Number Of Production Wells Research Articles

Qualitative Analysis and Quantitative Evaluation of Fracturing Disturbance in the Mahu 18 Block

In response to the fracturing disturbance problem in the Mahu 18 block, based on the production data of on-site fracturing disturbance well groups, the actual fracturing disturbance cases in the block were first statistically divided. The complex fracturing disturbance situation in the block was divided according to the relationship between the number of fracturing wells and the number of production wells. Then, the disturbance types were classified based on the production dynamic response characteristics of the disturbed wells, and the degree of disturbance was quantitatively evaluated for the different types. The results indicate two main types of fracturing interference in the Mahu 18 block: the fracture communication type, and the pressure wave interference type formed through inter-well connectivity through the reservoir matrix. The fracturing disturbance dominated by fracture communication can cause serious water channeling to the production well through the direct connection of inter-well fractures, leading to a surge in water production. This type of fracturing disturbance often has a severe negative impact on the production well. In addition, the pressure and production (water production, liquid production, oil production) in the production dynamic response characteristics of disturbed wells during fracturing disturbance were used as evaluation indicators to quantify the impact of different types of fracturing disturbance from multiple perspectives.

Corrigendum: The number of production wells affects the heat extraction performance of an enhanced geothermal system: insights from engineering-scale 3D THM coupling numerical simulations

Corrigendum: The number of production wells affects the heat extraction performance of an enhanced geothermal system: insights from engineering-scale 3D THM coupling numerical simulations

Submarine slope stability during the exploitation of natural gas hydrate from horizontal wells

Horizontal wells have the advantages of high production, considerable access to reserves, and effective sand production control; thus, they are potential well types for hydrate exploitation. In the process of hydrate mining, the decomposition of hydrate will cause the deterioration of the mechanical properties of the reservoir, which may induce submarine landslides, especially in the case of multiple horizontal wells, and the risk of submarine landslides is further increased. Therefore, it is necessary to study the influence of the horizontal well pattern adopted for hydrate mining on the stability of submarine slopes. First, a triaxial mechanical experiment of gas hydrate-containing sediments was carried out, and the mechanical parameters of the hydrate-containing sediments were obtained. Second, a thermal-fluid-solid multifield coupling model considering the hydrate phase transition during the production process was established. Finally, on the basis of the finite element strength reduction method, a slope stability evaluation model for hydrate extraction from a horizontal well pattern was established, and the influence of hydrate extraction from horizontal wells on the stability of submarine slope was analyzed. The results show that the peak strength, elastic modulus and cohesion of gas hydrate-containing sediments increase with increasing hydrate saturation. In the process of hydrate exploitation via horizontal wells, with the reduction in well spacing and the increase in the number of production wells, the risk of slope instability increases. Wells positioned along the slope strike are more conducive to slope stability than those positioned perpendicular to the slope strike. The slope stability increases gradually as the slope dip decreases. When the number of wells is the same, the slope stability increases gradually with increasing well spacing and production pressure.

STUDY OF THE EFFECTIVENESS OF THE APPLICATION OF COMPLEX GEOLOGICAL AND TECHNOLOGICAL MEASURES ON THE EXAMPLE OF GAS-CONDENSATE GENERATION IN THE CENTRAL PART OF THE PRIAXIAL ZONE OF THE DNIPROV-DNETZ BASIN

The field development system is the basis of hydrocarbon production, as it ensures the achievement of the necessary technical and economic indicators. Therefore, a high-perfor- mance development system is necessary to ensure maximum profit in the shortest possible time. Empirical studies, analysis and assessment of the effect of implementing a complex of geological and technological measures on the operational facility of a gas condensate field in the central part of the peri-axial zone of the Dnieper-Donets Basin were carried out in order to find methods for improving the existing gas and gas condensate field development systems and increasing gas extraction rates. It is shown that due to hydraulic fracturing, drilling and transfer of wells to the production facility during the five years of production of the produced gas, it is 7.8 % more than in the previous 21 hours, the rate of development of the field from 2015 to 2019 increased from 2.52 %. to 7.9 %, the average well yield increased by 83 % with an increase in the operational fund by 55 %. The results of studies of the effect of the application of geo- logical-technological measures are shown in the form of graphical dependences of the change in the rate of sampling on the number of production wells over time, the rate of daily gas sampling on the number of conducted geological-technological measures on the researched operational object over time. It has been determined that the main driver of the increase in gas production is the hydraulic fracturing of the formation in most of the operational wells, thanks to which the average increase in the output of the wells is 425 %. According to the results of geological and industrial data processing and analysis of changes in the rate of daily gas extraction over time, the effect of the performed operations is divided into three time segments lasting 15–18 months. The decrease in the duration of the effect from the increase in the fund of production wells and the conduct of hydraulic fracturing of the reservoir is due to the decrease in the volume of reservoir energy, therefore the investigated complex of measures will have the greatest effect when implemented at the initial stage of the development of a reservoir with similar geological parameters.

