is a dearth of comparative analyses focusing on the pore structures of shale-oil and tight-oil reservoirs within the Fengcheng Formation. This study addresses this gap by systematically analyzing and comparing the pore structures of these reservoirs using various techniques such as X-ray diffraction (XRD), scanning electron microscopy (SEM), low-temperature nitrogen adsorption, and mercury intrusion capillary pressure experiments (MICP). The results show that the shale oil within the Fengcheng Formation exhibits a higher content of carbonic acid compared to the tight-oil samples. Furthermore, it demonstrates smaller displacement pressure and median pressure, a larger sorting coefficient, and superior permeability in contrast to tight oil. Notably, the shale oil within the Fengcheng Formation is characterized by abundant striated layer structures and micro-fractures, which significantly contribute to the microstructural disparities between shale-oil and tight-oil reservoirs. These differences in microstructures between shale oil and tight oil within the Fengcheng Formation in the Mahu Sag region delineate distinct criteria for evaluating sweet spots in shale-oil and tight-oil reservoirs. [ABSTRACT FROM AUTHOR]

The Chang 6 sandstone reservoir of the Upper Triassic Yanchang Formation in the Ordos Basin is one of the tight-oil-rich intervals in the basin. Owing to the strong heterogeneity and complex lithology of the Chang 6 reservoir, lithology and fluid identification have become more challenging, hindering exploration and development. This study focused on the Chang 6 member in the Qingcheng area of the Ordos Basin to systematically analyze the lithology, physical properties, and oil-bearing properties of the Chang 6 reservoir. We adopted the method of normalized superposition of neutron and acoustic time-difference curves, the method of induced conductivity–porosity–density intersection analysis, the method of superposition of difference curves (Δφ), and the induced conductivity curve. Our results indicated that the method of normalized superposition of neutron and acoustic wave time-difference curves could quickly and effectively identify the lithologies of tight fine sandstone, silty mudstone, mudstone, and carbonaceous mudstone. The induced conductivity–porosity–density cross-plot could be used to effectively identify oil and water layers, wherein the conductivity of tight oil layers ranged from 18 to 28.1 mS/m, the density ranged from 2.42 to 2.56 g/cm3, the porosity was more than 9.5%, and the oil saturation was more than 65%. Based on the identification of tight fine sandstone using the dual-curve normalized superposition method, the oil layer thickness within the tight fine sandstone could be effectively identified using the superposition of difference curves (Δφ) and induced conductivity curves. Verified by oil-bearing reservoir data from the field test, the overall recognition accuracy of the plots exceeded 90%, effectively enabling the identification of reservoir lithology and fluid types and the determination of the actual thickness of oil layers. Our results provide a reference for predicting favorable areas in the study area and other tight reservoirs. [ABSTRACT FROM AUTHOR]

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Copyright of Petroleum Geology & Experiment is the property of Petroleum Geology & Experiment Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Based on the data of rock coring, thin sections, physical properties and organic texture, the source reservoir characteristics and hydrocarbon generation potential of the Permian Lucaogou Formation migmatite in Malang sag, Santanghu Basin were analyzed by means of microscopic observation, rock pyrolysis analysis and geochemical parameter intersection, and the reservoir forming conditions were discussed. The results show that the reservoir lithology of Lucaogou Formation is divided into mudstone, argillaceous limestone, argillaceous dolomite and tuff. The reservoir space is mainly intergranular pore intergranular pore, intergranular pore, volcanic ash devitrification pore, felsic dissolution pore and dissolution fracture, and the physical properties are low porosity and ultra-low permeability. The dominant lithology of the source rock is dolomitic mudstone and mudstone, with an average total organic carbon (TOC) of 4.41% . The organic matter types are mainly type Ⅰ and type Ⅱ2, and the maturity is mainly low maturity maturity. The source rock is characterized by high organic matter abundance, good organic matter type and hydrocarbon generation evolution in the oil generation stage. The comprehensive analysis shows that the shallow semi deep lacustrine mixed sedimentary rock source reservoir of Lucaogou Formation is integrated, with great hydrocarbon generation potential. It is a set of “ self generation, self storage, high-efficiency accumulation and other source supply” tight dolomitic oil reservoir with favorable reservoir forming conditions of “ good material foundation, sufficient basic conditions and efficient accumulation of oil and gas” . [ABSTRACT FROM AUTHOR]

