Influenced by the expansion of the Paleo-Tethys Ocean, the Devonian system along the western margin of the Yangtze Block presents a continuous sedimentary succession, with thickness up to several kilometers, providing favorable petroleum geological conditions. Due to complex surface structures and large burial depth of the Devonian in the Longmenshan piedmont zone of the Western Sichuan depression, this area has been insufficiently explored and studied. Moreover, there is limited research on stratigraphic distribution, reservoir development patterns, and hydrocarbon accumulation and preservation conditions of the Devonian in the deeply buried zones in the basin. Based on high-precision, contiguous 3D seismic data, this study identifies and confirms the presence of Middle-Upper Devonian high-energy facies zones. By integrating drilling and outcrop data, the fundamental hydrocarbon accumulation conditions of the Devonian in the central part of the Western Sichuan Depression are clarified, and future exploration directions are proposed. The results show that the strata in the Middle Devonian-Carboniferous in the central part of the Western Sichuan depression have a residual thickness ranging from 0 to 450 m, gradually decreasing from west to east, with a distribution area of up to 6,500 km². The Middle-Upper Devonian is primarily an open platform to restricted platform depositional system, where high-quality reservoirs are mainly intraplatform facies and contain dissolution pores/vugs, jointly controlled by high-energy facies zones, fractures and early-stage dissolution. These high-quality reservoirs exhibit distinct medium-strong amplitude, discontinuous reflection features on seismic sections, and distribute as NE-SW-trending strips, covering an area of approximately 2,000 km². Structural-lithologic traps in the Middle-Upper Devonian across the Western Sichuan depression, formed during the Indosinian period, show a good match with the peak hydrocarbon generation period of the Cambrian main source rocks. The overlying Triassic gypsum-salt rocks serve as a regional seal, ensuring excellent preservation conditions. Individual reservoirs can reach 100 m in thickness. These characteristics imply potential for forming large-to-medium, high-abundance gas fields. It is concluded that the Middle-Upper Devonian can be taken as a favorable target for deep-to-ultradeep marine exploration in the Sichuan Basin.

The Mabei area in the Mahu sag of the Junggar Basin has yielded significant hydrocarbon discoveries in multiple strata, including the Carboniferous, Permian, and Triassic. However, physical properties of crude oil vary spatially and stratigraphically, and the genetic mechanism underlying this differentiation represents a critical geological factor constraining hydrocarbon exploration. In this study, analyses on total hydrocarbon chromatography and biomarker were systematically performed. Based on the differential distribution of crude oil physical properties, the genetic mechanism of spatial differentiation was investigated, and an oil accumulation model for the Mabei area was established. The results show that the chemical composition of crude oil is the fundamental cause of physical property variations. Differences in depositional environment and thermal maturity of source rocks give rise to variations in chemical composition. In addition, multi-stage charging, mixing, and biodegradation further complicate the physical properties of crude oil. The Triassic crude oil in the sag and slope zones features low density, low viscosity, high wax content, and a high freezing point. It has a high proportion of saturated hydrocarbons and a low content of isomeric branched alkanes, indicative of predominantly high-mature oil. This oil was sourced from the high-maturity source rocks of the Fengcheng formation in the sag, migrated upward along faults, and accumulated in shallow reservoirs. The Permian crude oil in the slope zones and the conventional crude oil in the fault zones is characterized by high density, high viscosity, low wax content, and low freezing point. These oils have low saturated hydrocarbon content but abundant isomeric branched alkanes, and are dominated by mature oil, with a minor proportion of high-mature oil. Specifically, the mature oil originated from the source rocks of the Fengcheng formation in the fault and slope zones, forming reservoirs through vertical near-source migration or in-situ accumulation. The high-mature oil, which occurs only in the fault zones, is interpreted to have been sourced from both the Fengcheng and Jiamuhe formations, with lateral migration as the primary transport mechanism. The shallow heavy oil in the fault zones, buried at depths of less than 1,500 m, has a high freezing point and was mostly subjected to biodegradation.

