Search Results (28)

With the rapid development of the coalbed methane (CBM) industry in China, coal seam No. 8 of the Benxi Formation in the Ordos Basin has emerged as a key target for CBM development due to its abundant deep reserves. However, wellbore instability during deep CBM extraction has become increasingly problematic, with the degradation of coal mechanical strength caused by drilling fluid invasion being identified as a critical factor affecting drilling safety and operational efficiency. This study focuses on coal seam No. 8 of the Benxi Formation in the Sulige Gas Field, Ordos Basin. Through experimental analyses of the coal’s mineral composition, microstructure, hydration expansion properties, and mechanical strength variations, the mechanism underlying drilling fluid invasion-induced mechanical strength degradation is elucidated. The experimental results reveal that coal seam No. 8 of the Benxi Formation exhibits a high carbon content and a low absolute clay mineral content (approximately 6.11%), with minimal expansive minerals (e.g., mixed-layer illite–smectite accounts for 26.4%). Consequently, the coal demonstrates a low linear expansion rate and weak hydration dispersion properties, indicating that hydration expansion is not the dominant mechanism driving mechanical strength degradation. However, drilling fluid invasion significantly reduced coal’s Young’s modulus (from 1988.1 MPa to 1676.1 MPa, a 15.69% decrease) and compressive strength (from 7.9 MPa to 6.5 MPa, a 17.72% drop), while markedly affecting its internal friction angle. Friction coefficient tests further demonstrate that the synergistic action of water molecules and additives decreases microcrack sliding resistance by 19.22% with simulated formation water and by 25.00% with drilling fluid, thereby promoting microcrack propagation and failure. This process ultimately leads to a degradation in mechanical strength. Hence, the enhancement of sliding effects induced by drilling fluid invasion is identified as the primary factor contributing to coal mechanical strength degradation, whereas hydration expansion plays a secondary role. To mitigate these effects, optimizing the design of drilling fluid systems and selecting suitable anti-collapse additives to reduce sliding effects are critical for minimizing wellbore instability risks in coal seams. These measures will ensure safer and more efficient drilling operations for deep CBM extraction. Full article

Polymer flooding is a critical enhanced oil recovery technique; however, the development of polymer channeling along dominant channels during its later stages can adversely affect the process by increasing comprehensive water cut and dispersing remaining oil, thereby diminishing development benefits. This study aims to address this challenge by investigating the identification methods and distribution patterns of dominant channels in polymer flooding to inform and optimize the development strategy. Through a series of experiments, we analyzed how factors such as permeability, heterogeneity, reservoir thickness, and mineral composition influence the formation of dominant channels. We developed an identification method for dominant channels post-polymer flooding using a combination of reservoir engineering and mathematical analysis techniques. Our results highlight the significant role of rock and mineral composition, injection rate, and injection pressure in the formation of dominant channels. By integrating formation physical properties and production data from oil and water wells with the grey correlation method, we effectively identified dominant channels. This identification is crucial for guiding the development and adjustment of polymer flooding, enhancing oil recovery efficiency, and maximizing reservoir performance. Full article

The Sulige Gas Field is a typical low-permeability, low-pressure tight gas field, where pneumatic jetting is crucial for production. However, existing gas jet pumps have low efficiency, limiting field production and overall development. This paper explores the effect of adding water, at specific volume fractions, to the driving gas on pneumatic jet pump performance. Using Volume of Fluid (VOF) and Computational Fluid Dynamics (CFD) simulations, a three-dimensional fluid domain model was developed to analyze the flow field, turbulent kinetic energy, and energy conversion in the pump. Results show that the water volume fraction significantly impacts pump efficiency, with performance improving over natural gas as the driving medium. The optimal performance occurs at a 0.5 water volume fraction, with efficiency exceeding 40% and a dimensionless mass flow ratio of approximately 2.0. As the volumetric fraction of water increases, the optimal working point of the jet pump (the dimensionless mass flow ratio corresponding to the peak pump efficiency) gradually decreases. It drops from 2.0 at water volumetric fractions of 0.1 and 0.5, to 1.8 at 0.8, and further to 1.5 at 1.0. These findings provide valuable insights for optimizing pneumatic jet performance in the Sulige Gas Field. Full article