Numerical simulation on converting abandoned wells into double-well open-loop geothermal system

Converting abandoned oil wells into geothermal systems holds immense potential and has garnered international attention. However, research on converting abandoned oil wells into Open-Loop Geothermal Systems (OLGS) remains insufficient and requires further exploration. To address this gap, this study utilizes COMSOL software employing the Finite Element Method (FEM) to establish a numerical model of a double-well OLGS with 3D multi-physics field coupling, investigating geothermal extraction through numerical simulation. The findings indicate that in double-well OLGS, utilizing high flow rates in the early production stage and lower flow rates in the later stages enhances system thermal power. Additionally, employing lower inlet temperatures in the early production stage and higher inlet temperatures in the later stages favors geothermal extraction. Higher geothermal gradients and larger well spacings further benefit geothermal extraction. Increasing the length of the production well's insulating layer in the early production stage helps minimize heat loss. The outlet temperature exhibits high sensitivity to flow rate and geothermal gradient throughout the production phase, while sensitivity shifts towards inlet temperature and well spacing in the later stages. In the five-spot OLGS, outlet temperature and thermal power increase with a reduction in the number of production wells; moreover, assuming identical outlet temperatures (100 ℃) after 50 years of production, the thermal power of the five-spot OLGS exceeds that of the double-well OLGS by an average of 20937.88 kW per year.

Prognozowanie wskaźników zagospodarowania złóż ropy naftowej i gazu ziemnego na podstawie danych z okresu początkowego

The practice of oil fields development indicates that the economic efficiency of this process is largely determined by the oil production regime, which is characterized by indicators of the intensity of hydrocarbon extraction: the total number of wells in the field, the dynamics of their commissioning, and production volumes from each of them. At the same time, when justifying oil production projects, it is a very common opinion that it is premature to address the problems of managing the rate of raw material selection in the early stages of project development, often relegated solely to petroleum engineering without consideration of economic aspects. This often leads to a decrease in the efficiency of the entire project due to the inability to control the oil production regime in later stages. This formulation of the problem is particularly relevant for new oil production regions. In well-studied oil and gas region, an error in selecting the rate of raw material production may not be so critical. However, in the case of new fields in undeveloped regions, the cost of such an error can significantly exceed the economic benefits derived from the sale of all the oil produced. In this regard, the problem of developing models and methods for determining economically feasible regimes for oil field development based on controlling the rate of product selection is relevant. The article predicts the dynamics of the following indicators of oil and gas field development: current and cumulative production of oil, water and gas, average well flow rate, and water cut depending on the number of production wells, etc. It demonstrates how it is possible to simplify two- and three-parameter models using the proposed forecasting technique.

A STATISTICAL ANALYSIS OF GEOLOGICAL AND ENGINEERING PREDICTORS OF OILFIELD PERFORMANCE RESPONSE: A CASE STUDY OF OILFIELDS ON THE UK CONTINENTAL SHELF

Oilfield production is controlled by a wide range of geological and engineering parameters, many of which are at least partially interrelated. This paper uses multivariate statistical methods (principal component analysis, regression analysis and analysis of variance) to determine how these parameters are related, and which of them are most significant in controlling and predicting oilfield performance. The analysis is based on a database of publicly available oilfield data from the United Kingdom Continental Shelf (UKCS), from which a series of geological, engineering and fluid‐related control variables from 136 fields were pre‐processed and analyzed. This dataset is a subset of a much wider project database for UKCS oil, gas and condensate fields. For this study, the project database was divided into two datasets: a first dataset with 10 parameters from 136 fields, and a second, more detailed dataset with 27 parameters from 38 fields. Both datasets were analysed using principal component analysis in order to investigate possible correlations between numerically/statistically interrogable predictor variables such as porosity, permeability, number of production wells, gas‐oil ratio and reservoir temperature. A regression analysis was then carried out on the predictor variables in order to obtain a ranking of predictability (i.e. how indicative a predictor is of a particular outcome) and sensitivity (how sensitive an outcome is to slight changes in a predictor) in relation to recovery factor based on R‐squared and regression coefficient values. The results showed that key variables from the principal component analysis included field size, number of production wells, PVT, gross depositional environment and reservoir quality. High‐ranking parameters of predictability and sensitivity from the regression analysis were found to include API, net‐to‐gross, porosity and reservoir depth. These results are consistent with previous studies and suggest that it should be possible to forecast oilfield recovery based on only a few selected input variables. As a preliminary test of forecasting ability of the variable permutations put forward, a best‐subsets multiple regression was carried out using a statistical software package and yielded results which corroborated the main findings.

