Investigation of influence factors on CO_(2) flowback characteristics and optimization of flowback parameters during CO_(2) dry fracturing in tight gas reservoirs

CO_(2) dry fracturing is a promising alternative method to water fracturing in tight gas reservoirs,especially in water-scarce areas such as the Loess Plateau.The CO_(2) flowback efficiency is a critical factor that affects the final gas production effect.However,there have been few studies focusing on the flowback characteristics after CO_(2) dry fracturing.In this study,an extensive core-to-field scale study was conducted to investigate CO_(2) flowback characteristics and CH_(4) production behavior.Firstly,to investigate the impact of core properties and production conditions on CO_(2) flowback,a series of laboratory experiments at the core scale were conducted.Then,the key factors affecting the flowback were analyzed using the grey correlation method based on field data.Finally,taking the construction parameters of Well S60 as an example,a dual-permeability model was used to characterize the different seepage fields in the matrix and fracture for tight gas reservoirs.The production parameters after CO_(2) dry fracturing were then optimized.Experimental results demonstrate that CO_(2) dry fracturing is more effective than slickwater fracturing,with a 9.2%increase in CH_(4) recovery.The increase in core permeability plays a positive role in improving CH_(4) production and CO_(2) flowback.The soaking process is mainly affected by CO_(2) diffusion,and the soaking time should be controlled within 12 h.Increasing the flowback pressure gradient results in a significant increase in both CH_(4) recovery and CO_(2) flowback efficiency.While,an increase in CO_(2) injection is not conducive to CH_(4) production and CO_(2) flowback.Based on the experimental and field data,the important factors affecting flowback and production were comprehensively and effectively discussed.The results show that permeability is the most important factor,followed by porosity and effective thickness.Considering flowback efficiency and the influence of proppant reflux,the injection volume should be the minimum volume that meets the requirements for generating fractures.The soaking time should be short which is 1 day in this study,and the optimal bottom hole flowback pressure should be set at 10 MPa.This study aims to improve the understanding of CO_(2) dry fracturing in tight gas reservoirs and provide valuable insights for optimizing the process parameters.

Simulation of Gas-Water Two-Phase Flow in Tight Gas Reservoirs Considering the Gas Slip Effect

A mathematical model for the gas-water two-phase flow in tight gas reservoirs is elaborated.The model can account for the gas slip effect,stress sensitivity,and high-speed non-Darcy factors.The related equations are solved in the framework of a finite element method.The results are validated against those obtained by using the commercial software CMG(Computer Modeling Group software for advanced recovery process simulation).It is shown that the proposed method is reliable.It can capture the fracture rejection characteristics of tight gas reservoirs better than the CMG.A sensitivity analysis of various control factors(initial water saturation,reservoir parameters,and fracturing parameters)affecting the production in tight gas wells is conducted accordingly.Finally,a series of theoretical arguments are provided for a rational and effective development/exploitation of tight sandstone gas reservoirs.

Analysis of Reservoir Forming Conditions and Prediction of Continuous Tight Gas Reservoirs for the Deep Jurassic in the Eastern Kuqa Depression,Tarim Basin

The exploration targets in the Kuqa Depression at present are mainly structure traps in Cretaceous-Tertiary.Due to the complexity of mountain distribution and reservoir forming conditions, the exploration of Jurassic in the eastern Kuqa Depression has been in a state of semi-stagnation since the discovery of the Yinan-2 gas reservoir.According to the concept and theory of 'continuous petroleum reservoirs' and the re-analysis of the forming conditions of the Yinan-2 gas reservoir and regional natural gas in the eastern Kuqa Depression,it is believed that the deep Jurassic has good natural gas accumulation conditions as well as geological conditions for forming continuous tight gas reservoirs.The boundary of the Yinan-2 gas reservoir is not controlled by a structural spillpoint.The downdip part of the structure is dominated by gas,while the hanging wall of the fault is filled by water and forming obvious inverted gas and water.The gas reservoir has the normal temperature and ultrahigh pressure which formed in the near source or inner-source.All of these characteristics indicate that the Yinan-2 gas reservoir is different from conventional gas reservoirs.The deep Jurassic in the eastern Kuqa Depression has multisets of source-reservoir-cap assemblages,which comprise interbedded sandstones and mudstones.These assemblages are characterized by a self-generation,self-preserving and self-coverage model.Reservoir sandstones and coal measure mudstones are interbedded with each other at a large scale.As the source rocks,Triassic-Jurassic coal measure mudstones distribute continuously at a large scale and can generate and expel hydrocarbon.Source rocks contact intimately with the overlying sandstone reservoirs.During the late stage of hydrocarbon expulsion,natural gas charged continuously and directly into the neighboring reservoirs.Petroleum migrated mainly in a vertical direction over short distances.With ultra-high pressure and strong charging intensity,natural gas accumulated continuously.Reservoirs are dominated by sandstones of braided delta facies.The sand bodies distribute continuously horizontal.With low porosity and low permeability,the reservoirs are featured by strong heterogeneity.It is hypothesized that the sandstones of the interior depression tend to be relatively tight with increasing depth and structure stress weakness.Thus,it is predicted that continuous tight gas reservoirs of ultra-high pressure may exist in the deep formations of the eastern and even the whole Kuqa Depression.So,it is worth evaluating the exploration potential.

