FETKOVICH proposed the water influx rate equation in finite aquifer and the type curve with constant pressure in 1971 and 1980 respectively, which have been widely recognized and cited by experts both domestically and internationally. His methodology allows for the determination of a well's drainage radius and area by fitting actual production data to his type curve, a technique that has gained popularity among field experts. The derivation of this paper shows that the equation for water influx rate equation in finite aquifer of FETKOVICH is an is characterized by an exponential decline, a model he directly applied to analyze production declines in wells with volumetrically closed boundaries. He derived a dimensionless time for the type curve based on the relationship with the initial decline rate and used the inverse of dimensionless pressure as a proxy for dimensionless production to develop the type curve's dimensionless production profile. However, it's important to note that FETKOVICH's model does not establish a direct functional relationship between dimensionless time and dimensionless production in the type curve model, which means that a comprehensive dimensionless type curve cannot be formulated directly from his equations. This article deduces the water influx rate equation in finite aquifer and the dimensionless time and dimensionless production of the type curve, and questioned and commented on the existing problems.

In the past two decades, Sinopec Northeast Oil & Gas Company has made significant strides in exploring the southern Songliao Basin, revealing that the basin's volcanic rocks present a new and promising avenue for hydrocarbon exploration. According to the exploration practice of the basin, the company has developed a comprehensive four-component coupling reservoir control model specific to fault depressions. This model emphasizes the interconnected evolution of key elements such as hydrocarbon generating foci, reservoir formation periods, paleostructure, fault cap preservation, and effective reservoirs, with a particular focus on the main accumulation period. This strategic approach led to the significant discovery of a large-scale volcanic gas reservoir within the Huoshiling Formation in the Changling fault depression, located in the Songnan area. Consequently, the exploration focus has broadened from the Yingcheng Formation to the Huoshiling Formation, diversifying the exploration targets from acidic volcanic rocks to intermediate-basic volcanic rocks, and extending from subaerial to submarine eruptions. By using the technique of fine gas reservoir description, the integration of modeling, numerical modeling and geological engineering, the productivity breakthrough has been achieved in several wells in Songnan fault depression, and the efficient development and large-scale production of volcanic gas reservoir has been realized.

Industrial oil and gas have been found in the volcaniclastic rocks of the Huoshiling Formation erupted underwater in the continental lacustrine basin of the Changling fault depression in the Songliao Basin, which has broad exploration prospects. The study focuses on the reservoir space characteristics, physical properties and pore structure differences of the underwater eruption pyroclastic rock reservoirs in the Huoshiling Formation, and analyzes the reasons for the differences in physical properties of different types of reservoirs and their formation and evolution processes. There are mainly the following four aspects: ① Tuff, with its high volcanic glass content, predominantly features devitrification and dissolution pores as its main reservoir spaces. Coarser particle sizes in tuff correlate with improved physical properties, including larger and more abundant pores. Sedimentary tuff, rich in clay minerals, exhibits mainly interstitial spaces between these minerals and poorer physical properties. Tuffaceous sandstone, with high levels of soluble components like feldspar, debris, and laumontite, is characterized by dissolution pores. ② The average porosity is 2.43%, and the average permeability is 0.076×10^-3 μm². Coarse-grained tuff exhibits the highest porosity, followed by tuffaceous sandstone and fine-grained tuff, with sedimentary tuff displaying the poorest physical properties. ③ Devitrification significantly contributes to the high porosity yet ultra-low permeability observed in tuff reservoirs. Organic acid dissolution during the middle diagenesis stage, resulting from two separate oil and gas fillings, further enhances porosity. Additionally, fractures serve as conduits for organic acids and deep hydrothermal fluids, promoting further dissolution that connects dispersed dissolution pores and enhances reservoir space effectiveness. ④The coarse-grained tuff reservoir in the near-source facies gas-carrying subaqueous pyroclastic flow subfacies is a favorable target for oil and gas exploration.