In the eastern Ordos Basin, the coal seam No. 8 in the Carboniferous Benxi formation has been extensively developed for coal-rock gas. In the Ningqing block of the western Ordos Basin, however, the coal seams are typically thin, compositionally complex, and sedimentologically intricate, which has hindered their exploration and development. Using microscopic experiments such as proximate analysis, maceral analysis, and elemental analysis in combination with elemental logging and conventional logging data, this study analyzed the coupling relationships between measured data and sensitive logs. Subsequently, the macrolithotype and log-based identification criteria for the coal seam No. 8 in the Benxi formation in the Ningqing block were established. On this basis, sensitive elemental analysis was performed to reconstruct the coal-forming paleoenvironment, and maceral analysis was conducted to define a coal facies calibration index. The sedimentary facies distribution of the coal seam No. 8 was finely characterized, and the corresponding sedimentary facies model was constructed. Proximate analysis results indicate that, for the coal seam No. 8 in the Benxi formation of the Ningqing block, the fixed carbon and ash contents exhibit the strongest coupling with the density (DEN) log. In terms of macrolithotype, semi-dull coal is dominant, followed by semi-bright and dull coal, with bright coal being underdeveloped. Both total sulfur and inorganic sulfur contents exhibit a decrease-increase-decrease-increase cyclic pattern, indicating four sea-level fluctuations during the depositional period. Paleoenvironmental analysis based on elemental logging data indicates that the target interval was deposited in an environment alternating between weakly oxidizing and weakly reducing conditions, with primarily freshwater to brackish water and in a warm, humid paleoclimate, and recorded typical marine-continental transitional facies. Coal facies classification criteria were established based on macrolithotype, industrial components, and lithofacies associations. Accordingly, the facies of the coal seam No. 8 in the study area are categorized into three types: shallowly inundated herbaceous marsh and wetland herbaceous marsh dominantly under continental conditions in the central-northern region, and open-water swamp dominantly under marine conditions in the southern region. Moreover, a sedimentary facies model for the coal seam No. 8 in the Ningqing block was established. The research findings provide a basis for the exploration of coal-rock gas in the western Ordos Basin.

There is a close relationship between diagenetic facies and distribution of high-quality reservoirs. Logging interpretation of diagenetic facies is crucial for predicting favorable zones in low-porosity and low-permeability reservoirs. The diagenetic facies were classified after analyzing the data of cast thin sections, scanning electron microscopy (SEM), high-pressure mercury intrusion (HPMI), and physical property tests. Using logging data, the diagenetic facies were classified across the study area from the prospective of coring wells, full hole of individual wells, and target intervals by integrating the Fisher discriminant method with the dominant facies method. On this basis, the favorable zones were predicted. The results show that the ninth member of the Lower Jurassic Yan’an formation (Yan-9 member) in the H65 block of the southern Tianhuan depression, is represented by low-porosity and low-permeability, fine-pore and fine-throat reservoirs. These reservoirs are dominated by lithic quartz sandstone, with low cement content. The storage space is mostly composed of feldspar dissolved pores-intergranular pores, with uneven distribution of pore throats and poor connectivity. In the diagenetic transformation stage, compaction led to a significant reduction in porosity, by a rate up to 44.57%, thus being the main destructive factor. In contrast, dissolution improved the porosity only by 3.01%, suggesting a limited contribution to the optimization of pore throat connectivity and the expansion of storage space. Six types of diagenetic facies are identified in the study area, including intergranular pore facies, feldspar dissolved pore-intergranular pore facies, feldspar dissolved pore facies, kaolinite cementation facies, carbonate cementation facies, and mechanical compaction facies. Based on the classification of diagenetic facies by using the Fisher discriminant method across the study area, it is believed that the central and central-southern parts of the study area hold favorable conditions of diagenetic facies for oil and gas accumulation, and thus can be considered as the targets for subsequent exploration. The results demonstrate that the Fisher discriminant method is highly accurate in classifying diagenetic facies, thereby facilitating the prediction of favorable zones in low permeability reservoirs.