Evaluation of the Potential for CO2 Storage and Saline Water Displacement in Huaiyin Sag, Subei Basin, East China

CO2 geological storage combined with deep saline water recovery technology (CO2-EWR) is one of the most effective ways to reduce carbon emissions. Due to the complex structural features, it is difficult to use CO2-EWR technology in Huaiyin Sag, Subei basin, East China. In this study, the multi-source information superposition evaluation technology of GIS was utilized for the selection of CO2 storage sites and water displacement potential target areas in this area, which mainly focused on the sandstone reservoirs of Cretaceous Pukou Formation. Based on the results, a three-dimensional injection–extraction model was established. Various scenarios with different production/injection well ratios (PIR) were simulated. Research has shown that the suitability of the surrounding site of Huaiyin Power Plant can be divided into two levels: relatively suitable and generally suitable; the area in the generally suitable level accounts for more than 80%. At a PIR of 1, CO2 is distributed asymmetrically, whereas at PIRs of 2 or 4, CO2 is distributed symmetrically. When the number of production wells is constant, a higher injection rate results in a faster expansion rate of the CO2 plume. This means that the time taken for the CO2 plume to reach the production wells is shorter. Reservoir pressure increases rapidly after more than 60 years of CO2 injection at lower PIR values, while at higher PIRs, reservoir pressure eventually stabilizes. Higher PIR values correspond to higher gas saturation, indicating a greater capacity for CO2 sequestration with more producing wells. When PIR = 4, the total CO2 injection increased by 55.73% compared to PIR = 1. However, the extraction of saline decreases with an increase in the number of producing wells, resulting in a decrease in replacement efficiency. This study provides a theoretical basis and technical support for the implementation of large-scale CO2-EWR engineering and technology demonstration in this region.

Geothermal extraction performance in fractured granite from Gonghe Basin, Qinghai province, China: Long-term injection and production experiment

The efficient exploitation of geothermal energy through enhanced geothermal systems (EGS) has been a relevant topic for hot dry rock (HDR) geothermal resources. When cryogenic fluid is injected into a thermal reservoir, improving heat exchange efficiency is key to achieving the optimal exploitation of HDR. In this paper, granite outcrops from Gonghe Basin were used as the testing sample. The natural fractures in the granite samples were relatively well developed. To simulate long-term injection and production from multi-wells in situ, physical experiments were performed in a newly-developed, in-house large-scale true triaxial experimental system. Geothermal extraction performance of an HDR was simulated for long-term injection and production operations. Simultaneously, the mode of one-injection and multiple-production wells was represented. In the paper, the effects of the production-injection well spacing, the number of production wells and the injection rate on the production temperature and flow rate are discussed. The results show that, during long-term injection and production, there are two stages of production temperature variation, namely stabilization and attenuation. When the number of the production wells is increased, the heat extraction efficiency is accelerated. Moreover, competitive diversion of fluid among fractures occurred due to different conductivities. Furthermore, under different production modes, the production flow rate contributed differently to the heat extraction. Finally, the effect of the production-injection wells spacing on the heat exchange performance was analyzed; this is mainly reflected in the change of the effective heat exchange area between the rock and the injected fluid. The results emphasize the importance of designing an appropriate production mode and optimizing the injection-production parameters to ensure efficient HDR exploitation.

Research on Hydrolithospheric Processes Using the Results of Groundwater Inflow Testing

The article considers a mathematical model of the hydrolithospheric process taking into account the skin effect. A methodology for using the results of groundwater inflow testing to determine the parameters of approximating models that take into account skin effects is presented. In addition, the problems of modeling hydrodynamic processes taking into account random factors are considered. A statistical analysis of well monitoring data was carried out and an algorithm for studying processes was developed. Using the obtained approximating models, a procedure for solving the problem of selecting the optimal number of production wells has been developed. Based on the results of the groundwater inflow testing, the prospects for the development and use of new aquifers can be determined.