The binomial productivity equation is a pivotal tool for analyzing data in gas reservoir development, typically resolved using well test data. However, in tight volcanic gas reservoirs, the pressure remains stable and changes slowly, which can lead to challenges during productivity well tests. Specifically, the indication curve generated from measured data may have an intercept less than 0, rendering the equation unsolvable in its standard form, thereby necessitating a correction to the formula. Taking the Well-C2 of tight volcanic gas reservoir as an example, the reason of abnormal indication curve is analyzed. By reviewing and adapting existing equation correction methods, the bottom hole flowing pressure data from the productivity test well is adjusted, leading to the derivation of a new corrected binomial productivity equation. It is applied to the tight volcanic gas well, and the result is more stable than the result of single-point method. It can fully leverage the well test data and provide the basis for the calculation of open flow capacity and the formulation of subsequent development and production plan.

Anisotropic parameter inversion based on pre-stack azimuth gather seismic data is one of the primary methods for fracture prediction, among which two algorithms, RüGER approximate equation and Fourier series expansion, are more widely used. Both the anisotropic gradient in the RüGER approximate equation and the second-order term in the Fourier series expansion can characterize the crack intensity. In the experiment, the applicability of applying this two equations was compared in the single-layer interface and the fracture layer of the actual drilled wells, respectively, and the fracture spatial prediction results were compared in the actual volcanic rock development zone. There are dimensional differences in the prediction of fracture strength between the two equations of single interface model. The range of fracture strength of RüGER approximation equation is larger than that of Fourier series expansion. Multiple results exist for the calculation of fracture orientation using the RüGER approximation equation, which may result in an orientation perpendicular to the fracture. However, when applied to the fractured layers observed in wells, both methods yielded broadly consistent results regarding fracture orientation and strength. In the application to the volcanic rock formation of the LFS area in the southern Songliao Basin, the Fourier series' second-order term slightly outperformed the RüGER equation in aligning with the fracture strength interpretations derived from electrical imaging logging. Additionally, the predicted fracture orientations from both methods matched those interpreted from imaging logging. It is concluded that the Fourier series equation for predicting fractures is more suitable for popularization and application in the field of volcanic rocks.

Currently, the most widely used pre-stack simultaneous inversion algorithm is based on the Zoeppritz equation approximation of isotropic horizontal media. This method, however, encounters challenges in medium-basic volcanic reservoirs characterized by rapid lateral lithological changes and vertical multi-period stacking. In such environments, tuffs and sedimentary tuffs exhibit similar logging and geophysical responses, complicating the distinction of lithology and physical properties of volcanic rocks through pre-stack simultaneous inversion. To address these challenges, qualitative analyses were conducted on the seismic response characteristics of volcanic reservoirs using convolutional model forward modeling. Additionally, well rock physics was employed for physical analyses of lithology and sensitive parameters pertinent to volcanic reservoirs. Comparative analyses of six binomial and trinomial pre-stack inverse algorithms, aimed at approximating the Zoeppritz equation in the specific area, were conducted through model calculations and actual data assessments. Based on these comprehensive analyses, the approximate algorithms developed by SMITH & GIDLOW and FATTI were identified as preferable choices. These algorithms use the reflection coefficients of P-wave impedance, S-wave impedance, and density as inputs for pre-stack inversion. The inversion results for P-wave impedance were utilized to predict the presence of local tuff, while the inversion outcomes for density were employed to ascertain the effective reservoir physical properties. The efficacy of this approach was validated through the deployment of an evaluation well and a horizontal well, which yielded predicted compliance rates of 76.0% and 84.6%, respectively.