Sandstone bodies are distributed across a large area in the northeastern part of the Sulige gas field in the Ordos Basin. However, the production characteristics of gas wells in different areas are significantly different, and the success rate of drilling effective reservoirs is low. Therefore, studies on the patterns of natural gas enrichment are urgently needed. In this study, from the perspective of tectonic evolution, the mudstone sonic transit time method was used to calculate the denudation thickness of the study area in the Late Cretaceous; the denudation thickness was between 820 m and 1200 m, and the paleo-tectonic map of the top of He 8, which was the main layer at that time, was restored and analyzed in comparison with the present structure at the top of He 8, revealing that tectonic evolution has a controlling effect on the migration, accumulation and dispersion of natural gas after formation. During the critical period of hydrocarbon accumulation at the end of the Early Cretaceous, the short-axis nose uplift zone remaining in the central and western regions, and the long-axis nose uplift zone remaining in the central and eastern regions were favorable areas for natural gas migration and accumulation. The up-dip direction has lithological traps, and the gas reservoirs have survived to the present day. The short-axis nose uplift zone and anticline at the western margin disappeared through tectonic adjustment; thus, the paleo-gas reservoirs that formed there were destroyed, and the natural gas was adjusted to new traps. Full article

During the development of multi-layer tight sandstone gas reservoirs in Ordos Basin, China, it has not been easy to calculate accurately the production of each individual layer in gas wells. However, production allocation provides a vital basis for evaluating dynamic reserves and drainage areas of gas wells and remaining gas distributions of gas layers. To improve the accuracy and reliability of production allocation of gas wells, a new model was constructed based on the seepage equation, material balance equation, and pipe string pressure equation. In particular, this new model introduced the seepage equation with an elliptical boundary to accurately capture the fluid flow characteristics within a lenticular tight gas reservoir. The new model can accurately calculate the production and reservoir pressure of each individual layer in gas wells. In addition, the new model was validated and applied in the Sulige gas field, Ordos Basin. The following conclusions were drawn: First, The gas production contribution rates of pay zones based on the new model are fairly close to the measurements of the production profile logging, with errors less than 10%. Second, The overall drainage area of a gas well lies among those of each pay zone, and the total dynamic reserves of the well are close to the sum of the dynamic reserves of pay zones. Third, Higher permeability may lead to higher initial gas production of the pay zone, but the ultimate gas production contributions of pay zones are affected jointly by permeability and dynamic reserves. Finally, The new model has been successfully applied to the SZ block of the Sulige gas field, in which the fine evaluation of dynamic reserves, drainage areas, gas production, recovery factors, and remaining gas distributions of different layers was delivered, and the application results provide technical support for the future well placement and enhanced gas recovery of the block. Full article

Effective production prediction is vital for optimizing energy resource management, designing efficient extraction strategies, minimizing operational risks, and informing strategic investment decisions within the energy sector. This paper introduces a Dual-Stage Attention Temporal Convolutional Network (DA-TCN) model to enhance the accuracy and efficiency of gas production forecasting, particularly for wells in tight sandstone reservoirs. The DA-TCN architecture integrates feature and temporal attention mechanisms within the Temporal Convolutional Network (TCN) framework, improving the model’s ability to capture complex temporal dependencies and emphasize significant features, resulting in robust forecasting performance across multiple time horizons. Application of the DA-TCN model to gas production data from two wells in Block T of the Sulige gas field in China demonstrated a 19% improvement in RMSE and a 21% improvement in MAPE compared to traditional TCN methods for long-term forecasts. These findings confirm that dual-stage attention not only increases predictive accuracy but also enhances forecast stability over short-, medium-, and long-term horizons. By enabling more reliable production forecasting, the DA-TCN model reduces operational uncertainties, optimizes resource allocation, and supports cost-effective management of unconventional gas resources. Leveraging existing knowledge, this scalable and data-efficient approach represents a significant advancement in gas production forecasting, delivering tangible economic benefits for the energy industry. Full article