Geological characteristics and accumulation mechanisms of the "continuous" tight gas reservoirs of the Xu2 Member in the middle-south transition region,Sichuan Basin,China

＂Continuous＂ tight gas reservoirs are those reservoirs which develop in widespread tight sandstones with a continuous distribution of natural gas. In this paper, we summarize the geological features of the source rocks and ＂＇continuous＂ tight gas reservoirs in the Xujiahe Formation of the middle- south transition region, Sichuan Basin. The source rocks of the Xul Member and reservoir rocks of the Xu2 Member are thick （Xul Member： 40 m, Xu2 Member： 120 m） and are distributed continuously in this study area. The results of drilled wells show that the widespread sandstone reservoirs of the Xu2 Member are charged with natural gas. Therefore, the natural gas reservoirs of the Xu2 Member in the middle-south transition region are ＂continuous＂ tight gas reservoirs. The accumulation of ＂continuous＂ tight gas reservoirs is controlled by an adequate driving force of the pressure differences between source rocks and reservoirs, which is demonstrated by a ＂one-dimensional＂ physical simulation experiment. In this simulation, the natural gas of＂continuous＂ tight gas reservoirs moves tbrward with no preferential petroleum migration pathways （PPMP）, and the natural gas saturation of＂continuous＂ tight gas reservoirs is higher than that of conventional reservoirs.

Blasingame production decline type curves for analysing a multi-fractured horizontal well in tight gas reservoirs

Production decline analysis has been considered as an important method to obtain the flow parameters, reservoir properties and original gas in place. Although advanced Blasingame production decline analysis methods for vertical wells, fractured wells and horizontal wells are widely used, limited study has conducted on Blasingame production decline type curves for multi-fractured horizontal well(MFHW). Based on the perpendicular bisection(PEBI) grids, a numerical model was developed and the solution was obtained using control volume finite element method and the fully implicit method. Blasingame production decline-type curves of the infinitely conductive MFHW were plotted through computer programming. A field case was presented to analyse and verify the model developed. Five flow regimes, including early formation linear flow, early radial flow, compound linear flow, transient flow and pseudo-radial flow, are recognized. Fracture spacing is the main factor that affects early radial flow, compound linear flow and transient flow, the distance from the well to the circular boundary affects the pseudo-radial flow, and the type curves are also significantly affected by the formation permeability, fracture number and fracture half-length. The validation of field case suggests that the Blasingame production decline type curves proposed in this work can be applied to the production decline analysis for MFHW in tight gas reservoirs.

Sedimentology and Ichnology of Upper Montney Formation Tight Gas Reservoir, Northeastern British Columbia, Western Canada Sedimentary Basin

