Tight Gas Production Research Articles

Analysis of Factors Influencing Tight Sandstone Gas Production and Identification of Favorable Gas Layers in the Shan 23 Sub-Member of the Daning-Jixian Block, Eastern Ordos Basin

The Daning-Jixian Block harbors abundant tight sandstone gas resources. However, significant variations in gas production exist among the different wells within the block. A comprehensive study was conducted on key factors such as sedimentary strata and petrophysical characteristics to elucidate their impact on gas reservoir productivity. Linear regression equations were employed to classify the favorable reservoirs within the study area. The analysis revealed that within the first 6 months of production from the Shan 23 gas layer, daily gas production ranged from 2576.19 to 156,078.17 m3/d, averaging 24,037.9 m3/d. Over the first year, average daily production varied from 2185.05 to 136,806.99 m3/d, averaging 23,469.23 m3/d, indicating relatively stable production from the Shan 23 layer alone. In the dominant central area of the underwater distributary channel delta front in Shan23, the sand body exhibits a superimposed cutting type, resulting in high production rates. Conversely, the sand bodies on the periphery gradually transition to superimposed and isolated types, leading to decreased production. Through a correlation analysis of gas layer thickness, porosity, permeability, and initial gas well production, it was determined that gas production from the wells within the same layer is primarily influenced by gas layer thickness, porosity, and permeability. Gas saturation demonstrates a minimal impact on production according to single-factor analysis. The evaluated factors such as the gas productivity coefficient, energy storage coefficient, and enrichment coefficient exhibited similar distribution patterns across the study area. The high-value areas for the gas productivity coefficient, energy storage coefficient, and enrichment coefficient are concentrated in distributary channel zones and delta lobes. In contrast, regions with underdeveloped skeletal sand bodies generally display lower values for these parameters. The linear relationships between these parameters and the average gas production were calculated to further classify the favorable reservoirs in the study area. This study aimed to establish a scientific basis for the efficient development of the tight sandstone gas reservoirs within the Daning-Jixian Block.

Parallel role played by tight gas resource in fulfilling United States’ Energy requirement and reducing emission profile from hydrocarbon exploration and production industry (Life cycle analysis lens)

Tight gas has revolutionized the energy picture in North America. The US energy information agency states that the tight gas and oil in the USA has boosted the production of natural gas by around 35% in recent years. This has reduced the need for gas imports. Thousands of meters underground, tight gas trapped in microscopic pores of very dense rocks requires hydraulic fracturing to fracture the rock and releases the gas into the well, known as tight gas. Environmental impact of producing tight gas has caused concerns related to air emissions, water contamination and disposal of waste generated by the tight gas production. There are also concerns related to the possibility of methane escaping into the air during tight gas production and development of this resource class causing minor earth tremors. The advancements in the drilling technologies have recently enabled greater volume of gas to be produce from a single drilling site. This reduces the operational footprint, which is directly proportional to emission profile of tight gas resource. There is a knowledge gap in understanding of Green House Gas (GHG- CO2 equivalent) footprint of tight gas’ resource development because of lack of operational constraints in previous environmental impact assessment of this resource. The objective of this study is to add value and reduce the scientific gap with respect to understanding of tight gas’ resource development techniques, related environmental, and land impact. There remain concerns about development of tight gas related to chemical and methane release into the local water and air, seismic events because of hydraulic fracturing and waste disposal. In order to understand this phenomenon better the work establishes the tight gas production foundation by in depth understanding of 1) Features of Tight gas reservoirs; 2) Geological environment, deposition and generation of tight gas resource; 3) Field development techniques of tight gas resource including construction, production and processing. The work then uses methodology of accounting input and out parameters of cradle to grave tight gas system boundary throughout its life cycle and understands previous GHG (CO2 equivalent) number of tight gas resource development. The work does systematic analysis and summarizes the previously published life cycle analysis to understand further the potential environmental impacts of resource development of tight gas. This will help hydrocarbon exploration and production operators to optimize the operations of tight gas production by better understanding of each sub block of tight gas field development in terms of C02 numbers by using low carbon technologies thus reducing the potential impacts.