With the continuous deepening of oil and gas exploration and development, unconventional oil and gas resources, represented by tight oil, have become research hotspots. However, few studies have investigated tight oil potential in any systematic way in the shell limestone reservoir of the Sichuan Basin. Herein, we used thin section analysis, X-ray diffraction (XRD), high-pressure mercury intrusion, low-pressure N2 and CO2 adsorption experiments, low-field nuclear magnetic resonance (NMR), focused ion beam–scanning electron microscopy (FIB-SEM), and nano-CT to characterize multi-porous media. The reservoir space controlled by nonfabric, shell, and matrix constitutes all the reservoir space for tight oil. The interconnected porosity was mainly distributed in the range of 1% to 5% (avg. 2.12%). The effective interconnected porosity mainly ranged from 0.5% to 2.0% (avg. 1.59%). The porosity of large fractures was 0.1% to 0.5% (avg. 0.21%). The porosity of isolated pores and bound oil–water pores was 0.2% to 0.8% (avg. 0.44%). The dissolved pores adjacent to fractures, the microfractures controlled by the shell, the microfractures controlled by the matrix, the isolated pores, and the intracrystalline pores constitute five independent pore-throat systems. The development of pores and fractures in shell limestone reservoirs are coupled on the centimeter–millimeter–micron–nanometer scale. Various reservoir-permeability models show continuous distribution characteristics. These findings make an important contribution to the exploration and exploitation of tight oil in shell limestone. [ABSTRACT FROM AUTHOR]

In a mature middle and lower Gharif field in Oman, uncertainties surrounding initial water saturation and early water breakthroughs of unknown sources and paths suggest the presence of significant bypassed oil. In order to determine the areas with remaining oil, petrophysical and logging data of seven wells were processed using Techlog software and imported into Petrel software for modelling and simulation. Porosity was calculated using the Electric Propagation Time log and was utilized to evaluate the presence of oil, particularly in the upper tight zone of the formation. Despite the low resistivity readings in the highly porous layers, caused by good network connectivity and high formation water salinity, the resistivity contrast was sufficient to differentiate them from the oil zone. However, the calculated water saturation (Sw) in the tight top oil zone was high, consistent with the observed water production in the field. To improve the match between production data and simulation results, sensitivity analyses were conducted on various permeability anisotropy and relative permeability values within the model. The analyses showed that core-derived permeability anisotropy (vertical to horizontal ratio of 1:1) yielded a better history match for water production compared to the conventionally used value of 1:10. Water saturation maps were generated at the start and the end of production to highlight saturation distribution within the reservoirs. The maps revealed that in the lower porous part, the oil was fully depleted around the wells but remained trapped in the undrilled areas. [ABSTRACT FROM AUTHOR]

In recent years， tight oil horizontal wells in Daqing oilfield are mainly fractured by close cutting. However， the multi-cluster fracture propagation generates induced stress， which leads to uneven fracture extension in each cluster. To this end， the finite element software ABAQUS was used to establish the numerical model of multi-cluster fracture propagation in horizontal wells in Daqing tight-oil reservoir. The effects of two fracture parameters （cluster spacing， clusters within one fracturing stage） and three construction parameters （fracturing processes， construction displacement， and liquid viscosity） on fracture propagation were studied by the extended finite element （XFEM） simulation method. At the same time， it is found that there is a good consistency between the simulated fracture length of each cluster and the oil production contribution of each cluster when the simulated result is compared with the capacity contribution result of each cluster tested by actual optical fiber in the field. This confirms the correctness of the simulation results. The simulation results show that the stress interference of each cluster is obvious when the cluster spacing is reduced to 5 m， which is not conducive to fracture propagation. The mean fracture half-length of a single cluster does not change significantly when the cluster spacing reaches 10 m or more， and the reasonable cluster distance is about 10 m. The fracture half-length increases with increased clusters within one fracturing stage， but the non-uniform extension also becomes obvious. Compared with the simultaneous stimulation of multiple clusters in the bridge plug stage， the coiled tubing single-cluster stimulation mode is more favorable to fracture propagation. The average half-length of single cluster fractures increases with the rise of the construction displacement， and the uniform extension of fractures can be promoted by increasing the construction displacement. The average fracture half-length of a single cluster rises with the increase of liquid viscosity， and the proportion of high viscous liquid can be increased appropriately.

