Fuling Shale Gas Field Research Articles

Particular pollutants, human health risk and ecological risk of oil-based drilling fluid: a case study of Fuling shale gas field.

Samples of new oil-based drilling fluid (NOBDF) and circulating oil-based drilling fluid (COBDF) in Chongqing were tested and analyzed to evaluate the possible impact of oil-based drilling fluid (OBDF) on human health and ecological environment. Organic matter, metals, and naturally occurring radionuclide materials (NORMs) in OBDF samples were analyzed and determined by gas chromatography-mass spectrometry, high-performance liquid chromatography, PANalytical Axios Fast XRF spectrometer, and gamma ray spectrometer. The results revealed that the contents of trace metals and NORMs in OBDF were less, which would not cause local ecological risk or health risk to the drilling crew. However, the concentrations of various aromatics analyzed in OBDF were very high, which was easy to pose serious environmental and health hazards. There were 8 aromatic hydrocarbons (AHs) in NOBDF and 15 AHs in COBDF. And the total carcinogenic risk value of each aromatic hydrocarbon was far greater than 10-4, which belonged to an unacceptable level. In addition, the inhalation pathway seemed to be the most significant source of carcinogenic risk, accounting for 99% of the total carcinogenic risk. Meanwhile, it is recommended to equip drilling workers with gas masks and develop all-oil biodiesel drilling fluid.

E&P Notes (December 2021)

E&P Notes (December 2021)

Numerical Simulation Based on the Canister Test for Shale Gas Content Calculation

The accurate determination of the gas in place in shale reservoirs is a basic but challenging issue for shale gas evaluation. Conventional canister gas desorption tests on retrieved core samples and subsequent data analyses (via linear or polynomial regression)—originally developed for coalbed methane, where gases are mainly stored in the adsorbed phase—is unadvisable for shale gas, which is stored as an appreciable amount of free gas in shale reservoirs. In the present study, a mathematical model that simultaneously takes into account gas expansion, adsorption/desorption, and the gas flow in shale is proposed to simulate gas release from a core sample retrieved from the Lower Silurian Longmaxi Formation of the Fuling shale gas field, Sichuan Basin. The results indicate that, compared with the value of 2.11 m3/t rock estimated with the traditional United States Bureau of Mines (USBM) method, the total gas in place within the studied Longmaxi Shale estimated with our mathematical model under reservoir pressure conditions is up to 5.88 m3/t rock, which is more consistent with the result from the new volumetric approach based on Ambrose et al. According to our mathematical model, the content of free gas is 4.11 m3/t rock at true “time zero”, which accounts for 69.9% of the total gas. On the other hand, the lost gas portion is determined to be up to 4.88 m3/t rock (~85% of the total gas). These results suggest that the majority of the free shale gas is actually trapped within the pore space of the shale formation.

Characterizing the characteristics of natural fractures in shale based on the modified petrophysical model

In order to provide technical support for the shale gas exploration and development in the Lower Silurian Longmaxi Formation of the Sichuan Basin, this paper takes the Longmaxi Formation in the Changning and Fuling Shale Gas Fields as the research object to quantitatively characterize the development characteristics of natural fractures in the Longmaxi Formation shale by means of helium pycnometry, X-ray diffraction (XRD), true density testing and other methods, with the aid of the modified petrophysical model. Then, the development types and genetic mechanisms of natural fractures and their influences on shale gas development are discussed. The following research results are obtained. First, the modified petrophysical model can accurately describe the pore system in the Changning shale with a fitting rate of 0.74. Second, the development of natural fractures in shale is different in various regions. The natural fractures in the Changning Shale Gas Field, controlled by basement thrust faults, decollement layers and internal folds, are locally developed and filled with calcareous, and the average fracture porosity is 0.15%. In the Fuling Shale Gas Field, however, natural fractures, mainly controlled by reverse faults and slippage effect, are commonly more developed and unfilled or semi-filled with siliceous, and the average fracture porosity is 1.30%. Third, under the formation conditions, the opening of natural fractures is different. The natural fractures in the Changning Shale Gas Field are basically closed with weaker flowing ability, while those in the Fuling Shale Gas Field are relatively open with stronger flowing ability. Fourth, the occurrence mode of shale gas is influenced by natural fractures, and it is internally dominated by free gas. The initial gas production of shale gas wells is higher. In conclusion, (1) the regression coefficient is introduced to calculate the actual total organic matter content, which promotes the modified petrophysical model to describe matrix pores and fracture pores more accurately; (2) the development of natural fractures in the shale producing pay of the Sichuan Basin is relatively beneficial to shale gas enrichment and exploitation, but the flowing ability of the natural fractures will be weakened under the original formation conditions.

