Fuling Shale Gas Field Research Articles

Integrated AutoML-based framework for optimizing shale gas production: a case study of the Fuling shale gas field

Integrated AutoML-based framework for optimizing shale gas production: a case study of the Fuling shale gas field

Greater environmental risk of shale gas produced water from lacustrine than marine sources in Fuling shale gas field, China: Insights from inorganic compounds, dissolved organic matter, and halogenated organic compounds

Lacustrine shale gas represents a promising frontier in the future development of shale gas resources. However, research on the characterization of lacustrine shale gas produced water (SGPW) remains scarce. In this study, we characterized the geochemical properties of both marine and lacustrine SGPW (MSGPW and LSGPW) and assessed their dissolved organic matter (DOM) components using fluorescence EEM spectroscopy. Additionally, we employed Fourier-transform ion cyclotron resonance mass spectrometry (FT-ICR MS) to analyze halogenated organic compounds (HOCs) and non-HOCs in SGPW, as well as their transformations during storage in open impoundments. Pollutants in LSGPW generally had higher concentrations and greater fluctuations compared to those in MSGPW. Our findings from EEM spectroscopy and FT-ICR MS revealed that phenolic compounds may be important components of DOM in all SGPW. Moreover, the number of detected unique molecules in LSGPW was greater than in MSGPW. CHO or CHOS compounds dominated in non-HOCs, with LSGPW exhibiting generally higher DBE, modified aromaticity index (AImod), nominal oxidation state of carbon (NOSC), double bond equivalent minus oxygen per carbon ((DBE-O)/C) values, and lower H/C values compared to MSGPW, while unsaturated aliphatic compounds typically dominated in HOCs. Furthermore, we employed 37 transformation reactions that might occur during SGPW storage and found that oxygen addition and dealkyl group reactions were predominant, with these two types of reactions occurring more frequently in LSGPW than in MSGPW. LSGPW exhibited higher toxicity compared to MSGPW, with toxicity positively correlated with the concentrations of inorganic salts and organic substances with higher AImod, NOSC, and (DBE-O)/C. These findings contribute to a more comprehensive understanding of LSGPW, enabling the design and implementation of more rational disposal measures to effectively mitigate its potential environmental risks.

A comprehensive logging evaluation method for identifying high-quality shale gas reservoirs based on multifractal spectra analysis

Conventional logging interpretation methods qualitatively identify shale reservoirs using shale attribute parameters and interpretation templates. However, improving the identification accuracy of complex shale reservoirs is challenging due to the numerous evaluation parameters and the complexity of model calculations. To quantitatively characterize high-quality shale reservoirs effectively, this study utilizes two wells in the Fuling shale gas field as examples and establishes a comprehensive evaluation method for identifying high-quality shale gas reservoirs utilizing multi-fractal spectral analysis of well logs. First, the conventional well logs are qualitatively analyzed and evaluated via multiple fractals and R/S analysis. Subsequently, a gray relational analysis is employed to combine the production well logging, which reflects dimensionless productivity contributions, with the fractal characteristics of conventional well logs to obtain the corrected weight multifractal spectrum width ∆α' and fractal dimension D’. Comprehensive fractal evaluation indices λ and γ are introduced, forming three categories of productivity evaluation standards for shale gas reservoirs characterized by fractals. Finally, a validation well is employed to demonstrate the effectiveness of the evaluation method. The results indicate that the identification of high-quality shale gas reservoirs based on the above comprehensive fractal evaluation method can reflect the productivity classification level of fractured well sections, simplify the calculation of formation evaluation parameters, and avoid the problem of poor correlation between predicted sweet spot zones and gas production. This approach has wide applicability and value for identifying high-quality reservoir areas in shale gas reservoirs and provides technical support for the effective large-scale development of shale reservoirs.