Accurate production forecasting of tight gas reservoirs plays a critical role in effective gas field development and management. Recurrent-based deep learning models typically require extensive historical production data to achieve robust forecasting performance. This paper presents a novel approach that integrates transfer learning with the neural basis expansion analysis time series (N-BEATS) model to forecast gas well production, thereby addressing the limitations of traditional models and reducing the reliance on large historical datasets. The N-BEATS model was pre-trained on the M4 competition dataset, which consists of 100,000 time series spanning multiple domains. Subsequently, the pre-trained model was transferred to forecast the daily production rates of two gas wells over short-term, medium-term, and long-term horizons in the S block of the Sulige gas field, China’s largest tight gas field. Comparative analysis demonstrates that the N-BEATS transfer model consistently outperforms the attention-based LSTM (A-LSTM) model, exhibiting greater accuracy across all forecast periods, with root mean square error improvements of 19.5%, 19.8%, and 26.8% of Well A1 for short-, medium-, and long-term horizons, respectively. The results indicate that the pre-trained N-BEATS model effectively mitigates the data scarcity challenges that hinder the predictive performance of LSTM-based models. This study highlights the potential of the N-BEATS transfer learning framework in the petroleum industry, particularly for production forecasting in tight gas reservoirs with limited historical data. Full article

Depleted gas reservoirs are important places for the rebuilding of gas-storage reservoirs. In order to demonstrate the feasibility of constructing and operating such underground gas storage, a low-permeability gas-storage seepage model considering fracture development was developed and established. The model was solved using semi-analytical methods, and the pressure–response characteristics during natural gas injection were analyzed. The impact of gas injection volume on formation pressure has been clarified, and the calculation method for ultimate injection pressure has been determined. Additionally, through numerical simulation methods, the migration law of acidic gas during gas injection, the variation law of produced acidic gas concentration, and the main control factors affecting the concentration of the produced acidic gas were studied. Furthermore, measures to reduce the concentration of the acidic gas produced were proposed. Finally, injection and production plans were designed for typical depleted acidic gas reservoirs, simulating the operation of gas storage for 12 cycles. The results indicate that the quality of natural gas produced in the third cycle can meet the Class II standard for commercial natural gas. Through this study, the feasibility of constructing gas-storage facilities for acidic depleted gas reservoirs has been demonstrated, and injection and production strategies for this type of gas reservoir have been proposed. Full article

The H8 and S1 reservoirs in the lower Shihezi Formation and Shanxi Formation of the central block in the Sulige Gas Field are typical fluvial tight sandstone reservoirs. Due to frequent river channel migrations during deposition, the reservoirs exhibit complex spatial structures with developed intra-sand mudstone interlayers. As the field has entered the middle and late stages of development, the distribution of remaining gas is intricately controlled by these interlayers, necessitating research on their distribution to understand the remaining gas patterns and types for effective extraction enhancement. However, the thinness of interlayers presents a challenge for precise prediction. Addressing this, this study delineates different interlayer types and their origins, applies reservoir architecture theory, and utilizes bounding surfaces characterization, planar and sectional distribution studies, unit scale analysis, horizontal well data, and quantitative characterization methods to investigate the internal reservoir architecture bounding surfaces. The study finely portrays the interlayer distribution, analyzes the control of reservoir architecture bounding surfaces on remaining gas, and establishes a multi-tiered reservoir architecture model in the study area. Numerical simulation of the gas reservoir clarifies the types of remaining gas enrichment. This study also identifies and quantitatively characterizes the 5–3 level architecture bounding surfaces within the sandbody, categorizing the remaining gas into bounding surfaces-controlled, well-network uncontrolled, and single-layer unperforated types, proposing targeted enhancement measures for each type. Based on the findings, four vertical wells and three horizontal wells were deployed, improving the well network density to three wells per square kilometer. The first completed horizontal well encountered an effective drilling rate of 61.7%, marking significant implications for the exploitation and recovery enhancement of similar tight sandstone gas reservoirs. Full article

The Sulige gas field is a typical “three lows” (low permeability, low pressure, and low abundance) tight sandstone gas reservoir, with formation pressures often characterized by abnormally high or low pressures. The complex geological features of the reservoir further deviate from conventional understanding, impacting the effective implementation of wellbore blockage removal measures. Therefore, it is imperative to establish the wellbore blockage mechanism, prediction model, and effective prevention measures for the target area. In this study, based on field data, we first experimentally analyzed the water quality and types of blockage in the target area. Subsequently, utilizing a BP neural network model, we established a model for predicting the risk of wellbore blockage and analyzing mitigation measures in the target reservoir. The model’s prediction results, consistent with on-site actual results, demonstrate its reliability and accuracy. Experimental results show that the water quality in the target area is mainly a CaCl₂ type, and the predominant scales produced are CaCO₃ and BaSO₄. Model calculations reveal that temperature, pressure, and ion concentration all influence scaling, with BaSO₄ more influenced by pressure and CaCO₃ more influenced by temperature. Under the combined effect of temperature, pressure, and ion concentration, different types of scales exhibit distinct trends in scaling quantity. Combining scaling quantity calculations with wellbore contraction ratios, it was found that when the temperature, pressure, and ion concentration are within a certain range, the wellbore contraction rate can be controlled below 4%. At this point, the wellbore scaling risk is minimal, and preventive measures against wellbore scaling can be achieved by adjusting production systems, considering practical production conditions. This study investigates the mechanism of scaling in wellbores of tight sandstone gas reservoirs and proposes a cost-effective scaling prevention measure. This approach can guide the prediction of scaling risks and the implementation of scaling prevention measures for gas wells in tight sandstone reservoirs. Full article

