Typical Reservoir Research Articles

Natural gas accumulation conditions and exploration directions of Carboniferous clastic rocks in the northeastern margin of Junggar Basin, China

The Carboniferous strata in the northeastern Junggar Basin are an important exploration field for natural gas in the basin. However, volcanic rocks have long been the primary exploration target. In contrast, the exploration and research of clastic rocks associated with source formations have been largely overlooked, resulting in an insufficient understanding of the reservoir forming conditions and exploration potential of Carboniferous clastic rocks. Through the evaluation of Carboniferous source rocks, effective source stove characterization, clastic reservoir evaluation, oil and gas source correlation, and reservoir formation model construction in this region, three key findings have been made. First, the Carboniferous in the northeastern Junggar Basin has developed three sets of high-quality gas source rocks: the Dishuiquan Formation, the Songkalsu B Member, and the Shiqiantan Formation. These formations correspond to three hydrocarbon source centers: the Sannan–Dishuiquan Sag, the Wucaiwan Sag–Dajing area, and the Dongdao Haizi Sag–Baijiahai High. Second, the Carboniferous system in the northeast has developed multiple types of large-scale reservoirs, including sand conglomerates, sandstones, turbidites, dolomitic rocks, and shale. These reservoirs are generally characterized by low porosity to ultra-low porosity and low permeability to ultra-low permeability reservoirs. There is a dissolution pore development zone at depths of 2900–4500 m. Third, a comparison of oil and gas sources reveals that all three sets of gas source rocks contribute to the natural gas found in the northeast, with obvious characteristics of near-source reservoir formation. The Carboniferous clastic rocks host two types of natural gas reservoirs: unconventional and conventional near-source reservoirs. It is predicted that there is an orderly accumulation pattern of shale gas, tight sandstone gas, and conventional natural gas reservoirs. This study reveals that the Carboniferous clastic rock source and reservoir configuration in the northeastern Junggar Basin is highly favorable, and the natural gas reservoirs in source and near-source clastic rocks represent important exploration directions.

Study on dynamic imbibition mechanism of matrix-fracture in three dimensions tight sandstone based on level set method

Tight oil reservoirs require fracturing techniques to create complex fracture networks for efficient development. It is frequently accompanied by a dynamic matrix-fracture imbibition process, promoting enhanced recovery. At present, the mechanism of three dimensions (3D) matrix-fracture dynamic imbibition at the pore scale has not been fully elucidated. In this paper, the dynamic imbibition process of oil-water two phases in matrix-fracture was simulated based on the Navier–Stokes equations, and the level set method was used to capture the real-time interfacial changes between the two phases. It was found that during matrix-fracture dynamic imbibition process, oil-phase droplets in a single pore remain in the pore mainly due to the “stuck” effect. Cluster residual oil in the pore space is mainly retained due to the “flow around” effect. Continuous residual oil in the deeper regions of the matrix is due to insufficient capillary force. Water phase in the micro-confinement space of a tight reservoir intrudes into the pore space along the pore corners, forming the “fingering” phenomenon is beneficial for enhancing the efficiency of micro-dynamic imbibition. It differs from cognition obtained in the micro-view space during conventional water flooding. The enhancement of imbibition efficiency is often accompanied by the occurrence of fluctuations in the average pressure within the matrix. Therefore, a method involving impulse type of high-frequency and short-period for supplemental energy and imbibition is suggested to enhance recovery in tight sandstone reservoirs. This study reveals the detailed mechanisms of oil-water two-phase transport at different stages in the dynamic imbibition process and holds significant guiding implications for enhancing recovery in this type of reservoirs.