In the Chaganhua Gas Field within the Songnan Fault Depression, the Huoshiling Formation's volcanic reservoirs exhibit an average porosity of 4.5% and a permeability of 0.08×10^-3 μm, indicating a dense and highly heterogeneous nature. Due to this complexity, a comprehensive approach, testing a broad set of reservoirs, is required to establish effective classification criteria. This study used physical property data, high-pressure mercury injection, nuclear magnetic resonance, and other experiments to analyze the microstructure of volcanic reservoirs. Through multi parameter comparison, a microscopic classification standard was established. Nuclear magnetic logging served as a bridge between microscopic and macroscopic parameters, facilitating the creation of a comprehensive evaluation framework for classifying volcanic reservoirs. This framework encompasses microscopic structural features such as pore throat radius, displacement pressure, mercury saturation, alongside macroscopic parameters obtained from nuclear magnetic logging and other experiments, such as the T2 spectrum distribution, centrifugal saturation, porosity, permeability, saturation, acoustic time difference, lithology density, and resistivity. Reservoirs are categorized from high to low quality into classes A, B, and C based on this comprehensive set of criteria. This method has strong operability and provides a reliable basis for the testing plan of new drilling and the optimization of sweet spots in exploration and development of horizontal wells. The research methods and understanding have certain reference significance for the classification research of volcanic reservoirs.

To explore the intricate relationship between volcanic rock types, volcanic facies, and genetic models within the Yingcheng Formation of the Songliao Basin, and to understand their implications for oil and gas exploration, a comprehensive analysis was conducted using a wide array of geological data. This included field outcrops, drilling data, and rock slices, allowing for the identification of volcanic rock types, classification of volcanic facies, and analysis of the genesis characteristics of these facies. It is concluded that: ①Four types of volcanic rocks are developed in Yingcheng Formation, which are lava, pyroclastic lava, pyroclastic rock, and clastic sedimentary rock; ②The outcrops of Yingcheng Formation are divided into five lithofacies types,which are crater facies-volcano channel type, crater-post volcanic type, near crater-volcano slope type, volcanic slope type and volcanic dome type; ③Two genetic modes of volcanic facies, crater accumulation genetic mode and volcanic slope genetic mode, are established.

Represented by the integrated oilfield of the continental sandstone reservoir in Shengli Oil Zone, the main unit of which has entered the late stage of ultra-high water cut（>95%）. This stage has led to significant challenges, including extreme water consumption in certain areas, a sharp increase in the water-to-oil ratio, a marked decline in the utilization rate of injected water, rising operating costs per ton of oil, and diminishing economic returns. Despite these issues, approximately 60% of the remaining geological reserves are still present in the reservoir, making the widespread drilling of new wells economically unfeasible. The primary obstacles to profitable development at this stage include the preferential flow of injected water through zones of extreme water consumption and limited dynamic sweep efficiency. Addressing the identification, description, and management of these extreme water consumption zones is crucial for achieving profitable development in maturing oilfields with ultra-high water cuts. This paper suggests a comprehensive approach to tackle these challenges. It involves understanding the formation and control mechanisms of extreme water consumption zones, characterizing reservoir heterogeneity based on configuration and lithology, quantitatively describing the distribution of these zones, and devising strategies to regulate their expansion using variable streamlines in existing wells. The goal is to develop a suite of profitable development technologies that enable precise reservoir characterization and effective management of extreme water consumption zones in the late ultra-high water cut stage. Traditionally, a reservoir with a 98% water cut is considered nearly depleted. However, by applying key technologies for flow field regulation and benefit enhancement to a demonstration unit within such a reservoir, its economic lifespan can be extended by over a decade. This approach can stabilize annual oil production, reduce water cut, lower operating costs per ton of oil, and facilitate low-cost development in maturing oilfields at the late ultra-high water cut stage, thereby addressing the economic and operational challenges inherent in this phase of development.

The structural and mechanical characteristics of carbonate rock under the action of chemistry and mechanics is an important research topic for the evaluation of the effectiveness of acid fracturing technology in this kind of reservoir. This research focused on the impact of 20% HCI gelled acid on the structural and mechanical properties of carbonate rocks, categorized into four types based on their mineral composition: limestone, dolomite-bearing limestone, limestone-bearing dolomite, and dolomite. The experiments revealed distinct reactions of these rock types to acid exposure. Limestone exhibited uniform etching, while dolomite-bearing limestone showed selective etching, creating wormhole-like grooves. Limestone-bearing dolomite and dolomite predominantly experienced point etching and erosion along structural planes. Initially, the shear failure of carbonate rocks was primarily governed by matrix strength. However, acid treatment altered their internal structure, making them more susceptible to tensile stress damage, leading to potential splitting or destruction along structural planes. Notably, the reduction in the macroscopic strength of the carbonate rocks post-acid treatment was significantly greater than the decrease in matrix strength alone. The invasion of acid liquid into the rocks introduced additional microscopic defects, evidenced by a reduced proportion of elastic energy and an increased proportion of dissipated energy at peak stress levels. This suggests that the macroscopic mechanical property deterioration results from both matrix strength weakening and internal structural changes. These findings offer valuable insights for field acid fracturing operations in carbonate rock reservoirs and aid in the planning of subsequent production strategies