Volcanic rock reservoirs are complex in distribution, and especially the relationship between volcanic rock stratigraphic boundary and reservoir distribution remains unclear. Based on the data of field volcanic edifice sections, drilling, logging, elements, and thin sections, the stratigraphic boundaries in the Mesozoic volcanic rocks in the Bohai Bay Basin were identified, and their types and characteristics were clarified, and the influence of these stratigraphic boundaries on reservoirs was investigated. The results indicate that long-term, medium-term, and short-term exposed stratigraphic boundaries associated with eruptive unconformity are identified in the Mesozoic volcanic rocks in the Bohai Bay Basin. The long-term exposed stratigraphic boundaries reflect obvious angular unconformities in seismic data. In contrast, the medium-term and short-term ones exhibit remarkable signatures on electrical and elemental logs due to the presence of sedimentary interlayers and thin weathering crusts. These signatures are mainly manifested in decreased resistivity, lower density, increased acoustic travel time, and higher neutron porosity near the stratigraphic boundaries, as well as gradual increases in contents of elements such as Ca, Ti, Fe, Mg, P, and Mn. The stratigraphic boundaries exert differential control on volcanic rock reservoirs. Specifically, the long-term exposed stratigraphic boundaries control the weathering crust reservoirs (mostly 150-300 m thick) at the top of buried hills; below the medium-term exposed stratigraphic boundaries, intra-buried-hill reservoirs with thickness of 30-50 m are found; and beneath the short-term exposed stratigraphic boundaries, there are intra-buried-hill reservoirs, with thickness of 10 m or up to 50 m individually. A model of reservoir development controlled by 3 stratigraphic boundaries was established. It is recognized that the volcanic rock reservoir exhibit a multi-layered stacking architecture. The study provides a basis for the shift of exploration from weathering crust at the top of buried hills to reservoirs within buried hills.

Due to complex geological conditions and technical limitations, the migration of metal cations, changes of energy and other processes during the diagenesis of zeolite cement in deep reservoirs are difficult to quantify. Previous studies have compared the genesis of natural and synthetic zeolites, but most have focused on a single type; therefore, systematic comparisons on the genetic conditions among different zeolite types remain lacking. This study examines the Permian volcaniclastic-rich sandy conglomerate reservoirs in the Shawan sag of the Junggar Basin. Using microscopic methods such as thin section observation, scanning electron microscopy (SEM), and energy-dispersive spectroscopy (EDS), natural and synthetic zeolites of the same type were compared for their compositional and structural characteristics. The formation processes of natural and synthetic zeolites were compared based on the genetic conditions of synthetic zeolites. The paper preliminarily revealed the diagenetic conditions of natural zeolite and identified the genetic mechanisms and abnormal growth processes of zeolite cements, as well as the controlling factors for different zeolite phases. The results show that natural and synthetic zeolites are similar in formation temperature, pH value, and Si/Al ratio, and are also highly similar in chemical composition, crystal morphology, and structure. Furthermore, the dissolution of volcanic glass increases the concentration of OH^- ions, which in turn raises the salinity and alkalinity of pore water, promoting the formation and abnormal growth of zeolite cement and controlling the formation of different zeolite phases. Zeolite transformation is mainly influenced by the compositional differences of volcanic materials and the dissolution of volcanic glass.

High-pressure brine layers were encountered while drilling in the Shengjinkou formation of the Huxi anticline, Junggar Basin. The coexistence of kicks and lost circulation restricted drilling rate. Therefore, it is necessary to accurately predict the 3D distribution and pore pressure of these high-pressure brine layers. This study adopts well-seismic integration and “point-to-volume” prediction approach based on drilling, mud logging, well logging, and seismic data. The genesis of high-pressure brine layers was analyzed using seismic and structural characteristics at well sites. The pore pressure was predicted based on the correlation between pore pressure equivalent density and seismic trace integral interval attributes. The results show that the high-pressure brine layers in the Shengjinkou formation of the Huxi anticline originate from water-bearing fault-fracture bodies sealed by tight layers, and their distribution correlates with the distance from faults. Low pore pressure zones in the high-pressure brine layers occur at the edges of fault damage zones, where water invasion risk is low. In contrast, high pore pressure zones are located in the fault-fracture areas and the central parts of fault damage zones, where water invasion risk is high. These findings provide a basis for decision-making in risk identification, prevention and control, precise pressure control, and pressure reduction via drainage.