Prediction of Single-Well Production Rate after Hydraulic Fracturing in Unconventional Gas Reservoirs Based on Ensemble Learning Model

To address the significant challenges in determining the single-well production of tight gas and shale gas after hydraulic fracturing, artificial intelligence (AI) methods were implemented. Machine learning (ML) algorithms such as random forest (RF), extremely randomized trees (ET), lightweight gradient boosting machines (LightGBM), gradient boosting regression (GBR), and linear regression (LR) were utilized in conjunction with reservoir geology, engineering parameters, and production data to develop several foundational models for forecasting the production of unconventional gas wells. The accuracy of these models was evaluated. Based on this, improvements in the models’ predictive accuracy and generalizability were achieved through the ensemble of machine learning models. Furthermore, this paper selected two representative tight and shale gas reservoirs to demonstrate the application of the ensemble model for well production forecasting, and a comparative analysis with actual production data was conducted. For tight gas reservoir A, the blending model achieved an MAE of 0.8419 and an MSE of 1.0930, with an R2 score of 0.8812. For shale gas reservoir B, the blending model achieved an MAE of 1.4841 and an MSE of 3.1629, with an R2 score of 0.9524. The results of the case studies indicate that the ensemble model approach employed in this study has a higher predictive accuracy and reliability than a single machine learning algorithm, and is capable of handling high-dimensional, large-scale, and imbalanced data, offering scientific validation and technical support for the assessment of the well productivity in tight and shale gas wells.

Optimization of tight gas reservoir fracturing parameters via gradient boosting regression modeling

In China, the exploitation of most unconventional oil and gas reservoirs is dependent on hydraulic fracturing, which is a key method employed when developing tight gas formations. Numerous scholars and field engineers, both domestically and internationally, have conducted extensive numerical simulations and physical experiments to study crack propagation and predict post-fracturing productivity in hydraulic fracturing. Although some progress has been reported in this regard, it is difficult to accurately predict the well productivity using mechanistic models owing to the vertical multilayered development of tight gas reservoirs. In this study, vertical fractured wells in a block of Sulige gas field were examined. The block relied on hydraulic fracturing to produce tight gases. However, as development progressed, the available reservoir environment deteriorated, large differences emerged between wells after fracturing, and the fracturing results did not meet the expectations. In this study, geological, construction, and generation data for this block that had been collected since 2007 were analyzed. After applying multiple machine-learning methods to filter outliers and fill in missing values, k-means clustering, classification enhancement, extreme gradient enhancement, and LightGBM algorithms were used to establish a regression model. The analysis results revealed that the regression accuracy of the cluster test set was as high as 70% and that the LightGBM model had the best regression effect among the 227 stripper wells in the block. After optimizing the fracturing construction parameters (fracturing fluid volume, proppant volume, liquid-nitrogen volume, and pumping rate), the average fracturing fluid and liquid-nitrogen volumes per well decreased, whereas the unit reservoir proppant and liquid-nitrogen volumes increased. The results also revealed that 182 wells showed an improved initial production capacity during fracturing. The average gas production index per meter increased by 22.04%. This approach enabled rapid and efficient production forecasting and construction optimization. Moreover, this represents a novel fracture design method that is applicable to onsite engineers in tight gas production fields in the Ordos region.

Characteristics of Tight Gas Reservoirs in the Xujiahe Formation in the Western Sichuan Depression: A Systematic Review