Contrasting fracturing and cementation timings during shale gas accumulation and preservation: An example from the Wufeng-Longmaxi shales in the Fuling shale gas field, Sichuan Basin, China

The marine shales in southern China are characterized by high thermal evolution and intensive deformation during multistage burial and uplift. Fracturing and cementation, associated with tectonic activity, diagenesis, hydrocarbon generation and migration processes, are widely and variably distributed in shale reservoirs experiencing different tectonic evolution. In this study, we utilized cross-cutting relationships, fluid inclusion microthermometry, and laser Raman spectroscopy of fluid inclusions, along with U-Pb dating of fracture-filling calcite veins, integrated with burial history modeling, to elucidate the timing and mechanism of fracturing in the Paleozoic Wufeng-Longmaxi shale reservoir, as well as regional variations in the Fuling shale gas field. Bedding-parallel fractures (BFs) in shale reservoirs are filled with calcite and quartz veins. The timing of fracturing, as determined by minimum homogenization temperatures and U-Pb dating, is estimated to have occurred during ca. 191 -122 Ma, during which some short vertical (or high-angle) fractures (VFs) opened around 163.4 Ma and 137 Ma, subsequently sealed by calcite veins, respectively. All calcite and quartz veins within these fractures contain high-density methane inclusions, while shale reservoirs were in a high-over-mature evolutionary stage. This suggests that fracturing was primarily driven by gas generation overpressure during deep burial. In shale reservoirs near fault belt folds, multistage fractures developed, including three stages of intersecting fractures (IFs) and one-stage of long VFs. The timing of fracturing and cementation corresponds to the Yanshanian tectonic uplift (ca. 83 - 69 Ma) with intense tectonic movement likely being the direct cause of fracture opening. The presence of abundant gas inclusions in veins recorded shale gas expulsion during rapid tectonic uplift, reflecting the destruction of shale gas preservation conditions. In contrast, no significant fracturing or cementation processes have been observed in the tectonically gentle zones. The different fracturing and cementation processes indicated that preservation conditions declined with increased fracture openings during uplift, correlating with the gas enrichment.

Novel method for total organic carbon content prediction based on non-equigap multivariable grey model

Predicting total organic carbon content plays a crucial role in shale gas reservoir evaluation. To address multi-variable, imperfect logging data and non-equigap characteristics, this study developed a multi-variable grey derivative model for predicting the total organic carbon content trend. To begin with, the non-equigap factor is introduced and the parameter identification of the new model is established on the basis of least square method. Then, to reduce fluctuations in the original data, the weighted geometric average weakening operator is introduced. In addition, considering the system stability, the derivation method is used to calculate the time response formula of the model. Furthermore, two validation cases are provided to verify the validity of this novel model. Finally, the model is applied to the Fuling shale gas field in China for practical forecasting. Compared to other models, such as the grey model, statistical model, and artificial intelligence model, the proposed model achieved higher prediction accuracy in the three cases. Specifically, this model obtained 95.62%, 95.88% and 94.55% prediction accuracy for total organic carbon content. Results that the new model effectively addresses the limitations of previous studies that focus on single-parameter or equal spacing issues.

New approach of evaluating fracturing interference based on wellhead pressure monitoring data: a case study from the well group-A of Fuling shale gas field

Well pattern infilling has become an effective means for improving the development effect of gas reservoirs in unconventional gas reservoirs. The hydraulic fracturing of infill wells causes widespread fracturing interference between new and old wells. Because fracturing interference has a significant influence on the production of old wells, it is urgent to evaluate the degree of fracturing interference. This paper proposes a new approach to evaluating fracturing interference between new and old wells, which is based on a systematic analysis of the variation pattern of old well wellhead fracturing during the fracturing process of new wells. This new approach not only provides a semi-quantitative evaluation for the degree of fracturing interference between fracture sections of new and old wells but also achieves inter-well connectivity evaluation between new and old wells. This new approach is applied in well group A of the Fuling gas field to demonstrate its analysis process. The results show the different types of fracturing interference result in different levels of pressure response between each fracturing section and the old wells. For example, The pressure rise of old well A7-1 is more obvious in the fracturing process of the 2nd, 14th, and 13th sections of new well A68-5, and the old well A7-2 has significant fracturing interference with the 1st, 2nd, 3rd, 4th, and 6th sections. This achieves a semi-quantitative characterization of fracturing interference between new and old wells. The degree of fracturing interference between the old well A7-2 and the new well A68-5 is the strongest in well group A, which is the effect of compression fracture interference. The old wells A7-3 and A15-3 are the least impacted by fracturing interference, and follow the old wells A15-2 and A7-1. This result has implications for assessing the degree of fracturing interference and inter-well connectivity in unconventional gas reservoirs.