The mass fraction of total organic carbon (TOC) is one of the key indicators for evaluating the hydrocarbon generation potential of shale source rocks. Experimental measurements to evaluate the TOC content require significant cost and time. Furthermore, the experimental data are often fragmented and may not provide an accurate depiction of the source rocks throughout the entire block. To solve the above problems, this paper proposes to use the combination of conventional logging data and experimental data after an in-depth study of the geophysical characteristics of hydrocarbon source rocks in the Ordos Basin. A quantitative model between logging data and source rocks is established, and then the continuous distribution value of the TOC content in the hydrocarbon source rock interval is calculated. Firstly, the mud shale formation of the Permian–Shanxi Formation in the Upper Paleozoic, located in the Jingbian area of the Ordos Basin, is selected as the research target using the “Jinqiang method”. The model is constructed by selecting appropriate logging curves (acoustic time difference logging, resistivity logging, and density logging) and experimental results based on the response relationship between logging data and TOC data. This method provides more accurate and comprehensive data for source rock studies, combining experimental sampling to contribute to a better evaluation of TOC in source rock. The shale hydrocarbon source rock logging data from 10 wells are selected, and the model is used to realize the full-well section of the logging data to find the hydrocarbon source rock TOC, which is compared with the TOC data from the experimental core tested at a sampling point. The results demonstrate that the model is highly effective and accurate, with a mere 2.7% percentage error observed across 185 sample data points. This method greatly improves the accuracy and completeness of TOC evaluation compared with the results of previous studies and provides a guide for subsequent TOC logging evaluation of source rocks in other areas. With the study in this paper, continuous TOC values of source rocks are obtained, discarding the TOC values representing the whole set of hydrocarbon source rocks with a limited number of sample averages. This method can reflect the contribution of the layers with high and low organic matter abundance, and the calculated reserves are more accurate. By utilizing the measured TOC values of the study area to invert the model to find the parameters, this study contributes to the decision-making of hydrocarbon exploration in domestic and international basins. Full article

Faced with difficulties stemming from the complex interactions between tight gas sand bodies and fractures, when describing and identifying reservoirs, a composite reservoir model was established. By setting the supply boundary to characterize the superposition characteristics of sand bodies, a mathematical model of unstable seepage in fractured vertical wells in tight sandstone gas reservoirs was developed, considering factors such as stress sensitivity, fracture density and fracture symmetry. The seepage law and pressure response characteristics of gas wells in tight sandstone discontinuous reservoirs with stress sensitivity, semi-permeable supply boundary and complex fracture topology were determined, and the reliability of the model was verified. The research results more accurately display the pressure characteristic of a vertical well in the superimposed sand body with complex fractures and provide a more comprehensive model for tight gas production dynamic analysis and well test data analysis, which can more accurately guide the dynamic inversion of reservoir and fracture parameters. Full article