Helium resources accumulation regulations and their development prospects in China

Helium is a globally scarce strategic resource that is relevant to national economies and the development of high-tech industries, and China primarily depends on imported helium for its industrial applications. Therefore, there is an urgent demand for clarifying helium formation and enrichment patterns, searching for helium-rich fields, and realizing China's helium resource inventory and development potential. This article analyzes the reservoir characteristics and accumulation conditions of typical helium-rich fields in China, and clarifying the origin and source of helium as well as the main controlling factors of helium enrichment. It was recognized that helium in natural gas in China mainly comes from crustal sources. Relatively shallow buried ancient U–Th-rich granite basement or intrusion, large and stable ancient uplift or submarine formed in the early period, good overburden of huge thick paste-salt rock or mudstone cover, and channels connecting the basement and reservoir, were the main controlling factors of helium enrichment. Four types of helium-rich gas reservoirs, namely helium-rich conventional gas, helium-rich shale gas, helium-rich non-hydrocarbon gas, and helium-rich water-soluble gas, have been modeled and predicted to be helium-rich favorable exploration areas. Based on this analysis, the prospect of helium resource development in China has been analyzed. It was proposed that the exploration of helium-rich fields and the comprehensive development and utilization of medium- and low-abundance helium resources are important ways to increase the domestic helium production in China in the future.

Molecular dynamics study of shale oil adsorption and diffusion behavior in reservoir nanopores: Impact of hydrocarbon composition and surface type

Understanding shale oil adsorption in reservoir nanopores is essential for efficient extraction. This study used MD simulations to analyze the adsorption and diffusion of two- and multi-component hydrocarbons (Aromatics, Alkanes, Resin) on various shale surfaces (Calcite, Montmorillonite, Quartzite, Organic) at 353 K and 25 MPa. Hydrocarbons formed a bilayer adsorption structure comprising a high-concentration adsorption layer (L1, 0.35–0.90 g/cm3) and a low concentration weak adsorption layer (L2), with adsorption density ranked as Resin > Aromatics > Alkanes. Reservoir surfaces were classified as ionic (e.g., calcite, montmorillonite) and non-ionic (e.g., quartz, graphite), and polar hydrocarbons exhibited higher adsorption densities and energies on ionic surfaces due to combined electrostatic and van der Waals interactions, while non-ionic surfaces showed smaller adsorption differences. For multicomponent hydrocarbons, adsorption layer densities followed the order: graphite > MMT-SiO > quartz > calcite > MMT-Na, with competitive adsorption observed. The polar component exhibited a greater adsorption advantage on the calcite, MMT-SiO side and graphite surfaces due to electrostatic interactions and π-π interactions, and a lesser advantage on the MMT-Na side and quartz surfaces. Hydrocarbon diffusivity was influenced by molecular mass and polarity and ordered as Alkanes > Aromatics ≫ Resin. Polar molecules had a weaker diffusion than nonpolar molecules at similar molecular masses. Among the multicomponent hydrocarbons, the self-diffusion coefficient (Self-D) of Resin increased, while that of lighter components decreased compared to two-component systems. These findings offer strategies for improving shale oil recovery by tailoring injection fluids to reservoir types, anionic surfactants or chelating agents may be used to reduce electrostatic interactions in carbonate and clay reservoirs, while nonionic surfactants may be more effective in quartz reservoirs.

A New Approach to a Fracturing Sweet Spot Evaluation Method Based on Combined Weight Coefficient Method—A Case Study in the BZ Oilfield, China

The Sha3 member of the BZ Oilfield in Bohai Sea represents a typical ultra-low permeability thin interbedding reservoir. Hydraulic fracturing is an effective method for increasing oil and gas production. However, the complex geological conditions make it difficult to screen out the optimal frac spot. Consequently, the design of hydraulic fracturing exhibits certain limitations. A novel method for evaluating sweet spots is proposed, based on a refined geological reservoir model that considers the varying degrees of influence that geological and engineering factors have on fracturing effectiveness. This method utilizes grey correlation and hierarchical analysis to quantify and characterize the weight coefficients of each factor, ultimately leading to a combined weight coefficient approach. The results indicate that permeability and fracturing scale are the primary factors that impact the post-frac production of the BZ oilfield, with their respective combined weights being 0.33 and 0.25. The average weight for geological factors is 0.18, while for engineering factors it is 0.15. This suggests that geological factors have a greater influence on production than engineering factors. Furthermore, the correlation coefficient between the dual sweet spot index and the production is 0.96, indicating a strong positive correlation between the two variables. After comparing the predicted and actual production of each well, it was determined that the anastomosis rate is 80%. This finding holds significant guiding significance for selecting the optimal fracturing spot.