The production of BG shale oil Block of Jinhu Sag of Subei Basin declines rapidly after fracturing, showing poor development efficiency. Enhancing the estimated ultimate reserves（EUR） of individual wells during later depletion stages is crucial for profitable development. While CO₂ huff-n-puff is a common stimulation technique, its high costs and variable effectiveness have limited its widespread adoption. Based on the geological characteristics of BG block, we carried out research on the mechanism of shale oil stimulation by water huff-n-puff by using core NMR, SEM, well test analysis and other methods, and clarified that water huff-n-puff can greatly develop the oil in 1~100 nm pores in imbibition process and improve the porosity and permeability conditions. Given the Subei Basin shale oil's notable hydrophilicity, rich oil content, and extensive fracture network, water huff-n-puff technology was proposed and field-tested. Up to now, the cumulative oil increase of the two test wells is more than 7 600 tons, which shows good application prospects and economic benefits. And it has guiding significance for the low-cost and efficient production stimulation in the shale oil development in Subei Basin.

The utilization of hydrate-based capture and storage of CO₂ presents a promising avenue for substantial emissions reduction, contributing significantly to achieving carbon neutrality goals and addressing climate change. This paper delves into the foundational aspects of gas hydrates, including their properties, formation mechanisms, and models, as well as hydrate synthesis within porous media and the use of molecular dynamics simulations for understanding hydrate formation. Key challenges identified in the synthesis process of gas hydrates include the limited solubility of CO₂ in porous media, which poses a significant hurdle in precisely determining the storage capacity of CO₂ hydrates. Additionally, the local structural mechanisms, particularly nucleation processes involved in gas hydrate formation, are highlighted as complex areas that warrant further investigation. The paper also evaluates the potential of coal-bearing strata, especially in high-latitude and permafrost regions, as viable underground repositories for CO₂ storage via hydrate formation. This approach not only offers a method for reducing atmospheric CO₂ levels but also leverages the unique geological characteristics of these regions to enhance the efficiency and stability of CO₂ storage. In summary, while hydrate-based CO₂ capture and storage technologies hold considerable promise for climate change mitigation, addressing the scientific and technical challenges identified in this review is crucial for advancing the field and optimizing the efficacy of this storage method.

With the convergence of global carbon neutrality goals, the CCUS industry has ushered in new opportunities after a century of development. Developed countries in Europe and America have vigorously supported the research and development of CCUS technologies and the promotion of engineering demonstrations through measures such as carbon markets, carbon taxation systems, carbon subsidies or rebates, and carbon border adjustment mechanisms. The embryonic form of CCUS industrialization has emerged, with broad market prospects. Compared to foreign countries, China's CCUS-related policies and regulations are mainly guiding in nature, with the scale of the carbon market and carbon price levels still at relatively low levels, urgently requiring strengthened research on CCUS policy and regulatory formulation and supporting measures. Therefore, we define the input-output framework of CCUS projects, sort out the economic benefits and fiscal taxation policy environment of typical CCUS projects in the world, and put forward suggestions on the development of CCUS industrial benefits in China. The analysis shows that foreign projects generally receive direct subsidies from the government, with capture costs accounting for 70% to 80% of operating costs. Environmental costs mainly include environmental risks after CO₂ leakage and additional emissions generated after installing CCUS. Output benefits include direct and indirect benefits, and under conditions where gas prices exceed 200 RMB per ton, CO₂ enhanced oil recovery projects are difficult to achieve economic benefits. In conjunction with a comparative analysis of the current status of CCUS policies and regulations at home and abroad, suggestions for the development of CCUS industrialization are proposed, such as accelerating the pace of technological research and development iterations, increasing the construction of CCUS cluster hub centers, and promptly issuing progressive and combined CCUS policies and regulations..