Abstract 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.

This study investigates the impact of nanomaterials on different surfactant solutions. By measuring the parameters (including emulsification property, zeta potential, DLS, CA, IFT, etc.) of imbibition liquid system with nanoparticles and without nanoparticles, combining with imbibition experiments, the law and mechanism of improving the imbibition recovery of nanomaterials were obtained. The findings demonstrate that the nano-silica sol enhances the emulsification and dispersion of crude oil in the surfactant system, resulting in smaller and more uniform particle sizes for emulsified oil droplets. Non-ionic surfactant AEO-7 has the best effect under the synergistic action of nanomaterials. Zeta potential and DLS tests also showed that AEO-7 exhibits smaller particle sizes due to their insignificant electrostatic interaction with nanoparticles. Furthermore, the addition of nanomaterials enhances the hydrophilicity of core and reduces the interfacial tension. Under the synergistic action of nanoparticles, AEO-7 still showed the best enhanced core hydrophilicity (CA 0.61° after imbibition) and the lowest interfacial tension (0.1750 mN·m−1). In the imbibition experiment, the imbibition recovery of the system with nanomaterials is higher than that of the non-nanomaterials. The mixed system of AEO-7 and nano-silica sol ZZ-1 has the highest imbibition recovery (49.27%). Combined with the experiments above, it shows that nanomaterials have a good effect on enhancing the recovery rate of tight core, and the synergistic effect of non-ionic surfactant AEO-7 with nanomaterials is the best. Moreover, nanomaterials reduce adhesion work within the system while improving spontaneous imbibition recovery. These findings provide theoretical guidance for better understanding the mechanism behind nanomaterial-induced imbibition enhancement as well as improving tight oil's imbibition recovery. [ABSTRACT FROM AUTHOR]

Copyright of Petroleum Geology & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Surfactant-assisted spontaneous imbibition is an important mechanism in enhanced oil recovery by capillary pressure in low permeability and tight oil reservoirs. Though many experiments have been conducted to study the mechanism of enhanced oil recovery by surfactant-assisted spontaneous imbibition, the effects of surfactant type, concentration, and temperature have not been well studied. Using tight sandstone outcrop core samples with similar permeability and porosity, this paper experimentally studies surfactant-assisted spontaneous imbibition using three different surfactant types, i.e., sodium dodecylbenzene sulfonate (SDBS), cocamidopropyl betaine (CAB), and C12–14 fatty alcohol glycoside (APG). In addition to the type of surfactant, the effect of the surfactant concentration and the temperature is also investigated. The study results show that the ultimate oil recovery of spontaneous imbibition with formation water and denoised water is about 10%. Surfactant can significantly improve the oil recovery of spontaneous imbibition by reducing the interfacial tension between oil and water, emulsifying crude oil and improving oil mobility. APG showed better performance compared to SDBS and CAB, with a maximum oil recovery factor of 36.19% achieved with formation water containing 0.05% APG surfactant. Lower concentrations (0.05% APG) in the formation water resulted in a higher oil recovery factor compared to 0.1% APG. Increasing temperature also improves oil recovery by reducing oil viscosity. This empirical study contributes to a better understanding of the mechanism of surfactant-assisted spontaneous imbibition and enhanced oil recovery in tight oil reservoirs. [ABSTRACT FROM AUTHOR]