Geochemical Characteristics and Origin of Natural Gas in the Middle of Shuntuoguole Low Uplift, Tarim Basin: Evidence from Natural Gas Composition and Isotopes

Multiple types of reservoirs, including volatile oil reservoirs, condensate gas reservoirs, and dry gas reservoirs, have been discovered in ultra-deep layers buried at depths greater than 7500 m. Understanding the genetic types of natural gas is of utmost importance in evaluating oil and gas exploration potential. The cumulative proved reserves of the super deep layer in the Shuntuoguole low uplift area of the Tarim Basin exceed 1 × 108 t (oil equivalent). The origin, source, and accumulation characteristics of natural gas still remain a subject of controversy. By analyzing the composition and carbon isotope of natural gas, a detailed investigation was conducted to examine the unique geochemical and reservoir formation characteristics of the Ordovician ultra-deep natural gas within different fault zones in the middle region of the Shuntuoguole low uplift. It was determined that most of the natural gas in this area is displaying a characteristic of wet gas with a drying coefficient ranging from 0.41 to 0.99. The carbon isotope composition of methane in the gas reservoir shows relatively light values, ranging from −49.4‰ to −42‰. The carbon and hydrogen isotopes of the components are distributed in a positive order. The natural gas is oil type gas, which is derived from marine sapropelic organic matter and has a good correspondence with the lower Yuertusi formation. The maturity of natural gas in Shunbei No. 1 and No. 5 fault zones is about 1.0%, which is the associated gas of normal crude oil, while the maturity of No. 4 and No. 8 fault zones is higher than 1.0%, which is the mixture of kerogen pyrolysis gas and crude oil pyrolysis gas. The variations in the drying coefficient and carbon isotope composition of the natural gas provide evidence for the migration patterns within the Shuntuoguole low uplift central region. It indicates that the Shunbei No. 5 and No. 8 fault zones have likely migrated from south to north, while the No. 4 fault zone has migrated from the middle to both the north and south sides. These migration patterns are primarily controlled by high and steep strike-slip faults, which facilitate the vertical migration of natural gas along fault planes. Consequently, the gas accumulates in fractured and vuggy reservoirs within the Ordovician formation.

Control of Asphaltene Damage by In Situ Preparation of α-Fe2O3 Nanoparticles in Reservoir Model Oils: Miscible Displacement in Low-Perm Carbonates at Typical Reservoir Pressure and Temperature

Control of Asphaltene Damage by In Situ Preparation of α-Fe₂O₃ Nanoparticles in Reservoir Model Oils: Miscible Displacement in Low-Perm Carbonates at Typical Reservoir Pressure and Temperature

A study on the accumulation model of the Santos basin in Brazil utilizing the source–reservoir dynamic evaluation method