In the southwestern Tarim Basin, studies on the paleo-uplift and shelf divergence have focused on the sedimentary evolution and sequence filling during the Cambrian period. This research used zircon U-Pb dating and well-seismic technologies. The findings indicate that Cambrian deposits overlay the basin's basement structures, particularly in the Bachu uplift area. The Cambrian sedimentation patterns closely mirror the underlying basement tectonics. Influenced by these tectonics, along with tectonic movements and sea-level changes, four distinct sequences emerged in the Cambrian: the Yuertusi to Xiaoerbulake formations, the Wusonggeer to Shayilike formations, the Awatage Formation, and the Lower Qiulitage Formation. Additionally, seven sedimentary facies and ten depositional sub-facies were identified. From the first to the third Cambrian sequence, spanning the early to middle Cambrian, the area transitioned from a platform to a gentle slope, then to a steeper slope and finally to a deep shelf. This progression indicates a retreat towards the sea, fostering the development of Cambrian source rocks. In the late Cambrian, during the fourth sequence, the southwestern Tarim Basin transformed into a restricted platform. This period marked the establishment of the sedimentary framework in the Tarim Basin, with distinct eastern basin and western platform regions.

Since the discovery of the Ordovician weathering crust gas reservoir in the Ordos Basin in 1989, there has been notable progress in exploring the gas reservoir within the fifth member of the Majiagou Formation. However, the impact of the central paleo-uplift on the Majiagou Formation's deposition and reservoir characteristics in the Fuxian area remains underexplored. This gap in knowledge hampers oil and gas exploration efforts in the Lower Paleozoic strata of this region. Research into the stratigraphy, sedimentary microfacies, and karst development patterns of the Ordovician Majiagou Formation in the Fuxian area has shed light on how the central paleo-uplift influenced the area's geological deposition. This influence extends to the distribution of lithofacies and sedimentary microfacies as well. Findings indicate that the central paleo-uplift's effects on the Majiagou Formation in the Fuxian area have a legacy, with the formation's thickness varying significantly across different directions-thicker in the north and east, and thinner in the south and west. Further analysis of sedimentary microfacies reveals that the edges of the paleo-uplift were areas of strong hydrodynamic activity, leading to the formation of sheet-like intra-platform and tidal marginal beaches. The development of the Ordovician weathering crust is intricately linked to the central paleo-uplift's shape, structure, evolutionary history, and preservation conditions. The evolution of this uplift played a crucial role in both the development and preservation of the Ordovician karst system.

The BZ oilfield in Bohai, known for its buried hill carbonate reservoir, is currently in the middle to late stages of development. The reservoir is characterized by strong heterogeneity and a complex distribution of fractures and vugs, leading to challenges such as complicated production behavior, rapidly declining output, and significant discrepancies in the estimation of dynamic and static reserves. To address these issues, a comprehensive set of criteria for identifying different types of carbonate reservoirs in the oilfield was developed. This was based on conventional well log data, thin section analyses, limited core data, and information from well tests and production characteristics. The reservoirs were categorized into three main types: fracture, fracture-vuggy, and porous. A detailed three-dimensional numerical well-testing model was created to accurately predict high-quality reservoir zones. This model took into account the reservoir's horizontal and vertical heterogeneity, allowing for precise delineation and assessment of the reservoir boundaries and connectivity in complex wells. It also facilitated a more accurate evaluation of the dynamic reserves and confirmed the oil and gas potential in the submerged mountains at the boundary of the Archaean group. This comprehensive approach laid the groundwork for devising strategic adjustments during the latter stages of the oilfield's development. It guided field modifications aimed at maximizing the reservoir's potential, ultimately leading to validated high production outcomes.