A non-empirical model for gas transfer through circular nanopores in unconventional gas reservoirs

It is difficult to predict the flow performance in the nanopore networks since traditional assumptions of Navier–Stokes equation break down. At present, lots of attempts have been employed to address the proposition. In this work, the advantages and disadvantages of previous analytical models are seriously analyzed. The first type is modifying a mature equation which is proposed for a specified flow regime and adapted to wider application scope. Thus, the first-type models inevitably require empirical coefficients. The second type is weight superposition based on two different flow mechanisms, which is considered as the reasonable establishment method for universal non-empirical gas-transport model. Subsequently, in terms of slip flow and Knudsen diffusion, the novel gas-transport model is established in this work. Notably, the weight factors of slip flow and Knudsen diffusion are determined through Wu’s model and Knudsen’s model respectively, with the capacity to capture key transport mechanism through nanopores. Capturing gas flow physics at nanoscale allows the proposed model free of any empirical coefficients, which is also the main distinction between our work and previous research. Reliability of proposed model is verified by published molecular simulation results as well. Furthermore, a novel permeability model for coal/shale matrix is developed based on the non-empirical gas-transport model. Results show that (a) nanoconfined gas-transport capacity will be strengthened with the decline of pressure and the decrease in the pressure is supportive for the increasing amplitude; (b) the greater pore size the nanopores is, the stronger the transport capacity the nanotube is; (c) after field application with an actual well in Fuling shale gas field, China, it is demonstrated that numerical simulation coupled with the proposed permeability model can achieve better historical match with the actual production performance. The investigation will contribute to the understanding of nanoconfined gas flow behavior and lay the theoretical foundation for next-generation numerical simulation of unconventional gas reservoirs.

Molecular-level variation of dissolved organic matter and microbial structure of produced water during its early storage in Fuling shale gas field, China.

Shale gas-produced water (PW), the waste fluid generated during gas production, contains a large number of organic contaminants and high salinity matrix. Previous studies generally focused on the end-of-pipe treatment of the PW and ignored the early collection process. In this study, the transformation of the molecular composition and microbial community structure of the PW in the transportation and storage process (i.e., from the gas-liquid separator to the storage tank) were investigated. As the PW was transported from the gas-liquid separator to the portable storage tank, the dissolved organic matter (DOM) showed greater saturation, less oxidation, and lower polarity. DOMs with high O/C and low H/C ratios (numbers of oxygen and hydrogen divided by numbers of carbon) were eliminated, which may be due to precipitation or adsorption by the solids suspended in the PW. The values of double-bond equivalent (DBE), DBE/C (DBE divided by the number of carbon), and aromatic index (AI) decreased, likely because of the microbial degradation of aromatic compounds. The PW in the gas-liquid separator presented a lower biodiversity than that in the storage tank. The microbial community in the storage tank showed the coexistence of anaerobes and aerobes. Genera related to biocorrosion and souring were detected in the two facilities, thus indicating the necessity of more efficient anticorrosion strategies. This study helps to enhance the understanding of the environmental behavior of PW during shale gas collection and provides a scientific reference for the design and formulation of efficient transportation and storage strategies to prevent and control the environmental risk of shale gas-derived PW.

Spontaneous imbibition characteristics of slickwater and its components in Longmaxi shale

During and after multi-stage hydraulic fracturing, the spontaneous imbibition of water-base fracturing fluid in shale formation is considered as the main mechanism responsible for the retention of large amounts of fracturing fluid. Slickwater is widely applied in Fuling shale gas field, the largest shale gas field in China. To characterize the spontaneous imbibition of slickwater and its four major components, experiments were carried out by using modified imbibition cells. Results show that all of the imbibition curves can be divided into three stages: linear imbibition stage, transition stage and stable imbibition stage. Their imbibition capacities are in the order of cleanup additive, clay stabilizer, slickwater, defoamer and friction reducer from highest to lowest. We have found that the imbibed volume is larger than the initial pore volume. Nuclear Magnetic Resonance (NMR) tests, core images and porosity comparison before and after imbibition all indicate the secondary microfractures were created during the imbibition process. The calculated volume of secondary microfractures which is the difference between the pore volume before and after the imbibition is very close to the imbibed volume, indicating the imbibition mainly through the microfractures. We also found that the imbibition rate of slickwater and its components in the order from highest to lowest is cleanup additive (0.087 cc/d), slickwater (0.058 cc/d), clay stabilizer (0.035 cc/d), defoamer (0.022 cc/d) and friction reducer (0.014 cc/d), indicating the synergy effect of slickwater components on the imbibition process and the role to optimize the cleanup additives during slickwater design.