Theory, technology and practice of shale gas three-dimensional development: A case study of Fuling shale gas field in Sichuan Basin, SW China

In the Jiaoshiba block of the Fuling shale gas field, the employed reserves and recovery factor by primary well pattern are low, no obvious barrier is found in the development layer series, and layered development is difficult. Based on the understanding of the main factors controlling shale gas enrichment and high production, the theory and technology of shale gas three-dimensional development, such as fine description and modeling of shale gas reservoir, optimization of three-dimensional development strategy, highly efficient drilling with dense well pattern, precision fracturing and real-time control, are discussed. Three-dimensional development refers to the application of optimal and fast drilling and volume fracturing technologies, depending upon the sedimentary characteristics, reservoir characteristics and sweet spot distribution of shale gas, to form “artificial gas reservoir” in a multidimensional space, so as to maximize the employed reserves, recovery factor and yield rate of shale gas development. In the research on shale gas three-dimensional development, the geological + engineering sweet spot description is fundamental, the collaborative optimization of natural fractures and artificial fractures is critical, and the improvement of speed and efficiency in drilling and fracturing engineering is the guarantee. Through the implementation of three-dimensional development, the overall recovery factor in the Jiaoshiba block has increased from 12.6% to 23.3%, providing an important support for the continuous and stable production of the Fuling shale gas field.

Graphic Template Establishment and Productivity Evaluation Model of Post-Fracturing Based on the Fluctuation Pattern of G-Function Curve

In the process of fracturing construction in shale gas reservoirs, microseism is a common means and effective method to evaluate the fracturing effect, but it is not suitable for large-scale and large batches due to its high applicability conditions and cost. Therefore, a concise, fast and low-cost post-fracturing effect evaluation method is needed to evaluate the complexity of fractures formed by fracturing in shale gas reservoirs. In this paper, based on the basic theory of the G-function, the free variable μ was introduced to correct the filter loss coefficient with the participation of natural fractures, and thousands of G-function curves were plotted with fracturing data from hundreds of gas wells in the southern Fuling shale gas field in China. Through the feature analysis of the curve morphology, a G-function graphic template conforming to the block was established, which contains four types and eight morphologies. Four characteristic parameters in the G-function curve were selected to establish a productivity evaluation model for shale gas wells. Based on the validation results, it can be seen that the G-function graphic template and productivity evaluation model proposed by the author had a good correlation with the post-fracturing productivity of shale gas wells, which provided a fast, economical and accurate method for the post-fracturing effect evaluation and productivity evaluation of shale gas wells and can effectively provide feedback on the field fracturing effect and guide subsequent fracturing construction.

Depositional-diagenetic process and their implications for pore development of Wufeng-Longmaxi shales in the Jiangdong block, Fuling shale gas field, SW China

Depositional environment and diagenesis are important factors affecting pore characteristics, whereas how differential depositional and diagenetic processes affect pore development and preservation in shale remains controversial. In this study, based on geochemical analysis, low-temperature gas (including N2 and CO2) physisorption, core observation, thin section and field emission-scanning electron microscopy, the influences of various paleoenvironmental conditions and diagenetic pathways on pore development of the Wufeng and Longmaxi Formations are investigated. The results indicate that paleoenvironmental conditions determine primary mineral composition and content of organic matter, resulting in the various shale lithofacies. Subsequently, minerals in different shale lithofacies experienced various diagenetic events and evolution pathways, finally affecting pore generation and evaluation. Three system tracts, including transgressive systems tract (TST), early highstand systems tract (EHST) and late highstand systems tract (LHST) are identified in the Wufeng and Longmaxi Formations. Siliceous shale, mainly deposited in the TST, contains large amounts of biogenic authigenic quartz and abundant organic matter. Authigenic quartz aggregates effectively inhibit compaction and protect abundant pores. The contents of extrabasinal components increase during the EHST, while biogenic quartz and organic matter decrease to mainly develop mixed shale. Insufficient microcrystalline authentic quartz and high content of clay minerals lead to higher degree of compaction in mixed shale than siliceous shale, resulting in fewer residual pores. In contrast, clay minerals in clay-rich shale, deposited in the LHST, undergo strong compaction and illitization of smectite during diagenesis, resulting in strong deformation and loss of primary pores. As a result, higher amount of OM pores is generated and preserved in the organic-rich siliceous shales from the bottom of Wufeng and Longmaxi Formation, and gradually decreases in the mixed shale, while clay-rich shale in the upper section of the Longmaxi has the lowest amount of pore volume.