In current energy structure adjustments, the prominence of unconventional oil and gas resources continues to grow, with increasing attention being paid to tight gas, a major component of natural gas production. The Xujiahe Formation gas reservoir in the Western Sichuan Depression represents a typical tight gas reservoir and the study of its reservoir characteristics is a key focus for current and future exploration and development efforts. This review employs the PRISMA method to screen and integrate the primary findings of 26 documents spanning the period from 2008 to 2023, with the aim of providing a comprehensive overview of the progress and outcomes of research on the tight gas reservoir characteristics of the Xujiahe Formation in the Western Sichuan Depression. The selected research documents summarize the characteristics of the Xujiahe Formation tight gas reservoir in the Western Sichuan Depression from four perspectives: lithology, physical properties, reservoir space, and the main factors influencing reservoir quality. Through a review of these previous studies, it is evident that existing research has predominantly focused on the relationship between diagenesis and reservoir densification, indicating certain limitations. We also delve into the characteristics of tight gas sandstone reservoirs in the study area, considering their depositional systems, fracture development, cementation, and impact on the exploration and development of tight gas reservoirs. Additionally, we propose measures to stabilize and enhance tight gas production in the Xujiahe Formation in the Western Sichuan Depression. Moreover, we outline the next steps for further research and exploration.

Rapid assessment of water phase trapping on gas permeability reduction in typical tight gas reservoirs in China

Water phase trapping (WPT) is one of the primary formation damage issues which can cause a steep drop in tight gas production. This paper presented a rapid assessment of the damage potential of WPT in Daniudi, Nanpu 5th, and Keshen 9th tight gas reservoirs involving shallow to ultra-deep layers in China. Typical core samples of the three tight gas reservoirs were selected to perform water imbibition and drainage experiments to mimic the WPT occurrence. After that, the damage degree to core gas permeability induced by WPT was evaluated. Results showed that, for a 16-h vertical water imbibition experiment, the core samples of Daniudi gas reservoir experienced the fastest water imbibition process while the core samples of Keshen 9th gas reservoir established the highest water saturation. After water removal, the ranges of damage degree to core gas permeability induced by the incremental water saturation were 36.07%–78.13%, 36.06%–56.21%, and 61.00%–76.30% in Daniudi, Nanpu 5th, and Keshen 9th tight gas reservoirs, respectively. It found that with the increasing formation depth, tight gas reservoirs can suffer greater damage from WPT not only because of the decline in rock permeability but also the salting out of high salinity formation water. In general, it holds that strong water capillary imbibition phenomenon, low water removal capacity, and high gas permeability damage degree are found to be the striking features of WPT potential on these typical tight gas reservoirs in China.

Seepage Model and Pressure Response Characteristics of Non-Orthogonal Multi-Fracture Vertical Wells with Superimposed Sand Body in Tight Gas Reservoirs

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.

Model of cross-flow interference index and application for multi-layer commingled production in Sulige tight sandstone gas reservoir, Ordos Basin, China

Multi-layer commingled production is the main feature of gas well development in Sulige tight sandstone gas reservoir, Ordos Basin. Identifying potential interference between layers and devising methods for their characterization are crucial considerations for optimizing the development of gas reservoirs. To address these issues, we designed a physical simulation experiment process and interlayer commingled mining schemes, implementing various interlayer combination modes. The results show that a common occurrence in the process of multi-layer commingled production of tight gas and water layers, whether it involves gas layers production alone or simultaneous production of gas and water layers. This phenomenon involves the crossflow of gas and water between layers, resulting in interlayer interference and a subsequent reduction in gas reservoir recovery. Based on these observations, the concept of an interlayer interference index in multi-layer commingled production in tight sandstone gas reservoirs is proposed. The interference index model is obtained by fitting the multiple linear regression method, showcasing its correlation with the physical properties of the reservoir. High water saturation and a significant permeability ratio of the water layer to the gas layer (exceeding the critical value of 1) can result in the early occurrence of interlayer interference and yield a higher interference index. Furthermore, based on the interference index model, a novel method for productivity evaluation of gas wells in tight gas reservoirs is established. The calculations demonstrate that the interference index curve effectively characterizes the interlayer interference performance of gas wells. The productivity and production performance predictions derived from this model align closely with historical production data, affirming the model's effectiveness and accuracy. Therefore, the interference index model emerges as a valuable tool for predicting the productivity and production performance of gas wells in Sulige tight sandstone gas reservoirs. The research results have important theoretical guidance and practical significance for the efficient development of Sulige tight sandstone gas reservoirs.