Several decades of conventional oil and gas production in Western Canada Sedimentary Basin (WCSB) have resulted in maturity of the basin, and attention is shifting to alternative hydrocarbon reservoir system, such as tight gas reservoir of the Montney Formation, which consists of siltstone with subordinate interlaminated very fine-grained sandstone. The Montney Formation resource play is one of Canada’s prime unconventional hydrocarbon reservoir, with reserve estimate in British Columbia (Natural Gas reserve = 271 TCF), Liquefied Natural Gas (LNG = 12,647 million barrels), and oil reserve (29 million barrels). Based on sedimentological and ichnological criteria, five lithofacies associations were identified in the study interval: Lithofacies F-1 (organic rich, wavy to parallel laminated, black colored siltstone);Lithofacies F-2 (very fine-grained sandstone interbedded with siltstone);Lithofacies F-3A (bioturbated silty-sandstone attributed to the Skolithos ichnofacies);Lithofacies F-3B (bioturbated siltstone attributed to Cruziana ichnofacies);Lithofacies F-4 (dolomitic, very fine-grained sandstone);and Lithofacies F-5 (massive siltstone). The depositional environments interpreted for the Montney Formation in the study area are lower shoreface through proximal offshore to distal offshore settings. Rock-Eval data (hydrogen Index and Oxygen Index) shows that Montney sediments contains mostly gas prone Type III/IV with subordinate Type II kerogen, TOC ranges from 0.39 - 3.54 wt% with a rare spike of 10.9 wt% TOC along the Montney/Doig boundary. Vitrinite reflectance data and Tmax show that thermal maturity of the Montney Formation is in the realm of “peak gas” generation window. Despite the economic significance of the Montney unconventional “resource-play”, however, the location and predictability of the best reservoir interval remain conjectural in part because the lithologic variability of the optimum reservoir lithologies has not been adequately characterized. This study presents lithofacies and ichnofacies analyses of the Montney Formation coupled with Rock-Eval geochemistry to interpret the sedimentology, ichnology, and reservoir potential of the Montney Formation tight gas reservoir in Fort St. John study area (T86N, R23W and T74N, R13W), northeastern British Columbia, western Canada.

A Study of Solid-Free Drilling Fluid for Tight Gas Reservoirs

This project is explaining a laboratory development of a solid free drilling fluid formula that could be potentially used in tight gas reservoirs. The configuration of the weak gel fluid WGL-1, which is resistant to high temperature and high salt, was tested, and concluded that its gelling properties, salt and temperature resistance, and environmental protection were all in line with industry requirements. The final drilling fluid formula was developed as: water + (0.3% ~ 0.5%) NaOH + 5% KCl + 2% WGL-1 + 5% NaCl + (1.0% ~ 2.0%) HBFR Anti-high temperature fluid loss agent + 2% Polyol + (1.5% ~ 2.0%) SDL-1 Lubricant + 0.4% A4O1. The performance of the liquid was tested for temperature resistance, inhibition, gas formation protection effect, plugging performance, and static settlement stability. It was concluded that the temperature resistance performance is satisfied at 150°C, and the cuttings recovery rate is as high as 96.78%. It has good performance in inhibiting water dispersion and swelling of cuttings. The permeability recovery value reaches 88.9%, which meets the requirements of gas formation protection. The SSSI value shows that its settlement stability is good;under high temperature and high pressure, its sealing performance is good. This drilling fluid system has achieved the expected results and laid a foundation for further promoting the development of solid-free drilling fluid systems. The future development direction of solid-free drilling fluids is pointed out, to the improvement of properties to be applied in high temperature environment and have high salt resistance capacity.

A new model for predicting irreducible water saturation in tight gas reservoirs

The irreducible water saturation(Swir) is a significant parameter for relative permeability prediction and initial hydrocarbon reserves estimation.However,the complex pore structures of the tight rocks and multiple factors of the formation conditions make the parameter difficult to be accurately predicted by the conventional methods in tight gas reservoirs.In this study,a new model was derived to calculate Swir based on the capillary model and the fractal theory.The model incorporated different types of immobile water and considered the stress effect.The dead or stationary water(DSW) was considered in this model,which described the phenomena of water trapped in the dead-end pores due to detour flow and complex pore structures.The water film,stress effect and formation temperature were also considered in the proposed model.The results calculated by the proposed model are in a good agreement with the experimental data.This proves that for tight sandstone gas reservoirs the Swir calculated from the new model is more accurate.The irreducible water saturation calculated from the new model reveals that Swir is controlled by the critical capillary radius,DSW coefficient,effective stress and formation temperature.