The number of production wells affects the heat extraction performance of an enhanced geothermal system: insights from engineering-scale 3D THM coupling numerical simulations

Enhanced geothermal systems (EGSs) are expected to be one of the most promising methods of supplying energy to meet the world’s increasing energy demand. However, little attention has been paid to the influence of the number of production wells on the heat extraction performance of an EGS. A series of numerical simulations is organized in this work with three cases: Case 1 (one production well), Case 2 (two production wells), and Case 3 (three production wells). The results indicate that a slight temperature difference exists among the three simulation cases at the planes X-Y (Z = 0) and Y-Z (X = 0), while Case 1 ensures a greater cooling area, and the more production wells, the smaller the cooling area during the heat extraction in plane X-Z (Y = 0). In addition, the continuous injection of cooling water from the injection well and its arrival at different reference points enable the temperature at each point to declining with a variable amplitude of variation. This work also sets an efficiency (ef) to investigate the temperature variation in the EGS, where Case 1 exhibits a similar variation as Case 2, which is also similar to Case 3. It is hoped that this work will play a guiding role in EGS-related exploration and exploitation.

Исследование пластового флюида при разработке месторождений на шельфе Kарского моря

Introduction. With the expansion of offshore drilling and the distance of fields from the coastline, the number of production wells located in difficult underwater geological conditions is increasing, which complicates research. For example, the Yurkharovskoye field is located in a strip along the Tazovsky Peninsula under the waters of the Kara Sea. At the same time, the data obtained from the results of research are necessary when calculating reserves and designing the development of hydrocarbon deposits. Materials and research methods. Modeling of the operating conditions of the field under various thermodynamic conditions was carried out in order to determine the effect of water vapor and oil fractions on condensate losses during the development of the deposit [6–9]. The experiments were carried out to determine the amount of condensate in the reservoir gas, the physicochemical properties of hydrocarbons, and the effect of heavy oil fractions on condensate recovery [5, 10]. Prediction of condensate losses in the reservoir depending on the influence of negative factors must be taken into account when calculating hydrocarbon reserves and drawing up a field development project [11, 13]. Research results and their discussion. In the studied part of the section of the Yurkharovskoye field, located on the shelf of the Taz Bay, gas deposits were identified in the Aptian-Albian-Cenomanian complex and gas condensate deposits with oil rims in the Neocomian complex. The selection of development objects was based on a set of geological and geophysical data, the main of which are the presence of reservoirs and seals in the section and a single hypsometric position of the GWC or WOC in the case of an oil and gas condensate deposit. Correlation of well sections and identification of productive formations was based on the choice of benchmarks, the similarity of well logs, taking into account the nature of reservoir saturation and well test results. As a result of experimental PVT studies, the influence of water vapor and oil fractions as an integral part of the hydrocarbon system on the reservoir losses in the deposit was determined. The analysis of the performed studies confirmed that multicomponent hydrocarbon systems consist of a mixture of gas, condensate and water vapor, as well as oil fractions, which significantly changes the properties of the system and the dynamics of its phase processes during the development of the Yurkharovskoye field. Conclusions. The conducted PVT-experiments in order to identify the effect of water vapor and oil components that are part of natural gas showed that the predicted current and final condensate recovery factors are overestimated. An analysis of the research results revealed a different effect of water vapor on reservoir losses of hydrocarbons in the deposit due to an increase in partial pressure. In the presence of formation water in the gas condensate system, the CFC value decreased to 4-5%. Thus, the reason for the increase in reservoir losses of condensate in the deposit during the development of oil and gas condensate fields on the shelf of the Kara Sea was determined.

Numerical Simulation on the Heat Recovery Law of Exploiting Geothermal Energy from a Closed-Loop Geothermal System Converted from an Abandoned Five-Spot Well Pattern.

Exploiting geothermal energy from abandoned wells is a research hotpot at present. However, there is still a lack of research on exploiting geothermal energy using an abandoned well pattern. Aiming at this problem, in this paper, a novel method for exploiting geothermal energy from an abandoned well pattern is proposed. An unsteady heat transfer model is proposed to study the influence of some key parameters on the production law of the novel scheme, and the proposed model is verified with field experimental data. The result indicates that there exists a critical flow rate that can change the form of the characteristic curve of the outlet temperature with production time. The change of flow rate has more influence on the outlet temperature than that of temperature. A higher geothermal gradient is conducive to production. When the total number of wells and the total flow rate of the system are fixed, fewer production wells will be conducive to production. When the number of production wells and injection wells is determined, changing the deployment of production wells and injection wells has little effect on the outlet temperature and thermal power.