Concept and key technology of “multi-scale high-density” fracturing technology: A case study of tight sandstone gas reservoirs in the western Sichuan Basin

There are abundant tight sandstone gas resources in the Sichuan Basin, which are the important objects of reserve and production increase and large-scale development. Due to their discontinuous sandbody distribution, narrow channels, and strong horizontal and vertical heterogeneity, however, conventional fracturing technologies cannot achieve the ideal stimulation effect here. In order to address this difficulty, this paper dissects the geology engineering characteristics of tight sandstone gas reservoirs in the western Sichuan Basin. Starting from the seepage mechanics theory, the concept of “multi-scale high-density” tight gas fracturing technology is put forward by fully referring to the experience of previous multi-round reservoir stimulation in the western Sichuan Basin and the idea of unconventional volume fracturing technology. In addition, its conceptual connotation, key technologies and implementation effects are illustrated. The following research results are obtained. First, the seepage characteristics make it necessary for the efficient production of tight gas reserves to increase fracture density and stimulated reservoir volume (SRV). Second, the “multi-scale high-density” fracturing technology emphasizes the rationality of high-density hydraulic fracture creation and the matching of multi-scale fracture flow capacity, and aims at establishing a multi-level fracture system with effective and steady gas flow in tight reservoirs through fracturing. Third, the “wide, dense, support, stable, and precise” fracturing technology is applied to improve single well production and estimated ultimate recovery (EUR). Fourth, the engineering practice of “multi-scale high-density” fracturing technology in the tight reservoirs of Jurassic Shaximiao Formation and Triassic Xujiahe Formation in the ZJ Gas Field realizes the average single well production rate of 15.6 × 104 m3/d, which is 1.96 times higher than that before the stimulation. Obviously, it provides powerful support for the operation of the ZJ Gas Field into a giant gas field with the reserves of 100 billion cubic meters. In conclusion, the formation of the concept and key technologies of “multi-scale high-density” fracturing technology effectively supports the efficient development of tight gas in the western Sichuan Basin and points out the following research direction of tight gas reservoir stimulation. The research results provide reference and guidance for the large-scale benefit development of tight gas in China.

Study on the Tight Gas Accumulation Process and Model in the Transition Zone at the Margin of the Basin: A Case Study on the Permian Lower Shihezi Formation, Duguijiahan Block, Ordos Basin, Northern China

Recent discoveries of oil and gas have principally been located in the central part of the Ordos Basin, which is a petroliferous basin with the largest discovered reserves and annual production of tight sandstone gas in China. For tight sandstone gas reservoirs in the transition zone of the basin margin, the process of natural gas accumulation has remained relatively vaguely understood, because of the transitional accumulation of geological conditions such as structure, sedimentation, and preservation. In this study, thin-section identification and scanning electron microscopic observations of the reservoir core, measurement of the physical properties of the reservoir, microscopic petrography research and measurement of the homogenization temperature of fluid inclusions, digital simulations, and laser Raman spectroscopy analysis were combined to analyze the process of natural gas accumulation of the Permian Lower Shihezi Formation in Duguijiahan block, Hangjinqi area, northern Ordos Basin. The results showed that the Lower Shihezi Formation reservoir in the Duguijiahan block began gas charging in the southern part as early as the Early Cretaceous (130–128 Ma), and then gradually charged in the northern part. Three stages were identified in the digital simulations of gas charging, i.e., the breakthrough, rapid, and fully saturated stages. The initial porosity of the Lower Shihezi Formation reservoir ranged between 28% and 40%. Later, because of strong compaction and interstitial filling during burial, the sandstone porosity decreased rapidly, and densification (porosity < 10%) occurred in the mid–late Jurassic. This late tectonic uplift caused a continuous reduction in ground temperature, and diagenesis had a weak effect on pore transformation. The present porosity of the Lower Shihezi Formation reservoir basically inherited its characteristics in the late Early Cretaceous. The current average porosity of the reservoir is 8.58%, and the average permeability is 0.88 mD, and it can thus be characterized as a tight reservoir. The gas accumulation process of the Lower Shihezi Formation has three stages: (1) the depositional stage (C–P), corresponding to the depositional stage of the source-reservoir-cap combination in gas reservoir; (2) the natural gas accumulation stage (T–K1), corresponding to the period of rapid source rock maturation and natural gas charging step-by-step; and (3) the gas reservoir adjustment stage (K2–present), corresponding to the period of uplift and natural gas charging in the early stage that gradually migrated and accumulated northward along the fracture zone. Finally, the gas accumulation model in the transition zone at the margin of basin was established.