Quantitative characterization of tight gas sandstone reservoirs using seismic data via an integrated rock-physics-based framework

Seismic characterizing of tight gas sandstone (TGS) reservoirs is essential for identifying promising gas-bearing regions. However, exploring the petrophysical significance of seismic-inverted elastic properties is challenging due to the complex microstructures in TGSs. Meanwhile, interbedded structures of sandstone and mudstone intensify the difficulty in accurately extracting the crucial tight sandstone properties. An integrated rock-physics-based framework is proposed to estimate the reservoir quality of TGSs from seismic data. TGSs with complex pore structures are modeled using the double-porosity model, providing a practical tool to compute rock physics templates for reservoir parameter estimation. The VP/VS ratio is utilized to predict the cumulative thickness of the TGS reservoirs within the target range via the threshold value evaluated from wireline logs for lithology discrimination. This approach also facilitates better capturing the elastic properties of the TGSs for quantitative seismic interpretation. Total porosity is estimated from P-wave impedance using the correlation obtained based on wireline log analysis. After that, the three-dimensional rock-physics templates integrated with the estimated total porosity are constructed to interpret microfracture porosity and gas saturation from velocity ratio and bulk modulus. The integrated framework can optimally estimate the parameters dominating the reservoir quality. The results of the indicator proposed based on the obtained parameters are in good agreement with the gas productions and can be utilized to predict promising TGS reservoirs. Moreover, the results suggest that considering microfracture porosity allows a more accurate prediction of high-quality reservoirs, further validating the applicability of the proposed method in the studied region.

WELL TESTING ANALYSIS FOR HORIZONTAL WELL WITH CONSIDERATION OF THRESHOLD PRESSURE GRADIENT IN TIGHT GAS RESERVOIRS

A fundamental solution for homogeneous reservoir in infinite space is derived by using the point source function with the consideration of the threshold pressure gradient. The fundamental solution of the continuous point source function is then derived based on the Green function. Various boundary conditions of the reservoirs are considered for this case and the corresponding solutions are obtained through the mirror image reflection and the principle of superimposition. The line source solution is obtained by integration. Subsequently, the horizontal-well bottom hole pressure response function for a non-linear gas flow in the homogeneous gas reservoir is obtained, and the response curve of the dimensionless bottom hole pressure and the derivative for a horizontal well in the homogeneous gas reservoir are obtained. In the end, the sensitivities of the relevant parameters are analyzed, The well test model presented in this paper can be used as the basis of the horizontal well test analysis for tight gas reservoirs.

Dual-porosity model of rate transient analysis for horizontal well in tight gas reservoirs with consideration of threshold pressure gradient

Most researches of the threshold pressure gradient in tight gas reservoirs are experimental and mainly focus on the transient pressure response, without paying much attention to the transient rate decline. This paper establishes a dual-porosity rate transient decline model for the horizontal well with consideration of the threshold pressure gradient, which represents the non-Darcy flow in a fracture system. The solution is obtained by employing the Laplace transform and the orthogonal transform. The bi-logarithmic type curves of the dimensionless production rate and derivative are plotted by the Stehfest numerical inversion method. Seven different flow regimes are identified and the effects of the influence factors such as the threshold pressure gradient, the elastic storativity ratio, and the cross flow coefficient are discussed. The presented research could interpret the production behavior more accurately and effectively for tight gas reservoirs.

Enhancing recovery and sensitivity studies in an unconventional tight gas condensate reservoir

The recovery factor from tight gas reservoirs is typically less than 15%, even with multistage hydrauhc tractunng stimulation. Such low recovery is exacerbated in tight gas condensate reservoirs, where the depletion of gas leaves the valuable condensate behind. In this paper, three enhanced gas recovery （EGR） methods including produced gas injection, CO2 injection and water injection are investigated to increase the well productivity for a tight gas condensate reservoir in the Montney Formation, Canada. The production performance of the three EGR methods is compared and their economic feasibility is evaluated. Sensitivity analysis of the key factors such as primary production duration, bottom-hole pressures, and fracture conductivity is conducted and their effects on the well production performance are analyzed. Results show that, compared with the simple depletion method, both the cumulative gas and condensate production increase with fluids injected. Produced gas injection leads to both a higher gas and condensate production compared with those of the CO2 injection, while waterflooding suffers from injection difficulty and the corresponding low sweep efficiency. Meanwhile, the injection cost is lower for the produced gas injection due to the on-site available gas source and minimal transport costs, gaining more economic benefits than the other EGR methods.