To enhance the quantitative interpretation accuracy of fluid saturation in the Paleozoic tight sandstone gas reservoirs in the Ordos Basin, the physical and electric properties of the reservoir were analyzed, indicating a feasibility to interpret porosity, water saturation and gas saturation in sequence. The Archie formula was re-derived to obtain an equation to represent water-bearing porosity and resistivity, and the in-situ resistivity of formation water was defined, without the necessity to perform litho-electric experiments and formation water resistivity tests. On the basis of the above theory, taking the Well A area in the southeastern Yishaan slope as an example, a quantitative interpretation approach of reservoir fluid was established. Firstly, the existing basic data acquisition process and the main error causes were analyzed, and the data with the minimum fluid loss were selected as the basic data for interpreting water-bearing porosity. Then, the crossplot of water-bearing porosity and resistivity was established, and the water-bearing porosity interpretation equation was formed. Finally, according to the porosity interpretation equation and the water-bearing porosity interpretation equation, the gas saturation of reservoirs in the Well A area was quantitatively interpreted. It is found that the obtained gas saturation is highly consistent with the production results, and is 95.14% coincident with the single-layer gas test results. Compared with the results from Archie formula, the proposed interpretation approach exhibits lower technical requirements for experiments, and achieves improvements in both accuracy and resolution. This research enriches the theory for quantitative interpretation of tight sandstone gas reservoirs in the Ordos Basin, and provides reference for quantitative interpretation of tight sandstone gas reservoirs in other areas.

Identification of dominant flow channels is a critical step in oilfield development. Conventional studies on interwell dominant flow channels require data that are difficult to acquire, in addition to complex operations and high costs. Moreover, conventional numerical simulation methods employ grid-based complex geological models which feature burdensome data loading and long computation cycle. To quickly identify dominant flow channels, an interwell connectivity inversion model was established based on a capacitance resistance model for production (CRMP), and the injection-production data transmission relationship was constructed using connectivity coefficient and time constant. The ensemble Kalman filter (EnKF) was used as an optimization algorithm for automatic history match of production data, enabling quantitative characterization of interwell connectivity. The average permeability between wells and oil saturation at well points were calculated using the principle of hydroelectric similarity principle, fractional flow equation, and relative permeability curve. An oil saturation field map was plotted to characterize the dynamic production process of oilfield. The standard for dividing dominant flow channels was developed using the K-means algorithm, and multidimensional clustering analysis was conducted on connectivity coefficient and production data to achieve intelligent identification of dominant flow channels. Finally, the proposed model was applied to actual oil reservoirs. In this application, the noise effects of data and the model were considered, and multiple sets of parameters were updated simultaneously through data assimilation during the model training. The average value was taken as the optimal solution, thereby avoiding the ambiguity in results. The results indicate that the CRMP- and EnKF-based model accurately delineates the spatial distribution of dominant flow channels, and also reduces the uncertainty of reservoir parameter inversion. Actual reservoir applications demonstrate basically identical oil saturation fields inverted by CRMP and obtained by numerical simulation. The effects of data update and parameter convergence are significant, and the obtained connectivity coefficient agrees well with the tracer results, reaching 83%. The findings prove that the proposed technique is of great significance for decision-making in future waterflooding, profile control and well selection in oil reservoirs.

CO₂ huff-and-puff is considered as the most promising and effective enhanced oil recovery technique for depletion-drive development of ultra-low permeability reservoirs. Nonetheless, due to the limitations such as injection modes, gas costs, and safety/environmental concerns, it is urgent to find new huff-and-puff strategies for horizontal well depletion-drive development of these reservoirs. The alternating injection of nano-sized oil displacement agent and oxygen-reduced air not only leverages the oil displacement mechanisms of nanoparticles and gas, but also generates a distinctive synergistic effect. In this study, laboratory experiments were conducted to evaluate the oil displacement mechanisms of oxygen-reduced air and nano-sized oil displacement agent, and molecular simulation was employed at the microscopic level to investigate the synergistic effect of the combined huff-and-puff with oxygen-reduced air and nano-sized oil displacement agent. Then, reservoir engineering methods and numerical simulations were adopted to optimize key parameters including huff-and-puff timing, injection volume, injection rate, and soaking time. Finally, field tests were performed at horizontal wells C-H1 and D-H2 in the Z area. The tests revealed a cumulative incremental oil production of 4,526.7 tons and an input-output ratio exceeding 1∶2.5, demonstrating satisfactory huff-and-puff and displacement performance. The proposed combined huff-and-puff with oxygen-reduced air and nano-sized oil displacement agent provides a practical guidance for late-stage energy replenishment in horizontal well depletion-drive development of ultra-low permeability reservoirs.