Studies of natural gas production prediction and risk assessment for tight gas in Sichuan Basin

After a new round of tight gas geological evaluation was launched in 2018, a new chapter of tight gas exploration and development has been opened in the Sichuan Basin. In order to make better planning work, it is very important to study the variation rule and risk assessment of tight gas production. In this paper, the peak production is predicted by Ward model. Based on the prediction results, Hubbert and Gauss models were established to study the variation law of tight gas production, and the accuracy and prediction results of the models were determined by the degree of fitting and correlation coefficient. By studying the relationship between URR and production, it is concluded that the production increases in a step, and the future production of tight gas is simulated from the perspective of realization probability. Finally, the risk assessment matrix is established to study the difficulty degree of achieving the production target. The results are as follows: 1) Hubbert model has higher accuracy in predicting tight gas production change. The peak year of tight gas is 2042, the peak production is (86−106)×108m3/a, and the final URR recovery degree is about 60%. 2) The realization probability of production is calculated, and the possibility of reaching the target value is evaluated from the perspective of risk, so as to guide the production of tight gas, and finally promote the formulation of tight gas development planning in the Sichuan Basin.

Prediction of multiscale laminae structure and reservoir quality in fine-grained sedimentary rocks: The Permian Lucaogou Formation in Jimusar Sag, Junggar Basin

Fine-grained sedimentary rocks have become a research focus as important reservoirs and source rocks for tight and shale oil and gas. Laminae development determines the accumulation and production of tight and shale oil and gas in fine-grained rocks. However, due to the resolution limit of conventional logs, it is challenging to recognize the features of centimeter-scale laminae. To close this gap, complementary studies, including core observation, thin section, X-ray diffraction (XRD), conventional log analysis, and slabs of image logs, were conducted to unravel the centimeter-scale laminae. The laminae recognition models were built using well logs. The fine-grained rocks can be divided into laminated rocks (lamina thickness of <0.01 m), layered rocks (0.01–0.1 m), and massive rocks (no layer or layer spacing of >0.1 m) according to the laminae scale from core observations. According to the mineral superposition assemblages from thin-section observations, the laminated rocks can be further divided into binary, ternary, and multiple structures. The typical mineral components, slabs, and T 2 spectrum distributions of various lamina types are unraveled. The core can identify the centimeter–millimeter-scale laminae, and the thin section can identify the millimeter–micrometer-scale laminae. Furthermore, they can detect mineral types and their superposition sequence. Conventional logs can identify the meter-scale layers, whereas image logs and related slabs can identify the laminae variations at millimeter–centimeter scales. Therefore, the slab of image logs combined with thin sections can identify laminae assemblage characteristics, including the thickness and vertical assemblage. The identification and classification of lamina structure of various scales on a single well can be predicted using conventional logs, image logs, and slabs combined with thin sections. The layered rocks have better reservoir quality and oil-bearing potential than the massive and laminated rocks. The laminated rocks’ binary lamina is better than the ternary and multiple layers due to the high content of felsic minerals. The abovementioned results build the prediction model for multiscale laminae structure using well logs, helping sweet spots prediction in the Permian Lucaogou Formation in the Jimusar Sag and fine-grained sedimentary rocks worldwide.