A physical simulation method with a combination of dynamic displacement and imbibition was established by integrating nuclear magnetic resonance (NMR) and CT scanning. The microscopic production mechanism of tight/shale oil in pore throat by dynamic imbibition and the influencing factors on the development effect of dynamic imbibition were analyzed. The dynamic seepage process of fracking-soaking-backflow-production integration was simulated, which reveals the dynamic production characteristics at different development stages and their contribution to enhancing oil recovery (EOR). The seepage of tight/shale reservoirs can be divided into three stages: strong displacement and weak imbibition as oil produced rapidly by displacement from macropores and fractures, weak displacement and strong imbibition as oil produced slowly by reverse imbibition from small pores, and weak displacement and weak imbibition at dynamic equilibrium. The greater displacement pressure results in the higher displacement recovery and the lower imbibition recovery. However, if the displacement pressure is too high, the injected water is easy to break through the front and reduce the recovery degree. The higher the permeability, the greater the imbibition and displacement recovery, the shorter the time of imbibition balance, and the higher the final recovery. The fractures can effectively increase the imbibition contact area between matrix and water, reduce the oil-water seepage resistance, promote the oil-water displacement between matrix and fracture, and improve the oil displacement rate and recovery of the matrix. The soaking after fracturing is beneficial to the imbibition replacement and energy storage of the fluid; also, the effective use of the carrying of the backflow fluid and the displacement in the mining stage is the key to enhancing oil recovery. [ABSTRACT FROM AUTHOR]

Based on the geochemical, seismic, logging and drilling data, the Fuyu reservoirs of the Lower Cretaceous Quantou Formation in northern Songliao Basin are systematically studied in terms of the geological characteristics, the tight oil enrichment model and its major controlling factors. First, the Quantou Formation is overlaid by high-quality source rocks of the Upper Cretaceous Qingshankou Formation, with the development of nose structure around sag and the broad and continuous distribution of sand bodies. The reservoirs are tight on the whole. Second, the configuration of multiple elements, such as high-quality source rocks, reservoir rocks, fault, overpressure and structure, controls the tight oil enrichment in the Fuyu reservoirs. The source-reservoir combination controls the tight oil distribution pattern. The pressure difference between source and reservoir drives the charging of tight oil. The fault-sandbody transport system determines the migration and accumulation of oil and gas. The positive structure is the favorable place for tight oil enrichment, and the fault-horst zone is the key part of syncline area for tight oil exploration. Third, based on the source-reservoir relationship, transport mode, accumulation dynamics and other elements, three tight oil enrichment models are recognized in the Fuyu reservoirs: (1) vertical or lateral migration of hydrocarbon from source rocks to adjacent reservoir rocks, that is, driven by overpressure, hydrocarbon generated is migrated vertically or laterally to and accumulates in the adjacent reservoir rocks; (2) transport of hydrocarbon through faults between separated source and reservoirs, that is, driven by overpressure, hydrocarbon migrates downward through faults to the sandbodies that are separated from the source rocks; and (3) migration of hydrocarbon through faults and sandbodies between separated source and reservoirs, that is, driven by overpressure, hydrocarbon migrates downwards through faults to the reservoir rocks that are separated from the source rocks, and then migrates laterally through sandbodies. Fourth, the differences in oil source conditions, charging drive, fault distribution, sandbody and reservoir physical properties cause the differential enrichment of tight oil in the Fuyu reservoirs. Comprehensive analysis suggests that the Fuyu reservoir in the Qijia-Gulong Sag has good conditions for tight oil enrichment and has been less explored, and it is an important new zone for tight oil exploration in the future. [ABSTRACT FROM AUTHOR]

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.

Based on imbibition replacement of shut-in well in tight oil reservoirs, this paper expounds the principle of saturation rebalancing during the shut-in process after fracturing, establishes an optimization method for shut-in time after horizontal well volume fracturing with the goal of shortening oil breakthrough time and achieving rapid oil breakthrough, and analyzes the influences of permeability, porosity, fracture half-length and fracturing fluid volume on the shut-in time. The oil and water imbibition displacement in the matrix and fractures occurs during the shut-in process of wells after fracturing. If the shut-in time is too short, the oil-water displacement is not sufficient, and the oil breakthrough time is long after the well is put into production. If the shut-in time is too long, the oil and water displacement is sufficient, but the energy dissipation in the formation near the bottom of the well is severe, and the flowing period is short and the production is low after the well is put into production. A rational shut-in time can help shorten the oil breakthrough time, extend the flowing period and increase the production of the well. The rational shut-in time is influenced by factors such as permeability, porosity, fracture half-length and fracturing fluid volume. The shortest and longest shut-in times are negatively correlated with porosity, permeability, and fracture half-length, and positively correlated with fracturing fluid volume. The pilot test in tight oil horizontal wells in the Songliao Basin, NE China, has confirmed that the proposed optimization method can effectively improve the development effect of horizontal well volume fracturing.