Hybrid data-driven framework for shale gas production performance analysis via game theory, machine learning, and optimization approaches

A comprehensive and precise analysis of shale gas production performance is crucial for evaluating resource potential, designing a field development plan, and making investment decisions. However, quantitative analysis can be challenging because production performance is dominated by the complex interaction among a series of geological and engineering factors. In fact, each factor can be viewed as a player who makes cooperative contributions to the production payoff within the constraints of physical laws and models. Inspired by the idea, we propose a hybrid data-driven analysis framework in this study, where the contributions of dominant factors are quantitatively evaluated, the productions are precisely forecasted, and the development optimization suggestions are comprehensively generated. More specifically, game theory and machine learning models are coupled to determine the dominating geological and engineering factors. The Shapley value with definite physical meaning is employed to quantitatively measure the effects of individual factors. A multi-model-fused stacked model is trained for production forecast, which provides the basis for derivative-free optimization algorithms to optimize the development plan. The complete workflow is validated with actual production data collected from the Fuling shale gas field, Sichuan Basin, China. The validation results show that the proposed procedure can draw rigorous conclusions with quantified evidence and thereby provide specific and reliable suggestions for development plan optimization. Comparing with traditional and experience-based approaches, the hybrid data-driven procedure is advanced in terms of both efficiency and accuracy.

Case Study: Successful Application of a Novel Gas Lift Valve in Low Pressure Wells in Fuling Shale Gas Field

The Fuling shale gas field is facing a rapid gas production decline due to heavy liquid loading issues. Given the condition that most wells are located at remote areas in the mountains, the traditional gas lift methods that require either fixed compressor or skid-mounted gas lift trucks do not seem feasible and occur high operation costs. A new type of gas lift valve that can be opened or closed at a low valve dome pressure indicates the high sensitivity to low production pressure. Thus, the piping line pressure can be utilized to activate the valve due to its new advantages. In addition, the specially designed structure of the gas lift valve can be activated via pressure increases in the tubing to create a channel between the tubing and annulus. The valve that previously functioned as a dummy valve was then switched to a gas lift valve. Field application results show that all wells were successfully restarted by only utilizing the low piping pressure, and loaded liquid was lifted with gas production at an incremental rate that reached up to 27.4 × 10 kscm/d per well. Fewer slickline operations were conducted to replace the dummy valve. The result of the application shows that the new type of gas lift system has a wide range of application prospect for low pressure wells, especially for shale gas wells.

The generalized method for estimating reserves of shale gas and coalbed methane reservoirs based on material balance equation

As the main unconventional natural gas reservoirs, shale gas reservoirs and coalbed methane (CBM) reservoirs belong to adsorptive gas reservoirs, i.e., gas reservoirs containing adsorbed gas. Shale gas and CBM reservoirs usually have the characteristics of rich adsorbed gas and obvious dynamic changes of porosity and permeability. A generalized material balance equation and the corresponding reserve evaluation method considering all the mechanisms for both shale gas reservoirs and CBM reservoirs are necessary. In this work, a generalized material balance equation (GMBE) considering the effects of critical desorption pressure, stress sensitivity, matrix shrinkage, water production, water influx, and solubility of natural gas in water is established. Then, by converting the GMBE to a linear relationship between two parameter groups related with known formation/fluid properties and dynamic performance data, the straight-line reserve evaluation method is proposed. By using the slope and the y -intercept of this straight line, the original adsorbed gas in place (OAGIP), original free gas in place (OFGIP), original dissolved gas in place (ODGIP), and the original gas in place (OGIP) can be quickly calculated. Third, two validation cases for shale gas reservoir and CBM reservoir are conducted using commercial reservoir simulator and the coalbed methane dynamic performance analysis software, respectively. Finally, two field studies in the Fuling shale gas field and the Baode CBM field are presented. Results show that the GMBE and the corresponding straight-line reserve evaluation method are rational, accurate, and effective for both shale gas reservoirs and CBM reservoirs. More detailed information about reserves of shale gas and CBM reservoirs can be clarified, and only the straight-line fitting approach is used to determine all kinds of reserves without iteration, proving that the proposed method has great advantages compared with other current methods.