Understanding the displacement characteristics and mechanisms of high-pressure waterflooding is critical to improving oil recovery in low-permeability reservoirs. In this study, laboratory experiments were conducted on core samples from typical low-permeability reservoirs. The experiments were performed using T₂ spectra and T₁-T₂ two-dimensional NMR techniques under different injection parameters and displacement modes, in order to quantitatively evaluate the mobilization of crude oil and occurrence of residual oil in pores of various scales. Moreover, two-dimensional NMR analysis was performed to further reveal the oil-water distribution across pore sizes and its evolution during displacement. The results demonstrate that oil recovery has been improved significantly-by up to 14.38% and 8.05%, respectively-under elevated injection pressure and rate, primarily due to enhanced mobilization of oil in macropores. An additional recovery of 10.94% was achieved when high-pressure waterflooding was applied after imbibition, further mobilizing residual oil in macropores. These results identify injection pressure and rate as the dominant parameters governing the recovery enhancement by waterflooding in low-permeability reservoirs. It is recommended to combine high-pressure waterflooding with high-rate water injection, along with the coupling of soak imbibition and high-pressure waterflooding. This treatment is expected to effectively reduce residual oil saturation and improve oil recovery. The study provides theoretical support to the optimization of waterflooding process in low-permeability reservoirs.

During production of condensate gas, there is a gas-to-liquid phase transition along with temperature and pressure changes in wellbores. This phenomenon results in low accuracy of conventional bottomhole flowing pressure (BHFP) calculation methods such as empirical formula and the modified H-B algorithm. To address this problem, a BHFP prediction model based on machine learning (ML) algorithms including BP neural network and LightGBM was proposed. Using 1,536 measured datasets from 24 wells, followed by normalization, noise removal, and correlation analysis, the modified H-B algorithm, BP neural network, and LightGBM algorithm were employed for modeling. The results show that the histogram-based splitting and feature binding techniques of LightGBM can significantly reduce the computational complexity and improve the fitting accuracy, with the correlation coefficient up to 0.9893, and the mean absolute error (MAE) of 86.5% lower than the modified H-B algorithm. A quantitative analysis was conducted on the main factors controlling BHFP prediction, suggesting gas production as the most prominent factor. Based on the accurate fitting of BHFP, the proposed model was extended to condensate gas wells without pressure-measurement conditions, and it accurately identified two production wells at high-risk pressure points of retrograde condensation. Specifically, for Well A6, the production regime was adjusted by increasing the wellhead tubing pressure by 2.73 MPa, which ultimately led to an increase in the daily gas production by more than 2,000 m3/d, and in the gas productivity index by 31.6%. This performance validated the effectiveness of the proposed model in identifying high-risk wells and guiding optimization of production regime. It is concluded that the ML-based BHFP prediction model can efficiently quantify the multiphase flow behaviors in wellbores, providing reliable technical support for adjusting the production regime of condensate gas reservoirs and controlling retrograde condensation pollution.

Tight sandstone of the Carboniferous Taiyuan formation in the Xunyi area represents a favorable exploration target in the southern Ordos Basin. However, it exhibits rapid variation in lithofacies and is sheltered by both the overlying continental coal rocks and the underlying marine carbonate rocks with strong reflection events, which challenge reservoir prediction. In the eastern Xunyi area covered by 2D seismic survey, seismic attribute analysis and inversion on 2D lines were often used in previous prediction of reservoir distribution, These techniques suffered from problems such as multiple solutions and low accuracy. This paper proposes a probabilistic deduction method with step-by-step constraints to predict tight sandstone reservoirs in 2D seismic areas. First, a layer-flattening procedure was applied to identify layer-thickening zones and favorable sedimentary facies zones for tight sandstones, thus setting the first-level constraint. Then, under the regional sedimentary framework, structure models of different lithologic associations were established using actual drilling data, and the seismic reflection probability type for the sandstone development area was simulated by forward modeling. Accordingly, the favorable area for tight sandstone development was determined according to the seismic response characteristics of sandstone in the favorable sedimentary facies zones. In this way, the second-level constraint was created. Finally, the wave impedance inversion was performed based on well log constraint to define sweetspots in the sandstone, achieving the third-level constraint. This three-level sandbody control approach for predicting tight sandstone reservoirs by probabilistic deduction with step-by-step constraints achieves improvements in precision (from 15 m to 10 m) and prediction coincidence (from 40% to 75%). The newly deployed exploration well encountered a tight sandstone layer of 24 m thick, recording effective support to the exploration in marine-continental transitional tight sandstone gas reservoir.