Production prediction is crucial for the recovery of hydrocarbon resources. However, accurate and rapid production forecasting remains challenging for unconventional reservoirs due to the complexity of the percolation process and the scarcity of available data. To address this problem, a novel model combining a long short-term memory network (LSTM) and support vector regression (SVR) was proposed to forecast tight oil production. Three variables, the tubing head pressure, nozzle size, and water rate were utilized as the inputs of the presented machine-learning workflow to account for the influence of operational parameters. The time-series response of tight oil production was the output and was predicted by the optimized LSTM model. An SVR-based residual correction model was constructed and embedded with LSTM to increase the prediction accuracy. Case studies were carried out to verify the feasibility of the proposed method using data from two wells in the Ma-18 block of the Xinjiang oilfield. Decline curve analysis (DCA) methods, LSTM and artificial neural network (ANN) models were also applied in this study and compared with the LSTM-SVR model to prove its superiority. It was demonstrated that introducing residual correction with the newly proposed LSTM-SVR model can effectively improve prediction performance. The LSTM-SVR model of Well A produced the lowest prediction root mean square error (RMSE) of 5.42, while the RMSE of Arps, PLE Duong, ANN, and LSTM were 5.84, 6.65, 5.85, 8.16, and 7.70, respectively. The RMSE of Well B of LSTM-SVR model is 0.94, while the RMSE of ANN, and LSTM were 1.48, and 2.32.

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. [ABSTRACT FROM AUTHOR]

In this study, three-dimensional (3D) reservoir simulation models were developed to perform different simulation runs which aim to get an estimate for the optimal well spacing in such unconventional very low permeability reservoirs. It will take into consideration the limitations, uncertainties, and capabilities of each parameter like matrix permeability, hydraulic fracturing spacing, half-length, height, and conductivity to get an enhanced estimate of the optimal distance between wells. The estimated recovery factor and production forecasting using the reservoir simulation with its capabilities to get computational cases with different combinations will get the optimal well count with optimum economic evaluation. Utilizing 3D reservoir simulation modeling can help create a variety of scenarios with various arrangements of affecting factors, such as well design, pore volume, matrix permeability, and petrophysical parameters. Characterizing hydraulic fracture parameters, such as fracture spacing, fracture half-length, and fracture conductivity, is fraught with uncertainty. Furthermore, drilling, and fracturing procedures are expensive. As a result, it is crucial to quantify these fracture parameters using different data to optimize the fracture design for both single and many wells using economic analysis. A general production trend analysis and comparisons are run for various well spacing with different numbers of wells per 100 acres. The impact of the oil price and the other operational costs required for various instances will be considered in an economic evaluation based on a new well spacing optimization process. The net present value was calculated for several cases by changing the number of wells 2, 3, 4, 5, 6, 7, and 8 wells and showed that the optimum well spacing is 300 feet. [ABSTRACT FROM AUTHOR]

Based on imbibition replacement of shut-in well in tight oil reservoirs, this paper expounds the principle of saturation rebalancing during the shut-in process after fracturing, establishes an optimization method for shut-in time after horizontal well volume fracturing with the goal of shortening oil breakthrough time and achieving rapid oil breakthrough, and analyzes the influences of permeability, porosity, fracture half-length and fracturing fluid volume on the shut-in time. The oil and water imbibition displacement in the matrix and fractures occurs during the shut-in process of wells after fracturing. If the shut-in time is too short, the oil-water displacement is not sufficient, and the oil breakthrough time is long after the well is put into production. If the shut-in time is too long, the oil and water displacement is sufficient, but the energy dissipation in the formation near the bottom of the well is severe, and the flowing period is short and the production is low after the well is put into production. A rational shut-in time can help shorten the oil breakthrough time, extend the flowing period and increase the production of the well. The rational shut-in time is influenced by factors such as permeability, porosity, fracture half-length and fracturing fluid volume. The shortest and longest shut-in times are negatively correlated with porosity, permeability, and fracture half-length, and positively correlated with fracturing fluid volume. The pilot test in tight oil horizontal wells in the Songliao Basin, NE China, has confirmed that the proposed optimization method can effectively improve the development effect of horizontal well volume fracturing. [ABSTRACT FROM AUTHOR]