The exploration potential within deep-water petroliferous basins holds great promise for oil and gas resources. However, the dearth of geochemical and isotopic data poses a formidable challenge in comprehending the intricate hydrocarbon charging processes, thereby impeding the comprehensive understanding of hydrocarbon accumulation mechanisms and models. Consequently, the establishment of robust source–reservoir relationships in deep-water petroliferous basins represents a pivotal challenge that significantly influences the exploration strategies and the comprehension of hydrocarbon enrichment dynamics within such basins. In this study, we introduce a novel approach, termed the “source–reservoir dynamic evaluation method,” tailored to investigate reservoir accumulation models in deep-water petroliferous basins. This method uses basin simulation technology to recover the thermal evolution history and hydrocarbon generation and expulsion history of source rocks, and on this basis delimits the hydrocarbon kitchen range. At the same time, the maturity of source rocks corresponding to crude oil and natural gas in typical reservoirs is calculated. Then, when the thermal evolution degree of source rocks adjacent to the reservoir reaches this maturity, the corresponding geological period is the main charging period of hydrocarbon. As a typical deep-water petroliferous basin, the Santos Basin in Brazil has abundant oil and gas reservoirs under the thick salt rock, but there are still some fundamental problems such as unclear oil–gas accumulation process and model. Therefore, in this paper, the main charging periods of typical hydrocarbon reservoirs are determined based on the internal relationship between the thermal evolution history of the main source rocks and the maturity of crude oil and natural gas, and then the hydrocarbon accumulation process is analyzed and the dynamic accumulation model is established. Finally, the favorable prospecting direction is pointed out. The results show that the oil and gas in the Barra Velha Formation in the Santos basin are mainly derived from the Itapema Formation lacustrine shale source rock, and the source rock is mainly developed in the Eastern Sag of the Central Depression, and its main hydrocarbon generation period is from the deposition period of Florianopolis Formation to the deposition period of Santos Formation. The main hydrocarbon expulsion period was from the deposition period of the Santos Formation to the Early deposition of the Iguape Formation. The oil and gas in the Barra Velha Formation were mainly charged from the Late deposition period of the Santos Formation to the Early deposition period of the Iguape Formation. During this period, the hydrocarbon migrated vertically along the normal fault formed in the rift period to the trap of the adjacent inheritance structural highs and accumulated in the reservoir, which was dominated by the accumulation model of the “lower generation-upper reservoir-salt cap”. Since the Barra Velha Formation has the characteristics of near-source accumulation, based on the hydrocarbon expulsion center and hydrocarbon expulsion intensity of the source rock of the Itapema Formation, the distribution ranges of 85% and 50% Pre-salt accumulation probability in the Santos basin were calculated by using the quantitative analysis model of the hydrocarbon distribution threshold. It is suggested that the next oil and gas exploration should be carried out in the paleo-structural highs and slope of Class I favorable area (the hydrocarbon accumulation probability is more than 85%) and Class II favorable area (the hydrocarbon accumulation probability is 85–50%).

An accurate identification and spatial characterization method for the development degree of preferential flow paths in water-flooded reservoir

Water flooding is one of the most important methods for oil field development, It accounts for more then 70% of China's crude oil production. However, in the progress of water flooding, preferential flow paths often formed between oil and water wells, which seriously restricts production rate. How to effectively identify the preferential flow paths has become the key to improving the effect of water flooding. In this paper, to solve the problem of difficult identification of preferential flow paths in reservoirs, through the change of core seepage law with high pore volume water flooding experiment, parameters such as multiple of water flux, change value of permeability, and water saturation were selected for analysis. The weight coefficient for each parameter was determined by the variation coefficient method of objective weight. Subsequently, a comprehensive reservoir identification index was obtained by weighting each parameter, which was used to describe the development degree of the preferential flow paths. Finally, quantitative criteria of preferential flow paths were given. The spatial characterization of preferential flow paths was realized by post processing of the Eclipse software. The new method for identifying preferential flow paths fully considers the changes in physical properties and fluid mobility of water-flooded reservoirs. The results of the new applied to a typical water-flooded reservoir in the Bohai Bay Basin show that the preferential flow paths calculated by the new method were highly consistent with the judgment results of tracers. It can accurately and quickly identify the preferential flow paths. This study provides a scientific basis for adjusting measures of water-flooded reservoirs to further enhance oil recovery. Moreover, the new method holds broader prospects for application in the field of porous media transport.

Sedimentological and diagenetic facies of tight sandstones in lacustrine delta-front: A case study of the Jurassic Lianggaoshan Formation, eastern Sichuan Basin