Influence Factors on EGS Geothermal Reservoir Extraction Performance

The heat extraction performance of the enhanced geothermal system is simulated by using COMSOL software. The effects of six factors, such as the thermal conductivity of heat reservoir, matrix permeability, fracture width, injection temperature, injection flow rate, and the number of wells, on the heat extraction performance of EGS heat reservoir for 40 years are analyzed. The results show that the matrix permeability and injection flow are the main factors affecting the heat production performance of the EGS geothermal reservoir, while the thermal conductivity, fracture width, and injection temperature have little effect on the heat production performance of the EGS geothermal reservoir. Although increasing the number of production wells can improve the uneven distribution of the flow field to improve the system heat performance, taking into account the existing drilling technology and cost, the cost is higher, and the two-well system is still the basic form of absorbing rock heat.

Experimental Study on the Seepage Characteristics of Multilayer Commingled Production and Influencing Factors of the Development Effect in Low-Permeability Tight Sandstone Gas Reservoirs.

For low-permeability tight sandstone gas reservoirs, multilayer commingled production technology is usually adopted by a large number of production wells. This production method can significantly increase the productivity of a single well, thereby improving the efficiency of gas field development. To have a better understanding of the seepage characteristics of multilayer commingled production of the SXM (ShaXiMiao) Formation tight sandstone gas reservoirs, an indoor physical simulation experiment of commingled injection and separate production using double-pipe parallel long cores was designed under influencing factors such as formation pressures, permeability contrast, and water saturations. Finally, the contribution of high- and low-permeability reservoirs to the total production capacity under different conditions is clarified, which provides a reference for formulating reasonable development strategies for gas reservoirs. Through the experimental study, we found that the recovery degree of the high-permeability formation is higher than that of the low-permeability formation during the depletion production process. The combination of depletion development and water flooding can greatly increase the recovery degree of gas reservoirs. Under the same production pressure difference condition, the higher the formation pressure and the permeability, the higher the production capacity. If the water saturation increases, the production contribution rate of the high-permeability layer gradually increases, and the production contribution rate of the low-permeability layer gradually decreases.

A new method for evaluating the spatial correspondence between surface and subsurface geological lineaments: A case from the Potiguar Basin, NE Brazil

This paper provides a new technique for evaluating lineaments that focuses on the spatial link between surface and subsurface elements in a single layer. We chose a test area in northeast Brazil's Borborema Province. We extracted magnetic and relief lineaments from aeromagnetic and SRTM data. We defined the lineaments that agree on both layers using GIS operations. To identify the concordance between lineaments, we constructed kernel density maps that combined the data from each layer. We detected NE-SW solid conditioning of the structures. Even when evaluating only the concordant lineaments in other directions, they are expressed in groupings in NE-SW, as with NW-SE features, that associates with transfer failures and are contained by large NE-SW structures. The Atlantic Ocean's opening and expansion phases were linked to the E-W direction, also truncated by NE-SW lower density sections. The N–S trend was inexpressive. Areas with a higher density of concordant lineaments were associated with regions more susceptible to the Neotectonics of landform inversion, forming domes and arches-oriented NE-SW, as in Serra do Mel, Macau High, and Ponta Grossa High. Lower lineament density areas indicated visual correspondence with the most significant number of production wells in the Potiguar Basin, indicating that these regions are more favorable for the accumulation and trapping of hydrocarbons.

Economic Critical Resources for the Industrial Exploitation of Natural Gas Hydrate

AbstractSince the implementation of several pilot production tests were in natural gas hydrate (NGH) reservoirs in terrestrial and marine settings, the study of NGH has entered a new stage of technological development for industrial exploitation. Prior to the industrial exploitation of any given NGH reservoir, the economic feasibility should be examined. The first step of economic evaluation of a NGH reservoir is to know whether its resource amount meets the requirement for industrial exploitation. Unfortunately, few relevant studies have been conducted in this regard. In this study, the net present value (NPV) method is employed to estimate the economic critical resources required for the industrial exploitation of NGHs under different production scenarios. Sensitivity analysis is also performed in order to specify the effects of key factors, such as the number of production wells, gas price, technological improvement and tax incentive, on the economic critical resources. The results indicate that China requires the lowest economic critical resource for a NGH reservoir to be industrially exploited, ranging from 3.62 to 24.02 billion m3 methane. Changes in gas price and tax incentives also play significant roles in affecting the threshold and timeline for the industrial exploitation of NGH.