Study on Co-production compatibility evaluation method of multilayer tight gas reservoir

Tight sandstone gas reservoir normally has a poor pore connectivity and a low productivity of single layer production, and the multilayer co-production technique has received increasing attention to improve its recovery in recent years. However, the range and impact of geological conditions are still unclear, leading to a challenging comprehensive evaluation of multilayer co-production compatibility. In this study, the impact of a series of factors on multilayer tight gas production is discussed by numerical simulation in detail, and their compatibility thresholds are determined. The variable weight based fuzzy comprehensive evaluation (VW-FCE) method is constructed, and a co-production compatibility index (CCI) is further proposed for multilayer tight gas reservoir co-production evaluation, with an application to Daning-jixian tight gas reservoirs for verification. The results show that thickness, permeability, reservoir pressure, and gas saturation are the key factors affecting the co-production, and the 10-year cumulative gas production contribution of the lower sandstone increases with the increase of each parameter ratio between the lower and the upper sandstones. When the properties of two co-production layers are similar, their compatibility is mainly impacted by the formation pressure and gas saturation variations. Otherwise, their compatibility is controlled by the formation thickness and permeability. The CCI values for multilayer co-production is 0.6–1, and the gas production capacity shows a positive exponential relationship with the evaluation index. The proposed method is verified by comparing with the actual production data from typical wells of tight sandstone gas co-production in the Daning-Jixian area, which indicates that the CCI is appropriate to evaluate the co-production compatibility of multiplayer tight gas reservoir, and provide theoretical supports for tight gas co-production.

Life Cycle Assessment of unconventional hydrocarbons deposits of shale and tight gas production in Poland

Wydawnictwo SIGMA-NOT wydaje czasopisma fachowe informujące swoich czytelników o najnowszych osiągnięciach naukowych i nowoczesnych rozwiązaniach technicznych w Polsce i na świecie, popularyzuje problemy techniczne oraz poszerza wiedzę i kulturę techniczną.

Development status and prospect of tight sandstone gas in China

As one of the important types of unconventional gas, tight gas is widely distributed in various major petroliferous basins in the world. The breakthrough of reservoir reconstruction technology and the reduction of development cost promote the scale and industrial development of tight gas. China is the third largest tight gas producer in the world and its yearly tight gas production is up to 470 × 108 m3 in 2020. In order to evaluate the development prospect of tight gas in China, this paper systematically summarizes domestic key technical series developed in the last 20 years' tight gas practice, after briefly analyzing the distribution and development history of tight gas resources all over the world. Then, the prospect of tight gas development in China is based on CNPC's fourth resource evaluation results. And the following research results are obtained. First, tight gas resource in China is abundant, accounting for about 10% of global resources, and its development is divided into two stages, i.e. the development evaluation stage and the development adjustment stage. Second, key technologies in the development evaluation stage include the establishment of genesis unit of effective reservoir, enrichment area selection, development index evaluation, well pattern and type optimization, reservoir reconstruction, and development scheme optimization. Third, the core in the development adjustment stage is enhanced gas recovery (EGR). The main technical means are well pattern optimization and infilling. Which can increase the recovery factor by 10%–20%. In addition, layer reviewing and reperforating, old well sidetracking, secondary fracturing, drainage and gas recovery, and pressurized production are also effective technologies. In conclusion, tight gas still has greater production potentials and development prospects in China. The potential tapping of produced proved reserves, the development of unproduced proved reserves and the effective development of new proved reserves are three important aspects to ensure the mid- and long-term development of tight gas. The first two aspects can support the yearly tight gas production to reach the peak of (700–800) × 108 m3 in 2030–2035 and keep stable production for more than 10 years. Moreover, the continuous development of new proved reserves will further support the stable production of tight gas until 2050–2060.

Geochemical processes during hydraulic fracturing in a tight sandstone reservoir revealed by field and laboratory experiments