With the deep development of tight reservoir in Mahu Sag, the trend of rising water cut during flowback concerns engineers, and its control mechanism is not yet clear. For this purpose, the integrated numerical model of horizontal well pattern from fracturing to production was established, and its applicability has been demonstrated. Then the flowback performance from child wells to parent wells and single well to well pattern was simulated, and the optimization method of reasonable flowback strategy was discussed. The results show that the formation pressure coefficient decreases as well patterns were put into production year by year, so that the seepage driving force of the matrix is weakened. The pressure-sensitive reservoir is also accompanied by the decrease of permeability, resulting in the increase of seepage resistance, which is the key factor causing the prolongation of flowback period. With the synchronous fracturing mode of well patterns, the stimulated reservoir volume (SRV) is greatly increased compared with that of single well, which improves the reservoir recovery. However, when the well spacing is less than 200 m, well interference is easy to occur, resulting in the rapid entry and outflow of fracturing fluid, and the increased water cut during flowback. Additionally, the well patterns in target reservoir should adopt a drawdown management after fracturing, with an aggressive flowback in the early stage and a slow flowback in the middle and late stage. With pressure depletion in different development stages, the pressure drop rate should be further slowed down to ensure stable liquid supply from matrix. This research can provide a theoretical guidance for optimizing the flowback strategy of tight oil wells in Mahu sag. [ABSTRACT FROM AUTHOR]

Based on the parallel rock samples of tight oil reservoirs, the imbibition comparison experiments respecting to formation water and active water under different experimental conditions have been initiated. With adoption of the experimental measures i.e. Nuclear Magnetic Resonance (NMR), the micro-production mechanism of the enforcement of the imbibition oil recovery effect by the active agent has been analyzed. Surfactant may promote the imbibition effect of samples with different wettability, different water saturation and different sizes. The imbibition recovery ratios of No. 1 hydrophilic core in formation water and active water are respective 15.79% and 17.68%, and the active water imbibition increased by 1.88%, with an enforcement ratio of 11.97%. The imbibition recovery ratios of No. 3 lipophilic core in formation water and active water are respective 10.64% and 13.26%, and the active water imbibition increased by 2.62%, with an enforcement ratio of​ 24.62%. The enforcement effect of surfactant on the lipophilic core is higher than that on the hydrophilic core. The enforcement ratio of No. 1 core in macropores is 8.78%, and that of No. 3 rock is 36.14%, indicating that the surfactant can effectively reduce the seepage resistance of the lipophilic cores and enhance the imbibition recovery ratio of macropores. The increase magnitude and the enforcement ratio of the imbibition recovery of No. 4 low water-contained core are lower than those of No. 6 high water-contained core, indicating that the surfactant has a greater impact on the imbibition of high water-contained cores. The enforcement ratio in active water imbibition in core No. 4 is 28.59% in micropores and 15.46% in macropores; and respective 1460.74% and 9.56% for No. 6 core. The enforcement ratios of micropores in the two cores are both higher than those in macropores. It shows that the surfactant has a great influence on the permeability of micropores in the core. The increment magnitude in active water imbibition of small No. 2 core is 22%, and that of No. 2 large core is 26.93%, indicating that the surfactant has a greater impact on the imbibition of large cores.