A Big Data Method Based on Random BP Neural Network and Its Application for Analyzing Influencing Factors on Productivity of Shale Gas Wells

In recent years, big data and artificial intelligence technology have developed rapidly and are now widely used in fields of geophysics, well logging, and well test analysis in the exploration and development of oil and gas. The development of shale gas requires a large number of production wells, so big data and artificial intelligence technology have inherent advantages for evaluating the productivity of gas wells and analyzing the influencing factors for a whole development block. To this end, this paper combines the BP neural network algorithm with random probability analysis to establish a big data method for analyzing the influencing factors on the productivity of shale gas wells, using artificial intelligence and in-depth extraction of relevant information to reduce the unstable results from single-factor statistical analysis and the BP neural network. We have modeled and analyzed our model with a large amount of data. Under standard well conditions, the influences of geological and engineering factors on the productivity of a gas well can be converted to the same scale for comparison. This can more intuitively and quantitatively reflect the influences of different factors on gas well productivity. Taking 100 production wells in the Changning shale gas block as a case, random BP neural network analysis shows that maximum EUR can be obtained when a horizontal shale gas well has a fracture coefficient of 1.6, Type I reservoir of 18 m thick, optimal horizontal section of 1600 m long, and 20 fractured sections.

Modeling of the reservoirs heating with the aim of oil recovery increasing

The object of the research is optimal installation of the heat injection wells for reservoirs heating in order to increase oil recovery and, accordingly, support oil production in the hard-reaching heterogeneous reservoirs. One of the most problematic areas in modern oil production is the difficulty of extracting high-viscosity oil from the reservoirs. So far, the most effective method to overcome this problem is the thermal method. However, the possibilities of this method are limited by its high energy consumption and the cost of relevant practice research. Thus, less expensive corresponding methods of mathematical modeling become more important. This investigation uses a combined finite-element-difference method for the non-stationary thermal conductivity problem. Numerical modeling of the temperature distribution around heat injection wells are carried out, taking into account the heterogeneity of the thermal properties of the oil reservoir and the conditions of convective heat exchange at the reservoir’s boundaries. The proposed method, due to its high accuracy and convergence of the solutions, allows to obtain reliable practical results and has a number of advantages in comparison with the same research methods. It is established that the process of heating of oil reservoirs is slow and energy consuming, so to increase profitability, it is obviously necessary to use associated production products, such as associated gas. It is shown that less wet layers heat up better and there is no sense to heat the layer for more than two weeks, because the radius of the effective heating area (with a temperature exceeding 80 °C required for outcome of high-viscosity oil from the rock) in this case is sufficient. It is also found that the operation of heat-injection wells is more profitable with their joint interaction, in that case the effective heating area of the oil reservoir and, accordingly, the number of production wells will be the largest. Another hand, the main factor in the location of heat-injection wells is defined by special characteristics of the oil-bearing section of the reservoir in each case. The configurations of the location of heat-injection wells, which were presented in this paper, cover the most optimal cases of the installations of considered oil-bearing section of the reservoirs and can be used in practice.

Data-driven approaches for time series prediction of daily production in the Sulige tight gas field, China

The Sulige tight gas field is presently the largest gas field in China. Owing to the ultralow permeability and strong heterogeneity of the reservoirs in Sulige, the number of production wells has exceeded 3,000, keeping the stable gas supply in the decade. Thus, the daily production prediction of gas wells is significant for monitoring production and for implementing and evaluating stimulation measures. Therefore, on the basis of the three data-driven time series approaches, the daily production of 1692 wells over 10 years was mining for the daily production prediction of wells in Sulige. The jointed deep long short-term memory and fully connected neural network (DLSTM-FNN) model was proposed by introducing the recurrent neural network's sequential expression ability and was compared with random forest (RF) and support vector regression (SVR). After the daily production predictions of thousands of wells in Sulige, the proposed DLSTM-FNN model significantly improved the time series prediction accuracy and efficiency in the short training samples and had strong availability and practicability in the Sulige tight gas field.