The application of hydraulic fracturing has transformed tight sandstone gas into a very important global unconventional resource. The accurate description of geochemical processes during hydraulic fracturing can provide essential information for improving tight gas production. In this study, field fracturing and laboratory water-rock interaction experiments were designed and performed in conjunction with geochemistry, isotope, XRF, XRD and SEM techniques to reveal the prevalent geochemical processes. Sixty-five flowback fluid samples were collected from a hydraulic fracturing well and a tight sandstone sample was drilled from gas reservoir to perform water-rock interaction experiments. The results indicate that hydraulic fracturing flowback fluid is a complex mixture, with high TDS values (0.93–33.04 g/L) and heavy isotopes (e.g., mean δ18O of −5.35‰, mean 87Sr/86Sr of 0.714651). Geochemistry and isotope data reveal that the mixing process between fracturing fluid and formation water exerts an important influence on the flowback fluid chemistry, while water-rock and fluid-fluid interactions are also variably important during the hydraulic fracturing process. Pyrite oxidation process is confirmed during hydraulic fracturing in the tight sandstone reservoir, while the addition of gel breaker makes the process prominent. Due to high clay mineral contents (24%), ion exchange and adsorption/desorption are critical factors affecting the stability of the clay minerals during the entire fracturing and flowback processes. Approximately, 20%-43% of the strontium was removed from the solution by ion exchange between the 8 and 44 h intervals of the flowback process. The fractures derived from fracturing connect different types of high salinity formation water, leading to potential mineral precipitation (e.g., barite and calcite). The analysis of formation water needs to be taken into consideration during hydraulic fracturing operations.

Enhancing the production of tight sandstone gas well through fuzzy-ball fluid temporary plugging with diverting fractures and water cutting after refracturing in one operation

Refracturing is one of the most effective techniques to enhance the production of tight sandstone gas (TSG) well. Many TSG gas wells are facing the problem of water invasion after refracturing, the formation water may gradually occupy the gas-producing channels, preventing high gas productivity. In this paper, we newly developed a fuzzy-ball temporary plugging fluid (FTPF) with diverting fractures and water cutting after refracturing in one operation. The temporary plugging and water breakthrough control capabilities of the FTPF system were evaluated through the true triaxial large-scale core diversion fracturing experiment and matrix core and artificial fracture waterproof experiments. Meanwhile, the permeability damage evaluation experiments were performed to analyze the reservoir recovery ability. Results showed that the pressure-bearing capacity could reach up to 62.6 MPa, the rock fracture pressure was increased by 5–10 MPa compared with the initial hydraulic fracturing and an apparent fracture network structure was formed after refracturing. The breakthrough pressure gradients of simulated formation water were 2–10 times higher than that of nitrogen after the cores (including matrix and cores with 4 mm fractures) were plugged with FTPF, indicating its good water cutting ability. Before and after gel breaking, the permeability recovery value of the matrix core and the artificial fracture core was about 85–98%. The on-site application of FTPF to the refracturing of two TSG wells in the Sulige Gas Field in Northwest of China displayed that the average gas production has been enhanced by 64.8%. It is proposed that fuzzy balls can easily enter and gather at the tip of the initial fractures and form a stable pressure-bearing structure due to its viscoelastic properties and deformability. In addition, the hydrophilic fuzzy-ball core agents can adsorb on the rock's surface and form a polymer membrane, increasing the resistance of water flow.

An assessment of the source potential and reservoir characterization for tight gas exploration in the Subathu Formation shale, Himalayan Foreland Basin, Northwestern India

The Late Paleocene to Middle Eocene Subathu Formation shales in the prospective Himalayan Foreland Basin (HFB) were investigated to assess their source potential and reservoir characteristics. The organic-geochemical analysis of the investigated samples reveals that the total organic carbon (TOC) content ranges from 0.3 to 42.4 wt%, with an average value of 7.5 wt%. The visual kerogen assessment (VKA), the modified van Krevelen diagram and the HI versus Tmax crossplot indicate the prevalence of type III (gas-prone) kerogen. This is supported by the presence of significant amounts of vitrinite and inertinite group macerals, suggesting deposition in proximity to the source (e.g., swamp forest) in nearshore paludal (marshy) environments. The maximum pyrolysis yield temperature (Tmax) values range between 340 °C and 607 °C, suggesting immature to postmature gas generation stage. The vitrinite reflectance (Ro) values of the basal shale sequence range from 1.16 to 3.6 %, and their high maturity is attributed to their proximity to a major backthrust. The estimated hydrocarbon generation, migration, and retention data suggest a 91%–99% expulsion of hydrocarbons from the Subathu Fm shale. The bulk mineralogical data confirm the dominance of clay minerals (average 54.5%), which decreases up-section, where the younger shales have lesser clays and higher silica content. The kerogen type, richness and level of maturation along with the poor brittleness support a low fracability potential of the basal Subathu shales for tight gas production. A regional comparison is attempted with the Patala Formation in the Potwar Plateau of Pakistan.