The tight oil reservoirs of Fuyang and Gaotaizi in the Daqing Oilfield exhibit characteristics such as thin layers and distributed barriers, which pose challenges for maintaining drilling accuracy within the desired geological sweet spot. Hydraulic fracturing has emerged as the optimal method to connect production wells with target layers effectively. Understanding the behavior of hydraulic fracture propagation in multiple thin layers with significant differences in mechanical properties is crucial for assessing the extent of effective drainage. In this study, a finite element numerical simulation model incorporating cohesive elements is employed to investigate and quantify the effects of stress differences and rock mechanical parameters on fracture penetration. The results indicate that the stress difference between the reservoir and barrier layers plays a key role in controlling hydraulic fracture penetration and height. Moreover, the flow rate and viscosity of the fracturing fluid have a noticeable impact on fracture progression. Hydraulic fractures tend to propagate along the interface of layers with low flow rate and fluid viscosity, thereby hampering the penetration performance in those layers. To achieve a comparable penetrated fracture length in low permeability reservoirs, it is necessary to increase the volume of fracturing fluid in high permeability reservoirs. Furthermore, the barriers layers, which possess relatively weaker mechanical properties, can constrain the width development of hydraulic fractures. This limitation may result in the risk of excessive liquid without sufficient proppant (commonly known as “over liquid but no sand”). Therefore, appropriate measures should be implemented to increase the net pressure and avoid encountering this complex situation.

The Chang 6 sandstone reservoir of the Upper Triassic Yanchang Formation in the Ordos Basin is one of the tight-oil-rich intervals in the basin. Owing to the strong heterogeneity and complex lithology of the Chang 6 reservoir, lithology and fluid identification have become more challenging, hindering exploration and development. This study focused on the Chang 6 member in the Qingcheng area of the Ordos Basin to systematically analyze the lithology, physical properties, and oil-bearing properties of the Chang 6 reservoir. We adopted the method of normalized superposition of neutron and acoustic time-difference curves, the method of induced conductivity–porosity–density intersection analysis, the method of superposition of difference curves (Δφ), and the induced conductivity curve. Our results indicated that the method of normalized superposition of neutron and acoustic wave time-difference curves could quickly and effectively identify the lithologies of tight fine sandstone, silty mudstone, mudstone, and carbonaceous mudstone. The induced conductivity–porosity–density cross-plot could be used to effectively identify oil and water layers, wherein the conductivity of tight oil layers ranged from 18 to 28.1 mS/m, the density ranged from 2.42 to 2.56 g/cm3, the porosity was more than 9.5%, and the oil saturation was more than 65%. Based on the identification of tight fine sandstone using the dual-curve normalized superposition method, the oil layer thickness within the tight fine sandstone could be effectively identified using the superposition of difference curves (Δφ) and induced conductivity curves. Verified by oil-bearing reservoir data from the field test, the overall recognition accuracy of the plots exceeded 90%, effectively enabling the identification of reservoir lithology and fluid types and the determination of the actual thickness of oil layers. Our results provide a reference for predicting favorable areas in the study area and other tight reservoirs.

Despite the abundance of shale-oil and tight-oil reserves in the Fengcheng Formation within the Mahu Sag, exploration and development efforts for both types of reservoir are still in their early stages. A comprehensive examination and comparison of the pore structures of these reservoirs can establish rational classification and evaluation criteria. However, there is a dearth of comparative analyses focusing on the pore structures of shale-oil and tight-oil reservoirs within the Fengcheng Formation. This study addresses this gap by systematically analyzing and comparing the pore structures of these reservoirs using various techniques such as X-ray diffraction (XRD), scanning electron microscopy (SEM), low-temperature nitrogen adsorption, and mercury intrusion capillary pressure experiments (MICP). The results show that the shale oil within the Fengcheng Formation exhibits a higher content of carbonic acid compared to the tight-oil samples. Furthermore, it demonstrates smaller displacement pressure and median pressure, a larger sorting coefficient, and superior permeability in contrast to tight oil. Notably, the shale oil within the Fengcheng Formation is characterized by abundant striated layer structures and micro-fractures, which significantly contribute to the microstructural disparities between shale-oil and tight-oil reservoirs. These differences in microstructures between shale oil and tight oil within the Fengcheng Formation in the Mahu Sag region delineate distinct criteria for evaluating sweet spots in shale-oil and tight-oil reservoirs.