In recent years, there has been quite a dispute over the water shutoff effect of fuzzy ball fluids in fractured tight sandstone gas reservoirs. The core issue of this dispute is to try and make fuzzy ball fluid stabilize gas during the water shutoff process for sustainable development. In order to solve this dispute, the Linxing He-2 reservoir matrix core and a core with artificial fractures were used to simulate interlayer water, artificial fractures, and water output channels from the side and bottom. Simulated formation water and nitrogen were used as the two-phase flow phase. The breakthrough pressure of the air and water phases was tested after plugging with fuzzy ball fluid in order to simulate and analyze the water shutoff effect of the fuzzy ball fluid and its ability to achieve air establishment and water control. The results of this study show that for the core matrix, the breakthrough pressure gradient for water and gas varied from 0.200 MPa/cm to 0.210 MPa/cm and 0.015 MPa/cm to 0.025 MPa/cm, and for artificial fractured cores, the breakthrough pressure gradient of water and gas varied from 0.035 MPa/cm to 0.040 MPa/cm and 0.015 MPa/cm to 0.020 MPa/cm. These results prove that fuzzy ball fluid can block small-scale water output channels, such as matrix pores, through the polymer film-forming structure, and plug the artistic cracks and large-scale water output channels of the water flowing into the sides and bottom through the accumulation of a large number of fuzzy balls, which greatly improves the flow resistance of water. The amount of fuzzy ball fluid should be carefully adjusted with consideration of the water output and formation conditions. For large-scale water output channels and side and bottom water shutoff operations, it is recommended that the amount of fuzzy balls be increased along with the number of fuzzy balls in the system in order to increase the breakthrough pressure of water and achieve the stable control of air and water. It is believed that the fuzzy balls would quickly change their shapes to match the sizes of fracture channels to enter into fractured reservoirs and that an active hydrophobic membrane would form on the surface of fractured rocks, with macromolecules and surfactants being dispersed in the fluid system. In addition, the interface between the fuzzy balls is also hydrophobic, which would slow down the flow of water and provide a continuous gas percolating channel after aggregating and entering into the fractures. This increases the persistence of water intruding into the formation and does not affect the percolation of the gas of fractured tight sandstone gas reservoirs. This research is of great significance for the EOR of tight sand gas reservoirs and the sustainable development of oil and gas resources in China. Full article

The western Sulige gas field is a new and key reserve area for the rolling development of the Sulige gas field in China. However, due to the complex gas–water relationship and the difficulty in identifying gas and water formation, the scale and benefit deployment of the gas field are seriously restricted. In particular, almost all of the wells in the area produce water, and no water measurements have been carried out for any single well, which leads to an unclear understanding of the dynamic characteristics of the production wells, thus affecting the productivity calculations of the gas wells and the overall regional productivity evaluation. Based on the testing data for a gas well, the impacts of the reservoir property parameters on the gas and water production were analyzed by combining the production performance and static geological characteristics. It was determined that the physical parameters K, Kh, and φS_g had good positive correlations with gas production but not with water production; thus, effective prediction cannot be obtained for water production in gas well testing. After the analysis of the liquid-loading law, the gas wells were classified into three types: continuous liquid-carrying production, slight liquid-loading, and liquid-loading wells. In general, up to 96% of the gas wells were liquid-loaded. According to the different production performances exhibited in the different stages of the gas wells, five types of methods for diagnosing water production wells were proposed (gas testing, pilot production, gas–liquid two-phase measurement testing, liquid level detection, and production performance analysis), as well as the diagnostic criteria and corresponding solutions. To obtain real-time water production data for each well and investigate the change in the water–gas ratio (WGR) during the whole production process, a water production splitting method for gas wells based on three-dimensional geological modeling and numerical simulation combined with the constraints of the total water production of gas gathering stations was explored and established. The splitting results can be used to evaluate the water and gas productivity of gas wells and determine the best deliquification period. The gas well productivity when water production was considered was about 10% lower than that when water production was not considered. The best deliquification period was determined to be 125 days for wells with small water production, 20 days for wells with moderate water production, and 3 days for wells with serious water production. The results of this study could provide technical support for the scientific evaluation of gas well production indicators, reduction in development costs, and improvement in oil recovery. Full article

This study conducted pin disc friction and wear performance tests on polyethylene-lined oil pipes and four types of centralizing materials (45# steel, nylon, polytetrafluoroethylene (PTFE), and surface alloy coating) in oil fields. The friction coefficient and wear rate were tested, and the wear mechanism was analyzed using scanning electron microscopy (SEM) and three-dimensional confocal microscopy. Using a combination of experimental testing analysis and theoretical research, a comprehensive evaluation of the current wellbore centering and anti-wear technology for oil was conducted. The experimental results indicate that the usage limit of polyethylene-lined oil pipes is 400 N, and compared to metal oil pipe materials, the wear rate of both stabilizing material and tubing material is lower, indicating that it has a certain service life. From the perspective of testing load, taking into account the factors of friction coefficient and wear rate, the recommended sequence of straightening material for polyethylene lined oil pipes is (1) surface alloy coating, (2) nylon, (3) PTFE, and (4) 45# steel. Full article