In this study, taking the Jurassic Lianggaoshan Formation (J1l) tight sandstones in the eastern Sichuan Basin as an example, the types and well-logging responses of main sedimentological and diagenetic facies in the lacustrine delta-front are investigated based on summarizing the sedimentary characteristics and reservoir properties. Subsequently, further validation and application are conducted in the study area through machine learning. Research results show that the J1l lacustrine delta-front in the eastern Sichuan Basin mainly develops subaqueous distributary channels and mouth bar sand bodies, exhibiting typical densification reservoirs, with porosity and permeability distributed between 0.48% and 11.24% (av. 3.87%) and 0.0003–0.653 × 10−3 μm2 (av. 0.026 × 10−3 μm2), respectively. Strong compaction and strong cementation are the primary factors leading to densification, whereas chlorite coatings and weak dissolution play constructive roles in preserving some primary pores, creating a small amount of dissolution pores, and enhancing permeability. In terms of manifestation, the pore-throat content with a radius greater than 0.006 μm governs the reservoir quality. Furthermore, five types of diagenetic facies are identified in the J1l subaqueous distributary channels and mouth bars: strong compaction facies (Type I), strong cementation facies (Type II), chlorite-coating and intergranular pore facies (Type III), weak dissolution and intragranular pore facies (Type IV), and medium compaction and cementation facies (Type V). Overall, the thick and coarse-grained subaqueous distributary channels can be considered as the preferred exploration targets for tight oil and gas, with type III and type IV diagenetic facies being the most favorable reservoirs, characterized by well-logging responses of high AC and low GR, DEN, and RT. Based on the fine division of sedimentological and diagenetic facies, establishing well-logging interpretation models and then employing machine learning to achieve sweet spot reservoir prediction can provide valuable insights for tight oil and gas exploration in regions lacking core data.

Comparison of Pore Structure Characteristics of Shale-Oil and Tight-Oil Reservoirs in the Fengcheng Formation in Mahu Sag

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.

Permeability Upscaling Conversion Based on Reservoir Classification

Deep and ultra-deep reservoirs are characterized by low porosity and permeability, pronounced heterogeneity, and complex pore structures, complicating permeability evaluations. Permeability, directly influencing the fluid production capacity of reservoirs, is a key parameter in comprehensive reservoir assessments. In the X Depression, low-porosity and low-permeability formations present highly discrete and variable core data points for porosity and permeability, rendering single-variable regression models ineffective. Consequently, accurately representing permeability in heterogeneous reservoirs proves challenging. In the following study, lithological and physical property data are integrated with mercury injection data to analyze pore structure types. The formation flow zone index (FZI) is utilized to differentiate reservoir types, and permeability is calculated based on core porosity–permeability relationships from logging data for each flow unit. Subsequently, the average permeability for each flow unit is computed according to reservoir classification, followed by a weighted average according to effective thickness. This approach transforms logging permeability into drill stem test permeability. Unlike traditional point-by-point averaging methods, this approach incorporates reservoir thickness and heterogeneity, making it more suitable for complex reservoir environments and resulting in more reasonable conversion outcomes.

Research advances on the mechanisms of reservoir formation and hydrocarbon accumulation and the oil and gas development methods of deep and ultra-deep marine carbonates

Based on the new data of drilling, seismic, logging, test and experiments, the key scientific problems in reservoir formation, hydrocarbon accumulation and efficient oil and gas development methods of deep and ultra-deep marine carbonate strata in the central and western superimposed basin in China have been continuously studied. (1) The fault-controlled carbonate reservoir and the ancient dolomite reservoir are two important types of reservoirs in the deep and ultra-deep marine carbonates. According to the formation origin, the large-scale fault-controlled reservoir can be further divided into three types: fracture-cavity reservoir formed by tectonic rupture, fault and fluid-controlled reservoir, and shoal and mound reservoir modified by fault and fluid. The Sinian microbial dolomites are developed in the aragonite-dolomite sea. The predominant mound-shoal facies, early dolomitization and dissolution, acidic fluid environment, anhydrite capping and overpressure are the key factors for the formation and preservation of high-quality dolomite reservoirs. (2) The organic-rich shale of the marine carbonate strata in the superimposed basins of central and western China are mainly developed in the sedimentary environments of deep-water shelf of passive continental margin and carbonate ramp. The tectonic-thermal system is the important factor controlling the hydrocarbon phase in deep and ultra-deep reservoirs, and the reformed dynamic field controls oil and gas accumulation and distribution in deep and ultra-deep marine carbonates. (3) During the development of high-sulfur gas fields such as Puguang, sulfur precipitation blocks the wellbore. The application of sulfur solvent combined with coiled tubing has a significant effect on removing sulfur blockage. The integrated technology of dual-medium modeling and numerical simulation based on sedimentary simulation can accurately characterize the spatial distribution and changes of the water invasion front. Afterward, water control strategies for the entire life cycle of gas wells are proposed, including flow rate management, water drainage and plugging. (4) In the development of ultra-deep fault-controlled fractured-cavity reservoirs, well production declines rapidly due to the permeability reduction, which is a consequence of reservoir stress-sensitivity. The rapid phase change in condensate gas reservoir and pressure decline significantly affect the recovery of condensate oil. Innovative development methods such as gravity drive through water and natural gas injection, and natural gas drive through top injection and bottom production for ultra-deep fault-controlled condensate gas reservoirs are proposed. By adopting the hierarchical geological modeling and the fluid-solid-thermal coupled numerical simulation, the accuracy of producing performance prediction in oil and gas reservoirs has been effectively improved.