Study on Development of Shale Gas Horizontal Well With Time-Phased Staged Fracturing and Refracturing: Follow-Up and Evaluation of Well R9-2, A Pilot Well in Fuling Shale Gas Field

In the development of the Fuling shale gas field, for the first time, Well R9-2 was selected for a test of time-phased staged fracturing and refracturing treatments to study the effectiveness of fracturing at each stage for a novel development approach exploration. This paper introduces the design of the experiments, analyzes the results, and provides a follow-up evaluation of the entire development process. As of 9 August 2020, the well had gone through three phases of development. Phase I: time-phased staged fracturing and development for Stages 1–2, 3–4, 5–6, and co-development for Stages 1–6; Phase II: Stages 1–6 were developed once more after refracturing; Phase III: sealing the sections in Stages 1–6, then fracturing and development of Stages 7–19. Pressure build-up tests were conducted during the development of Stages 1–2 and 3–4, and gas production profile logging and microseismic monitoring were performed during the co-development of Stages 1–6. The results show that the combination of time-phased staged fracturing and refracturing treatments can fracture each stage more effectively. The pressure build-up test can effectively obtain the reservoir parameters of developed shale gas wells. The potential of refracturing treatment in a developed well can be identified from the gas production profile logging and microseismic monitoring. The findings are of this study productive for enhanced shale gas recovery; the combined pattern of time-phased staged fracturing and refracturing acts as a direct guideline to future shale gas production.

Evaluating the connectivity of shale gas wells by new rare element tracers

Three types of rare earth elements, Pr, Yb and Sm, in shale gas well and fracturing fluid, which showed a low content and are environmentally friendly and chemically stable, formed complexes with ethylenediamine tetra-acetic acid and di-picolinic acid, both of which were applied as tracers in the determination of the connectivity of shale gas wells. A case study was made in two shale gas wells (Jiaoye 66-Z1HF and Jiaoye 66-Z2HF) of the middle gas reservoir in the Jiaoye No. 66 extended platform well group in the Fuling shale gas field of SINOPEC. We first injected rare element tracer into the wells, and then evaluated the connectivity of the Jiaoye No. 66 extended platform after fracuring by monitoring whether there was rare element tracer in the tracer-injected wells and the flow-back fluid from adjacent wells, and finally discussed the feasibility of three-dimensional development of the lower, middle and upper gas layers of the Fuling shale gas field. The results of flow-back fluid monitoring showed that a high content of Sm tracer, which had been injected into well Jiaoye 66-Z2HF, was occasionally found in well Jiaoye 66-Z1HF, indicating that there might be a connection between the middle gas layers of the two wells. There is no abnormal Pr, Yb or Sm concentrations in the monitoring wells of the lower gas layers, indicating that they were not connected with the central gas layers. A high concentration of Sm tracer was detected in the mixed back-flow fluid samples of wells Jiaoye 5-S2 and Jiaoye 5-S3 in the upper gas layer, indicating that they were connected to the central gas layers. The present investigation has verified that rare element tracer technology is a facile and effective method for the connection determination between shale gas wells and has broad application prospects.

Coevolutionary Dynamics of Organic-Inorganic Interactions, Hydrocarbon Generation, and Shale Gas Reservoir Preservation: A Case Study from the Upper Ordovician Wufeng and Lower Silurian Longmaxi Formations, Fuling Shale Gas Field, Eastern Sichuan Basin