Pyrolysis kinetics and environmental risks of oil-based drill cuttings at China’s largest shale gas exploitation site

Chongqing Fuling shale gas field, the largest shale gas exploration site in China, produces a large amount of oil-based drill cuttings (OBDC) every year, which is a hazardous waste. Traditional treatment methods such as solidification/stabilization did not recycle the valuable components such as petroleum hydrocarbons. Pyrolysis is proven to be an efficient method that can recover those components. This study firstly investigated the pyrolysis kinetics by two different methods on the basis of detailed material characterization, and then taking the workers and the surrounding ecological environment as the analysis object, the human health risk assessment (HHRA) and ecological risk assessment were evaluated respectively before and after pyrolysis. The results showed that the pyrolysis of OBDC was divided into three stages, and the cracking of light hydrocarbons stage was the key control step for pyrolysis process. The activation energy E increased gradually during the pyrolysis progress. The HHRA results showed that pyrolysis could greatly reduce the non-carcinogenic risk, carcinogenic risk and ecological risk by 59.6 %, 62.8 % and 75 % respectively. However, the carcinogenic risk after pyrolysis was still higher than the critical value 10−6.

Shale gas wastewater geochemistry and impact on the quality of surface water in Sichuan Basin

Shale gas wastewater (SGW) disposal is a major challenge in the areas in central China due to its increasing volume associated with intensification of shale gas exploration and its high levels of contaminants. In the Fuling shale gas field of Sichuan Basin, a small amount of SGW originated from the flowback and produced water (FPW) is treated and then discharged to a local stream. This study investigated the inorganic water geochemistry and Sr isotopic composition of the FPW in Fuling shale gas field, the SGW effluent that is generated in the treatment facility, and the quality of a local river after the disposal of treated SGW. The data generated in this study reveals that FPW generate after several years of shale gas operation maintain the original geochemical fingerprints detected in early stages of FPW generation, and consistent with the FPW composition detected in other shale gas fields in Sichuan Basin. We show that reuse of saline FPW for hydraulic fracturing can generate an inverse salinity trend, where the salinity of FPW decreases with time, reflecting the increase of the contribution of formation water with lower salinity. The treatment of the FPW results in ~40 % reduction of the salts by dilution with freshwater and selective (80–90 %) removal of some of the inorganic contaminants. The original geochemical fingerprints of the FPW from Fuling shale gas field was not modified during FPW treatment, reinforcing the applicability of these tracers for detecting SGW in the environment. Discharge of treated SGW effluent to a local river causes a major 200-fold dilution and reduction of all contaminants levels below drinking water and ecological standards. Overall, this study emphasizes the importance of water quality monitoring of treated SGW and the overall measures needed to protect public health and the environment in areas of shale gas development.

A Shale Gas Leaking Incident in Fuling Shale Gas Field in Chongqing, China: A Case Study

A ground natural gas leaking event at the Fuling shale gas field is reported in this paper. Thirteen leakage spots were discovered in two places near the SW-1 and SW-2 drilling wells. The biggest leak rate was above 1000 m3 per day, and no H2S was identified in any of the 13 leaking spots, according to the field study. The chemical components, carbon isotope properties of the leaking gases, and the geological context of the leaking location were researched in order to determine the reason for the leaking incident. From the geological conditions, the Shimen 1# fault belt cuts the whole strata from bottom to top, according to seismic reverse time migration (RTM), and the fault and leaking spots are located in the range of the surface projection of the horizontal section of the adjacent shale gas well. The fracture development evaluation shows that the Wufeng–Longmaxi Formation, which is also the producing layer of the Fuling shale gas field, has a very high possibility of fracture development. From the geochemical view, the carbon isotope of the leaking gases lies in the range of the Wufeng–Longmaxi Formation, showing that the Wufeng–Longmaxi Formation is the gas source of the leaking gas.