The sand groups 4 and 5 of the upper Guantao formation (Ngs4 and Ngs5) in the Chengdao oilfield, Bohai Bay Basin, represent meandering river deposits, and exhibit rapid reservoir sedimentary facies transition. Reservoirs in the upper Guantao formation are found with pronounced interlayer and planar heterogeneities. Based on two dimensions of reservoir quality and spatial distribution, four evaluation index systems comprising basic parameters, intralayer heterogeneity parameters, interlayer heterogeneity parameters, and planar heterogeneity parameters respectively were established. Employing the Random Forest algorithm, the importance of each parameter to heterogeneity was quantified. Subsequently, basic composite index and intralayer/interlayer/planar heterogeneity composite indexes were calculated, a formula for calculating reservoir heterogeneity composite index was designed, and the reservoir heterogeneity composite index was yielded. The results indicate that a higher heterogeneity composite index reflects a weaker reservoir heterogeneity.

Deep drilling in the Shunbei area is confronted with a complex geological environment where reservoirs are controlled by strike-slip fault zones. In addition, the strata in this area are highly fragmented, posing a significant risk of deep wellbore instability. However, no quantitative method is currently available to characterize the fragmentation degree, leaving the instability mechanism unclear. This paper presents a 3D quantitative method to characterize the degree of fragmentation in deep strata based on seismic data, as demonstrated by a case study of the Ordovician Yijianfang-Yingshan formation in the Shunbei area. First, an index for the degree of rock mass fragmentation was established using acoustic wave dynamics. Second, wave impedance inversion was performed on seismic data that had been processed by Gaussian filtering and normalization. Third, fault identification results from 3D seismic data were transformed into threshold-type weight function to constrain the fragmentation degree index. Finally, 3D seismic imaging technology was integrated with the time-depth relationship, together with well location, inclination, and azimuth data, to achieve spatial matching between the 3D wellbore trajectory and fragmented zones. The fragmentation degree index was then validated through laboratory experiments and individual-well logging data. The proposed method was further validated by comparison with fault identification models including edge detection and ant tracking. The predicted rock-mass fragmentation profile matches the borehole enlargement log with an agreement rate of 89% for actual wells in the Shunbei area. This method provides a reference for predicting the degree of fragmentation in deep strata.

In the southern Songliao Basin, deep strata experienced intense volcanic activity during faulting period. Volcanic rocks act as the critical hydrocarbon reservoir rocks, but they interfere the seismic imaging of underlying strata. It is very important to study the impact of volcanic rocks on seismic imaging of underlying strata. Based on the typical characteristics and elastic parameters of the volcanic rocks in two eruption cycles and the overlying and underlying rocks in the Chaganhua subsag of the Changling fault depression, physical models were built by scaling down, and seismic acquisition and image processing were performed. On this basis, the impacts of the volcanic rocks on the seismic imaging of the underlying strata were analyzed. The results show that equivalent velocity and density models for volcanic rock formations can be constructed using mixed materials with mica powder and epoxy resin as cementing agents to simulate volcanic rock with high wave impedance and high hardness, together with different proportions of organic crystals to simulate different facies zones. These physical models yield the errors of P-wave velocity less than 2%. It is found that the volcanic rocks of Lower Cretaceous Yingcheng formation have great impacts on the well-seismic calibration of the underlying strata, the thickness of the volcanic rocks and the thickness of the underlying clastic rocks jointly affect the well-seismic calibration of the volcanic rocks of the Lower Cretaceous Huoshiling formation, and the seismic imaging-derived velocity in the volcanic rock area is smaller than the actual velocity of the strata. Based on the research results from the physical models, and considering the data of existing wells and previously acquired insights on the thickness and distribution of the volcanic rocks and clastic rocks, grid tomographic velocity modeling was conducted to iteratively optimize the velocity model, improving the compatibility between actual seismic data and synthetic seismogram. This study provides reference for seismic imaging in volcanic rock areas in other regions around the world.