Shale gas deposits are self-sourced, self-accumulating, and self-preserving in the Upper Ordovician Wufeng Formation and Lower Silurian Longmaxi Formation of the Fuling Shale Gas Field in the eastern Sichuan Basin. They were both seemingly mixed by secondary oil cracking and kerogen cracking gases during the high maturation window. The reservoir space primarily consists of mineral pores and organic matter (OM) pores, and the shale gas was mainly trapped by a high-pressure system. In this study, the Fuling O3w-S1l Shale Gas Field in the eastern Sichuan Basin was used as a case study to discuss the coevolutionary process and organic-inorganic interactions of hydrocarbon generation, accumulation, and preservation. The results indicate that the processes and mechanisms of organic-inorganic interactions and coevolution of hydrocarbon generation and reservoir preservation are quite different among the shale graptolite zones (GZ) with respect to hydrocarbon generation, types and characteristics of shale gas reservoirs, seal characteristics, and their spatiotemporal relations. In the WF2-LM4 GZ, the favorable OM, biogenic authigenic quartz and organic-inorganic interactions are highly coupled, leading to the high level of coevolution demonstrated within the field, as well as to the favorable conditions for shale gas accumulation. Conversely, the overlying LM5-LM8 GZ seemingly exhibits early densification and late charge and has a reverse mode of reservoir development (i.e., low degree of coevolution). These two coevolutionary processes were conducive to the development of a high degree of spatiotemporal matching between the reservoir (i.e., WF2-LM4 GZ) and the seal (i.e., LM5-LM8 GZ). This is due to underlying differences in their coevolutionary histories. The synthetic work presented here on the coevolutionary processes and mechanisms of formation for organic-inorganic interactions and hydrocarbon generation and reservoir preservation reveals insights into the driving mechanisms of shale gas enrichment, providing a basis for effectively predicting favorable enrichment intervals for shale gas worldwide.

Productivity forecast for multi-stage fracturing in shale gas wells based on a random forest algorithm

ABSTRACT This study addresses the problem of low-accuracy production forecasting for horizontal shale gas wells by applying a random forest algorithm and considering both the physical reservoir parameters and the engineering fracturing parameters. Based on the interpretation of logging data, drilling data, fracturing data, and sectional production data from the Fuling shale gas field, the random forest algorithm was used to build a regression model, through partial correlation analysis and recursive feature elimination to select the optimal key influencing factors. The study revealed that the layer, cluster spacing, number of clusters, 40/70 mesh low-density ceramsite (medium sand), and total proppant are the key factors influencing sectional production, and they all have different effects on it. The random forest algorithm showed better prediction capacity than the other algorithms. Its coefficient of determination and root-mean-square error on the test set were 0.723 and 0.319, respectively, which indicates that it is an effective approach and has good generalization ability. The prediction results of the productivity regression model based on the random forest algorithm, combined with the trend surface response analysis, were used to obtain the optimal values of the six key fracturing parameters of the unfractured well.

Explaining Local Residents' Attitudes toward Shale Gas Exploitation: The Mediating Roles of Risk and Benefit Perceptions.

Using Fishbein’s multi-attribute model, this paper proposes that the impact of socio-demographic and psychosocial factors on local residents’ overall attitude toward shale gas exploitation (SGE) is mediated by their risk and benefit perceptions. The proposition has been validated with the generalized structural equation modeling approach with a cross-sectional dataset of 825 residents from China’s Fuling shale gas field. Results indicate that the influence of benefit perception on residents’ overall attitude outweighs that of risk perception. Moreover, residents’ perceived fairness, affective feeling, and trust in regulatory agencies have positive influences on their overall attitude, primarily via their risk and benefit perceptions, in decreasing order of influences. Finally, we also find that residents’ attitudes have been significantly influenced by their socio-demographic factors, including age, residential area, and political ideology. Thus, our study extends the literature with theoretical and empirical models by exploring the influences factors of local residents’ attitudes toward SGE, and results from our empirical survey provide insight into policy design to promote the acceptance of SGE.

Numerical simulation of hydraulic fracture propagation in laminated shale reservoirs

Abstract The main area of the Jiaoshiba anticline of the Fuling shale gas field was taken as the research object, laboratory rock mechanical experiments and direct shear experiments were conducted to clarify the mechanical anisotropy characteristics and parameters of rock samples with rich beddings. Based on the experimental results, a 3D fracture propagation model of the target reservoir taking mechanical anisotropy, weak bedding plane and vertical stress difference into account was established by the discrete element method to analyze distribution patterns of hydraulic fractures under different bedding densities, mechanical properties, and fracturing engineering parameters (including perforation clusters, injection rates and fracturing fluid viscosity). The research results show that considering the influence of the weak bedding plane and longitudinal stress difference, the interlayer stress difference 3–4 MPa in the study area can control the fracture height within the zone of stress barrier, and the fracture height is less than 40 m. If the influence of the weak bedding plane is not considered, the simulation result of fracture height is obviously higher. Although the opening of high-density bedding fractures increases the complexity of hydraulic fractures, it significantly limited the propagation of fracture height. By reducing the number of clusters, increasing the injection rate, and increasing the volume and proportion of high-viscosity fracturing fluid in the pad stage, the restriction on fracture height due to the bedding plane and vertical stress difference can be reduced, and the longitudinal propagation of fractures can be promoted. The fracture propagation model was used to simulate one stage of Well A in Fuling shale gas field, and the simulation results were consistent with the micro-seismic monitoring results.