Effect of dynamic threshold pressure gradient on production performance in water-bearing tight gas reservoir

Water content and distribution have important impacts on gas production in water-bearing tight gas reservoirs. However, due to the structural and chemical heterogeneity of tight reservoirs, the water phase exists in various states, which has complicated the analyses of the effects of water characteristics on tight gas production performance. In this work, the water phase is distinguished from immobile to mobile states and the term of constrained water saturation is proposed. It is established that water can flow when the driving pressure difference is larger than the critical driving pressure difference. A new theoretical model of threshold pressure gradient is derived to incorporate the influences of constrained water saturation and permeability. On this basis, a new prediction model considering the varied threshold pressure gradient is obtained, and the result indicates that when threshold pressure gradient is constant, the real gas production capacity of the reservoir will be weakened. Meanwhile, a dynamic supply boundary model is presented, which indicates that the permeability has a strong influence on the dynamic supply boundary, whereas the impact of initial water saturation is negligible. These findings provide insights into the understanding of the effects of water state and saturation on the threshold pressure gradient and gas production rate in tight gas reservoirs. Furthermore, this study provides useful guidance on the prediction of field-scale gas production. Cited as: Zhu, W., Liu, Y., Shi, Y., Zou, G., Zhang, Q., Kong, D. Effect of dynamic threshold pressure gradient on production performance in water-bearing tight gas reservoir. Advances in Geo-Energy Research, 2022, 6(4): 286-295. https://doi.org/10.46690/ager.2022.04.03

Effects of bedding direction on brine imbibition in Lower Shaximiao tight sandstone: An NMR analysis

Spontaneous imbibition phenomenon caused by capillarity plays an important role in the production of tight sandstone gas. Understanding the effects of bedding direction on liquid imbibition is important as it can give insights into water block phenomena that can negatively impact gas production. In this paper, four tight sandstone specimens were cored from Sichuan Basin, China with different bedding directions (i.e., the angles between the bedding plane and the horizontal plane of four specimens are 0°, 45°, 60° and 90°, respectively). Nuclear magnetic resonance (NMR) technique was used to monitor the fluid distribution changes during the spontaneous imbibition processes of these specimens. The results show that such tight sandstone exhibited strong hydrophilicity with the small pores dominating throughout the imbibition process. The T 2 spectra for all four rocks specimens not only increased upward but also shifted to larger relaxation times due to brine intake along the minerals surface (further indicating the hydrophilic characteristics of this rock). For such tight sandstone, capillary force and friction resistance between the fluid (brine) and mineral surfaces controlled the imbibition processes. For the 0°, 45° and 60° specimens, “stop illusion” phenomena which the imbibed brine volume had a tiny increase during a long period occurred. However, this was not observed in the 90° specimen (where the bedding direction and fluid flow direction are parallel). This is largely attributed to the significant tortuosity in the flow for the 0°, 45° and 60° specimens compared to the 90° specimen, leading the smallest friction resistance existed in the 90° specimen. Among these four specimens, the 0° specimen had the slowest imbibition rate and lowest imbibition efficiency, while the 90° specimen exhibited the fastest rate and highest efficiency. With the aim of maximizing gas production, this work provides some guidance for the selection of directional fracturing and injection-production methods in the exploitation and production of tight sandstone gas field. • Rock specimens with different bedding directions were used to conduct the spontaneous imbibition experiments monitored by NMR. • Different imbibition behaviors of four specimens were compared and analyzed. • Driving and resistance forces on the fluid during the experiment were summarized and compared. • The “stop illusion” phenomenon was observed and analyzed.