Hydrologic Model Prediction Improvement in Karst Watersheds through Available Reservoir Capacity of Karst

This study aimed to enhance flood forecasting accuracy in the Liangfeng River basin, a small karst watershed in Southern China, by incorporating the Available Reservoir Capacity of Karst (ARCK) into the HEC-HMS model. This region is often threatened by floods during the rainy season, so an accurate flood forecast can help decision-makers better manage rivers. As a crucial influencing factor on karstic runoff, ARCK is often overlooked in hydrological models. The seasonal and volatile nature of ARCK makes the direct computation of its specific values challenging. In this study, a virtual reservoir for each sub-basin (total of 17) was introduced into the model to simulate the storage and release of ARCK-induced runoff phenomena. Simulations via the enhanced model for rainfall events with significant fluctuations in water levels during 2021–2022 revealed that the Nash–Sutcliffe efficiency coefficient (NSE) of the average simulation accuracy was improved by more than 34%. Normally, rainfalls (even heavy precipitations) during the dry season either do not generate runoff or cause negligible fluctuations in flow rates due to long intervals. Conversely, relatively frequent rainfall events (even light ones) during the wet season result in substantial runoff. Based on this observation, three distinct types of karstic reservoirs with different retaining/releasing capacities were defined, reflecting variations in both the frequency and volume of runoff during both seasons. As a real-time environmental variable, ARCK exhibits higher and lower values during the dry and rainy seasons, respectively, and we can better avoid the risk of flooding according to its special effects.

Profundizando en la bioecología de Culex interrogator Dyar y Knab, 1906 (Diptera: Culicidae) en Camagüey, Cuba

Culex interrogator is a culicid species that has recently been reported in the insular Caribbean, first in Cuba, specifically in the province of Santiago de Cuba, and shortly afterward in the Dominican Republic. This study’s objective is to report for the first time the presence of Cx. interrogator in the Cuban province of Camagüey and investigate its larval breeding sites in the urban environment. In 2022, visual inspections were conducted in all dwellings and facilities in the municipality of Camagüey, including intra- and peridomiciliary areas in the urban and suburban regions. In each positive mosquito reservoir, as many larvae and pupae as possible were collected. A total of 30 samples positive for Cx. interrogator (n = 155 larvae) were collected from 13 types of reservoirs. Ditches were the most frequent reservoir with the species present (n = 8; 26.66%), followed by ground-level tanks and sewage pits (n = 4; 13.33% each). All positive reservoirs were located in outdoor areas of dwellings. The discovery of this mosquito species in Camagüey, with many unknown aspects of its role as a vector, highlights the need for close monitoring and in-depth study.

Characteristics and Genesis of Carbonate Weathering Crust Reservoirs: A Case from the Ma5Member of Ordovician in Gaoqiao Area, Ordos Basin, China.