Variations of Pore Structure in Organic-Rich Shales with Different Lithofacies from the Jiangdong Block, Fuling Shale Gas Field, SW China: Insights into Gas Storage and Pore Evolution

The pore structure of gas shale reservoirs strongly influences gas occurrence, migration and enrichment, which has become an important fundamental issue for shale gas exploration and production. To...

Heterogeneous preferences for shale water management: Evidence from a choice experiment in Fuling shale gas field, southwest China

Increasing concerns about the water-related impacts posed by shale gas development have prompted the need for protecting water resources. Determining the preferences for shale water management is critical for the design and implementation of cost-effective management strategies. Nevertheless, the public's multidimensional preferences for different aspects of the shale water management have not yet been addressed in shale-related studies. To this end, a choice experiment is used to examine the preference heterogeneity for shale water management that would improve water consumption, wastewater recycling, and water quality monitoring in Fuling shale gas field, southwest China. Results from a random parameter logit model show that residents' average WTP is 45.76 yuan per year per household for the improvements of all water-related attributes to the highest qualitative level. The accumulated welfare gains indicate that local government could increase the gas price by 0.058 yuan per cubic meter for implementing water management strategies. We also find considerable preference heterogeneity in both systematic and random utility components, and average WTP is significantly influenced by the respondent's demographical and psychological characteristics. The findings highlight the potential to find socially acceptable ways to promote shale water management and provide insight into the relevant policymaking process.

An overview of the geology and production of the Fuling shale gas field, Sichuan Basin, China

The Fuling shale gas field in China is the largest shale gas field as well as the largest of its type discovered in any Lower Paleozoic formation. In this study, the geology and production of the upper and lower gas layers in the Fuling shale gas field are evaluated in terms of structure, shale quality, fault, initial production, and estimated ultimate recovery (EUR). The shale in the lower gas layer of the Jiaoshiba anticline is a high-quality reservoir, where the space is dominated by organic pores in kerogen, and the gas content is high. The shale gas wells reveal relatively high initial production and EUR. However, the shale in the upper gas layer of the Jiaoshiba anticline has reservoir space mainly composed of clay mineral pores and organic pores within bitumen, and the gas content is low. In terms of structure, primary gas migration may occur in the upper gas layer, resulting in free gas accumulation in the structural high, where the development effects are generally better than those in the structural low. The lower gas layer in the Pingqiao anticline, is the main interval for shale gas accumulation and development due to the high-quality shale. Under the influence of faults, the efficiency of exploration wells emplaced on top of the anticline is much lower a compared with those in the flanks. The residual synclines close to the Sichuan Basin, including the Baima and Baitao anticlines, are characterized by more recent uplifts, larger area, greater distance from the deep and large faults, and early fracture closure. Therefore, we recommend that the shale gas exploration and development should be carried out preferentially in areas close to the center of the residual synclines, featuring relatively high-pressure coefficient and moderate burial depth.

A time-lapse CSEM monitoring study for hydraulic fracturing in shale gas reservoir

Hydraulic fracturing has been widely used in shale gas production. During the hydraulic fracturing, microcracks are open and filled with the conductive fluid, which enhances the overall hydraulic conductivity of the shale formulation. Undoubtedly, the monitoring of the fracturing process is crucially important for shale gas production. The controlled source electromagnetic method (CSEM) is sensitive to the electric conductivity change and can potentially be used for monitoring hydraulic fracturing. In this paper, we carried out numerical modeling and a field test on the CSEM monitoring of hydraulic fracturing at the Fuling shale gas field in southern China. Firstly, we perform the numerical modeling based on a synthetic model derived from the logging data of the field test site to investigate the effect of the steel-cased well on EM responses. Then, we investigate EM responses at the surface caused by the shale gas reservoir for different configurations to optimize survey parameters. Subsequently, the optimal broadside survey system is applied to investigate the effectiveness of CSEM monitoring on a synthetic hydraulic fracturing process. Finally, a real application is applied to carry out the time-lapse CSEM monitoring of the hydraulic fracturing during the shale gas production. Both the modeling results and the field data show the optimistic potential of use CSEM monitoring on the hydraulic fracturing process applied in the shale gas production.