Modified Flowing Material Balance Equation for Shale Gas Reservoirs

To determine original gas-in-place, this study establishes a flowing material balance equation based on the improved material balance equation for shale gas reservoirs. The method considers the free gas in the matrix and fracture, the dissolved gas in kerogen, and the pore volume occupied by adsorbed phase simultaneously, overcoming the problem of incomplete consideration in the earlier models. It also integrates the material balance method with the flowing material balance method to obtain the average formation pressure, eliminating the problem with the previous method where shutting down of wells was needed to monitor the formation pressure. The volume of the adsorbed gas on the ground is converted into volume of the adsorbed phase in the formation using the volume conservation method to characterize the pore volume occupied by the adsorbed phase, which solves the problem of the previous model that the adsorbed phase was neglected in the pore volume. The model proposed in this study is applied to the Fuling Shale Gas Field in southwest China and compared with other flowing material balance equations, and the results show that the single-well control area calculated by the model proposed in this study is closer to the real value, indicating that the calculations in this study are more accurate. Furthermore, the calculations show that the dissolved gas takes up a large fraction of the total reserves and cannot be ignored. The sensitivity analyses of critical parameters demonstrate that (a) the greater the porosity of the fracture, the greater the free gas storage; (b) the values of Langmuir volume and TOC can significantly affect the results of the reservoir calculation; and (c) the adsorbed phase occupies a smaller pore volume when the Langmuir volume is smaller, the Langmuir pressure is higher, or the adsorbed phase density is higher. The findings of this study can provide better understanding of the necessity to take into account the dissolved gas in the kerogen, the pore volume occupied by the adsorbed phase, and the fracture porosity when evaluating reserves. The method could be applied to the calculation of pressure, recovery of free gas phase and adsorbed phase, original gas-in-place, and production predictions, which could help for better guidance of reserve potential estimations and development strategies of shale gas reservoirs.

Study on pressure-boosting stimulation technology in shale gas horizontal wells in the Fuling shale gas field

After more than seven years of commercial development in the Fuling shale gas field, most old wells in the main block are confronted with significant pressure decline, so shale gas production is lower than the critical fluid-carrying flow rate and considerably reduced production. Pressure-boosting stimulation technology can increase the pressure difference between flow pressure and transmission pressure, which improves gas transmission capacity, maintains production and subsequently improves the recovery. This study analyzes the pressure-boosting stimulation pattern and prediction method of the remaining recoverable reserves in the Fuling shale gas field. The findings show that the pressure-boosting stimulation pattern of a gas-gathering station can reduce the abandonment pressure of a gas well to the maximum extent and fulfill the requirements for the new adjustment wells in the gas-gathering station; therefore, it is a pressure-boosting pattern suitable for the Fuling shale gas field. Blasingame analysis method can effectively predict the production change of continuous recovery over the next ten years. In addition, the influence of water production in shale gas wells on pressure-boosting stimulation technology is discussed. The research results can provide experience and direction for the continuous improvement of gas recovery in the Fuling and the same type shale gas fields.

Research and test for shut-in after fracturing of volume fracturing technology in Sulige low pressure tight gas

Shut-in after fracturing has become an important supporting technology for volume fracturing in unconventional oil and gas wells, which is helpful for gas and water imbibition replacement to increase single well production. In this paper, the hydraulic pressure, capillary pressure and osmotic pressure, the three main forces that affect well production, are calculated and compared in the Sulige tight sandstone gas field and Fuling shale gas field. The results show that the total forces affecting well production in the Sulige gas field are similar to those in the Fuling shale gas field, and it has the potential to exhibit shut-in after fracturing. For the characteristics of “low pressure” and “water blocking risk” in Sulige gas field, it is suggested that:(1)injecting N2 or CO2 during hydraulic fracturing and reasonably controlling the shut-in time after fracturing, such as shut-in for approximately 30 h, can ensure effective natural fluid flowback while replenishing energy to the formation and reduce the damage caused by water blocking and (2)the waterproof lock slickwater is used in the test wells, and the result shows that slickwater can reduce the reservoir damage and increase well production when compared with guanidine gum fracturing fluid. This research can provide some basis and reference for the field test of shut-in after fracturing in the Sulige tight sandstone gas field.