The hydrocarbon reserves in carbonate rocks account for about half of the global hydrocarbon reserves and are an important reservoir type. The Ordovician Majiagou Formation in the central Ordos Basin is a representative weathering crust reservoir. The Caledonian movement uplifted the stratum as a whole, and subsequently, 120 million years of exposed weathering, denudation, and leaching created this unique karst paleomorphology. Dolomite reservoirs have developed dissolved pores and microfractures, which are the best reserved spaces for natural gas and good hydrocarbon migration channels. This paper takes the Ma5Member (hereinafter referred to as Ma51+2) carbonate reservoir in Gaoqiao Gas Field as the research target, based on the core, thin section, cathodoluminescence, logging data, etc., and systematically study the effect of karstification on the reservoir and the genesis of the dolomite reservoir. The results show that the depositional period of the Ordovician Majiagou strata is a regression cycle and the depositional environment is a limited evaporative tidal flat. The reservoir lithology of Ma51+2 is mainly gypsiferous dolomite and micrite dolomite. The reservoir space types consist of intergranular pores, gypsum mold pore, intragranular dissolution pores, intercrystalline pores, and microfractures. The porosity has values from 0.3 to 11.2% (mostly less than 5.0%) with an average of 3.3%, and the permeability ranges from 0.003 to 13.2 mD (mostly less than 1 mD) with an average of 0.36 mD. Karstification is divided into three periods, including syngenetic karst, eogenetic karst, and burial karst. The sedimentary microfacies determine the material basis of the reservoir, and multistage karstification finally modifies the physical properties. By deeply exploring the formation mechanism and influencing factors of the carbonate reservoir in the Ordovician Majiagou Formation, it provides an important theoretical basis and practical guidance for oil and gas exploration and development. At the same time, it also has important reference value for understanding and predicting the development law and distribution characteristics of carbonate reservoirs under similar geological background.

Analysis of nitrogen migration and transformation in the typical deep and large reservoir of the Lancang River — Evidence from nitrogen and oxygen isotopes

The environmental effect resulting from dam construction and the formation of large reservoirs has long been a topic of significant concern. While current research at a macro scale provides a well understanding regarding the evolution of nitrogen nutrient status in river-reservoir ecosystems, the vertical migration and transformation characteristics of nitrogen in reservoirs under changing runoff remain less defined. This study centers on a typical deep reservoir along the Lancang River-Nuozhadu (NZD) Reservoir in April and December. The monitoring reveals a distinct vertical stratification phenomenon in the NZD Reservoir in the vertical profile in April, which can be categorized into a mixed layer (ML) (0–5 m), a thermocline layer (TL) (5–40 m), and an isothermal layer (IL) (>40 m) based on the water temperature. However, little stratification in the profile is occurred in December. The results of nitrogen and oxygen isotopes in April indicate that the biochemical process of nitrogen in the NZD Reservoir is predominantly driven by nitrification. However, different nitrogen biochemical processes are coupled in various stratified regions in the vertical direction. In the ML, simultaneous assimilation of ammonia nitrogen by phytoplankton occurs. In the TL, there is a process of oxidation and decomposition of particulate organic nitrogen due to a significant stratification effect and an extended hydraulic retention time. In the region of minimal dissolved oxygen (30–40 m), simultaneous denitrification may take place. In December, the main process is nitrogen assimilation in reservoir surface (ML). Statistical analysis of environmental factors highlights water temperature (T) and dissolved oxygen (DO) as crucial environmental factors influencing nitrogen migration and transformation within the reservoir. This study suggests that in deep reservoirs experiencing vertical thermal stratification, the characteristics of DO and nitrogen migration and transformation exhibit significant vertical spatial heterogeneity. This phenomenon may lead to diverse ecological environmental effects. Future efforts should focus on enhancing the fine monitoring of stratified water bodies in deep and large reservoirs and analyzing the ecological environmental effects of material cycling in greater detail.

Experimental Study on Gas Production Capacity of Composite Reservoir Depletion in Deep Carbonate Gas Reservoirs