Temperature and origin of fluid inclusions in shale veins of Wufeng–Longmaxi Formations, Sichuan Basin, south China: Implications for shale gas preservation and enrichment

In the southeastern Sichuan Basin, the Wufeng–Longmaxi Formations are major strata used for shale gas exploration and development. Although the Fuling shale gas field—the largest Lower Paleozoic shale gas field in the world—has already been developed, shale gas wells in other parts of this area apart from the Jiaoshiba anticline vary greatly in production capacity. Microstructures and inclusion homogenization temperatures were analyzed for venous fluid inclusions in samples taken from the main shale gas wells in the Wufeng–Longmaxi Formations and were combined with simulated burial–thermal histories, hydrocarbon generation and expulsion histories, and fracture formation–closure times and stages to determine how fracture and fluid activities influenced shale gas preservation/destruction conditions. Veins were composed of quartz, calcite, and quartz–calcite and contained gas–liquid two-phase brine and high-density methane inclusions. Combined with simulated burial–thermal histories, the results showed that fracture-fluid activity time could be inferred from inclusion homogenization temperatures and was consistent with gas content and output of shale gas wells. The deeper and earlier the vein formation, the more favorable the preservation conditions of the shale gas reservoir. Furthermore, the more the fracture formation–closure stages and the lower the inclusion homogenization temperature, the more severe damage to the shale gas reservoir has happened. Clearly, in areas from Jiaoshiba to Pingqiao, Nanchuan, and Dingshan in the southwest, increasing the number of paleo-fluid activity and vein formation stages, as well as later paleo-fluid activity time, worsened shale gas preservation conditions. The results can act as a reference for studying fracture-fluid activity, enrichment, and preservation of shale gas in the southeastern Sichuan Basin and other parts of the world.

Water use for shale gas development in China’s Fuling shale gas field

A large volume of water is required in shale gas development, especially for large-scale hydraulic fracturing in horizontal wells. This study focuses on 334 shale gas wells in the largest production field Fuling in China. Models are formulated to estimate the water use at each stage of the development process, including pre-drilling preparation, drilling and cementing, fracturing, gas testing, production testing. Domestic water used by employee community of shale gas companies are also fully considered. The results show that the average fracturing water use per well was 34,756.0 m3 in Fuling, which accounted for 98% of the total water use. By the end of 2017, the total fracturing water used in Fuling was 1.09 × 107 m3, and a total of 2.28 × 106 m3 of flowback fluid was achieved with 2.16 × 106 m3 of water reused. In addtion, the domestic water used by the employee community was found to be 2.19 × 106 m3, which was equivalent to the water saved from the flowback fluid. China’s special “development campaign” mode for shale gas extraction is the reason. The results improve the understanding of water use in China’s shale gas development and also provide important implications for water management.

Research and Application of Plunger Gas Lift Technology in the Fuling Shale Gas Field

Plunger gas lift technology is often used for drainage of water and gas recovery in gas wells.However,the conventional short plunger cannot solve some problems in shale gas well in Fuling Shale Gas Field,such as the large master valve on wellhead and downhole variable-diameter pipe string,therefore,an elastic block variablediameter combined plunger was developed.The plunger adopts the design of elastic block and lengthening,which not only ensures the passage of the plunger,but also effectively reduced the leakage rate of the plunger.The temperature and pressure instruments are installed in the plunger to monitor the downhole pressure and the running state of the plunger,so as to provide the basis for adjusting the operating system of the plunger.According to the production characteristics of shale gas wells at different stages,the intervention time and operation system of plunger gas lift are optimized.Plunger lift technology has been applied in 34 wells in Fuling Shale Gas Field,with average daily gas production of a single well increased by 0.95×10^4 m^3,realizing shale gas production continuously and stably.The plunger gas lift technology provides a new technical way for the efficient development of Fuling Shale Gas Field,and has a function of guiding the development in other shale gas fields.