Carbon Dioxide and its Carbon Isotopic Composition of Natural Gas in the Sichuan Basin, SW China

The Sichuan Basin, covering an area of 180 × 103 km2, has the following advantages in natural gas geology: The sedimentary rocks are 6,000–12,000 m thick with high maturity of source rocks, and nine sets of primary gas source rocks are developed in the basin with a gas–oil ratio of 80:1, and thus it is a gas basin. The remaining recoverable reserves of conventional and unconventional natural gas are up to 13.6404 × 1012 m3. Multiple gas-bearing systems are developed with 25 conventional and tight oil and gas producing layers and 135 discovered gas fields, and the total proved geological reserves and cumulative production of natural gas by the end of 2019 were 5.7966 × 1012 m3 and 648.8 × 109 m3, respectively. The CO2 components and the correlation with relevant parameters for 243 samples from 22 gas fields indicate that CO2 in the Sichuan Basin display the following two characteristics: (1) Relatively low CO2 content of 0.02%–22.90% with an average of 2.96%, which guaranteed the commerciality of natural gas exploration and production; (2) cratonic CO2, which is characterized by low CO2 contents (<5%) and low R/Ra ratios (<0.24). According to the δ13CCO2 values and the relationship with R/Ra, δ13C1, CO2 contents, and wetness coefficient (W) for 263 gas samples, the δ13CCO2 values display three characteristics: (1) The highest δ13CCO2 value (10.4‰) in China is found in the Fuling shale gas field, which extends the interval values from previous −39‰–7‰ to −39‰–10.4‰. (2) The δ13CCO2 values can be applied to identify the CO2 origin of natural gas in the Sichuan Basin: type A, organic origin from thermal decomposition of organic matter, with an average δ13CCO2 value of −12.8‰ and average wetness coefficient of 7.8% for 44 samples; type B, organic origin from thermal cracking of organic matter, with an average δ13CCO2 value of −15.7‰ and average wetness coefficient of 1.30% for 34 samples; type C, inorganic origin from thermal decomposition or organic acid dissolution of carbonate rocks or minerals, with an average δ13CCO2 value of −1.8‰ and average wetness coefficient of 0.85% for 175 samples. (3) δ13CCO2>δ13CCH4. This is a common characteristic shared by all geological age (from Z2dn to J2s) gas reservoirs and various gas types (coal-derived gas, oil-associated gas, and shale gas).

Simultaneous numerical simulation of the hydraulic fractures geometry in multi-stage fracturing for horizontal shale gas wells

In this study, the hydraulic fracture geometry of multistage treatments is simulated. A simultaneous numerical simulation strategy is implemented for the three modules that allow for hydraulic fracture geometry calculation. The implemented modules of the simulation strategy are the fracture propagation, the formation stress, and the flow rate distribution, which are coupled to obtain a simultaneous solution. A second-order partial differential equation that describes the fracture propagation module is solved using an implicit Finite Difference Method (FDM), taking advantage of the concept of transmissibility. The flow rate distribution module calculates the inlet flow rate at each fracture by solving a nonlinear equation system. The formation stress module is described by a linear equation system, solved with the Discontinuous Displacement Method (DDM) for induced stress formation calculation. Coupling the modules requires the solution of two implicit equation systems and the evaluation of a fracture length criterion. A case is studied based on a single well (i.e., the X2-HF well) located northeast of the Fuling shale gas field, targeting the Wufeng and Longmaxi formation. A four-stage stimulation treatment with three fracture clusters is simulated. The space discretization for each stage is done for 30 elements with 10-time steps of 666 s. The obtained geometry in the mentioned field has a maximum half-length of 165.6 m and a minimum half-length of 136.8 m. The numerical solution requires 9.55 s to solve a single-stage scenario and 34.2 s to solve a four-stage scenario.