Deep carbonate gas reservoirs exhibit diverse reservoir types and complex seepage patterns. To study the gas production capabilities of different composite reservoir types, we classified the reservoirs of the fourth member of the Dengying Formation in the Anyue Gas Field into high-quality reservoirs (HRs) and poor-quality reservoirs (PRs) based on high-pressure mercury injection (HPMI) experiment results. By varying the differential pressure of the depletion experiment and the connection method, as well as the permeability and water saturation of the composite core, the effects of well location deployment, permeability ratio of the high-quality reservoir and poor-quality reservoir (PRHPR), gas well production pressure difference (GWPPD), and water saturation on the depletion gas production characteristics of the composite reservoir were studied. The research results show that (1) deploying wells on HR enables high gas production rates and ultimate recovery rates; (2) only when the PRHPR falls within a reasonable range (21.88–43.19) can the “dynamic recharge” capability of PR and the high permeability of HR be coordinated to achieve high gas recovery rates; (3) a GWPPD of 3 MPa is optimal, resulting in fast gas production rates and high ultimate recovery rates for PR; (4) high water saturation (≥50%) leads to premature water breakthrough at the well bottom, decreased gas production rate, and sealing of HR and PR reserves by formation water. Combining experimental results with field production data is our next research focus. Our future research focus will be on integrating experimental results with field production data to provide solid theoretical support for the efficient development of this type of gas reservoir.

Exploring geothermal resources with the CSAMT and microtremor methods: a case study in Tangquan, Jiangsu Province, China

The development of geothermal energy has received extensive attention because of global energy scarcity and environmental pollution. The Tangquan area is in the north of the Yangtze fold belt, and the lack of magmatic rock development has resulted in a low-temperature type of geothermal reservoir. There are sporadic hot springs and cold springs exposed in the study area, but the uncertain deep geological structure, unknown geothermal reservoir formation mechanism, and lack of detailed exploration data seriously restrict the exploration and development of geothermal resources in the area. Filling underground faults with water can significantly reduce electrical resistivity, while traps filled with warm water can cause a decrease in S-wave velocity. Thus, a new integrated geophysical method, including the controlled source audio-frequency magnetotelluric (CSAMT) and microtremor methods, is applied for geothermal exploration in the region. The combination of CSAMT and microtremor methods can determine thermal-controlled and water-conducting structures more effectively and locate geothermal storage more accurately. The source, channel, storage, and cover of regional geothermal reservoir formation are analyzed using geophysical and geological data. That is, the regional NE- and NW-trending faults are explained as thermal-controlled and water-conducted structures, respectively. The deep Sinian Dengying Formation supplies a heat- and water-bearing space. The tectonic intersection area, especially the tensional fault zone, is found to be closely related to the existence of geothermal reservoirs, which is well verified by later drilling results. Finally, a geothermal reservoir model is established to comprehensively understand the distribution of geothermal energy in the region.

A novel method to identify preferential flow paths by considering the time-varying effect of petrophysical parameters in ultra-high water-cut reservoirs

The continental clastic reservoirs mainly distributed in the eastern region of China are regarded as the “ballast stone” for ensuring national energy security. After long-term waterflooding, reservoir petrophysical parameters have changed drastically. When the ultra-high water-cut period is achieved, the preferential flow paths are widely distributed inside the reservoir, resulting in severe ineffective water circulation and high difficulty in inhibiting water cut rise and stabilizing oil production. Due to the slow calculation speed and low identification accuracy of the existing methods, it is crucial to propose a novel method to identify preferential flow paths by considering the time-varying impact of petrophysical parameters in ultra-high water-cut reservoirs. To tackle this issue, massive dynamic and static data are collected from typical water-drive reservoirs in the Daqing oilfield to analyze the dynamic characteristics of preferential flow wells and the time-variation laws of reservoir parameters. A rapid evaluation index system for preferential flow paths is thereafter established. By describing the time-variation of reservoir permeability and fluid apparent viscosity and introducing a dynamic flow resistance coefficient to infer the inter-well or inter-layer connectivity, a novel method with the time-varying effect of petrophysical parameters considered is developed to quickly identify preferential flow paths in ultra-high water-cut reservoirs. A critical criterion of preferential flow paths is further constructed. Finally, the proposed method is used to determine the spatial distribution of preferential flow paths in a typical block of the Daqing oilfield. Results demonstrate that, once a preferential flow path is formed, some distinct dynamic characteristics of injectors and producers will be exhibited. Based on the estimated dynamic flow resistance coefficient, the preferential flow paths are further classified into four types: non-preferential, primary preferential, intermediate preferential, and strong preferential flow paths. Using the proposed method, the identification accuracy of preferential flow paths exceeds 95%, and the identification speed is more than 10 times faster than the traditional methods.