Types and genesis of sweet spots in the tight sandstone gas reservoirs:Insights from the Xujiahe Formation,northern Sichuan Basin,China

Through comprehensively applying geological and geophysical data,as well as core and thin section observation,the characteristics of reservoirs and fractures in the second member of the Xujiahe Formation(hereinafter referred to as Xu2 Member)in the Yuanba area,northern Sichuan Basin,were studied.Combined with the analysis of the main controlling factors of production capacity,the types and characteristics of the sweet spots in the tight sandstone gas reservoir were determined.The evaluation standards and geological models of the sweet spots were established.The results are as follows:(1)There are bedding-parallel fracture-,fault-induced fracture-,and pore-dominated sweet spots in the tight sandstone gas reservoirs of the Xu2 Member.(2)The bedding parallel fracture-dominated sweet spots have developed in quartz sandstones with well-developed horizontal fractures and micro-fractures.They are characterized by high permeability and high gas output during production tests.This kind of sweet spots is thin and shows a limited distribution.Their logging responses show extremely low gamma-ray(GR)values and medium-high AC values.Moreover,the bedding parallel fracture-dominated sweet spots can be mapped using seismic methods.(3)The fault-induced fracture-dominated sweet spots have welldeveloped medium-and high-angle shear fractures.Their logging responses show an increase in peaks of AC values and total hydrocarbon content and a decrease in resistivity.Seismically,the areas with welldeveloped fault-induced fracture-dominated sweet spots can be effectively mapped using the properties such as seismic entropy and maximum likelihood.(4)The pore-dominated sweet spots are developed in medium-grained feldspathic litharenites with good reservoir properties.They are thick and widely distributed.(5)These three types of sweet spots are mainly determined by sedimentation,diagenesis,and tectonism.The bedding parallel fracture-dominated sweet spots are distributed in beachbar quartz sandstones on the top of the 1st sand layer group in the Xu2 Member,which develops in a shore-shallow lake environment.The fault-induced fracture-dominated sweet spots mainly occur near faults.They are increasingly developed in areas closer to faults.The pore-dominated sweet spots are primarily distributed in the 2nd and 3rd sand layer groups,which lie in the development areas of distributary channels near provenances at western Yuanba area.Based on the geological and seismic data,a comprehensive evaluation standard for these three types of sweet spots of the tight sandstone reservoirs in the Xu2 Member has been established,which,on the one hand,lays the foundation for the development and evaluation of the gas reservoir,and on the other hand,deepens the understanding of sweet spot in the tight sandstone gas reservoirs.

Evaluation of Well Spacing for Primary Development of Fractured Horizontal Wells in Tight Sandstone Gas Reservoirs

Methods for horizontal well spacing calculation in tight gas reservoirs are still adversely affected by the complexity of related control factors,such as strong reservoir heterogeneity and seepage mechanisms.In this study,the stress sensitivity and threshold pressure gradient of various types of reservoirs are quantitatively evaluated through reservoir seepage experiments.On the basis of these experiments,a numerical simulation model(based on the special seepage mechanism)and an inverse dynamic reserve algorithm(with different equivalent drainage areas)were developed.The well spacing ranges of Classes I,II,and III wells in the Q gas field are determined to be 802–1,000,600–662,and 285–400 m,respectively,with their average ranges as 901,631,and 342.5 m,respectively.By considering both the pairs of parallel well groups and series well groups as examples,the reliability of the calculation results is verified.It is shown that the combination of the two models can reduce errors and provide accurate results.

Tight gas production model considering TPG as a function of pore pressure,permeability and water saturation

Threshold pressure gradient has great importance in efficient tight gas field development as well as for research and laboratory experiments.This experimental study is carried out to investigate the threshold pressure gradient in detail.Experiments are carried out with and without back pressure so that the effect of pore pressure on threshold pressure gradient may be observed.The trend of increasing or decreasing the threshold pressure gradient is totally opposite in the cases of considering and not considering the pore pressure.The results demonstrate that the pore pressure of tight gas reservoirs has great influence on threshold pressure gradient.The effects of other parameters like permeability and water saturation,in the presence of pore pressure,on threshold pressure gradient are also examined which show that the threshold pressure gradient increases with either a decrease in permeability or an increase in water saturation.Two new correlations of threshold pressure gradient on the basis of pore pressure and permeability,and pore pressure and water saturation,are also introduced.Based on these equations,new models for tight gas production are proposed.The gas slip correction factor is also considered during derivation of this proposed tight gas production models.Inflow performance relationship curves based on these proposed models show that production rates and absolute open flow potential are always be overestimated while ignoring the threshold pressure gradients.

Gas-Water Production of a Continental Tight-Sandstone Gas Reservoir under Different Fracturing Conditions

A numerical model of hydraulic fracture propagation is introduced for a representative reservoir(Yuanba continental tight sandstone gas reservoir in Northeast Sichuan).Different parameters are considered,i.e.,the interlayer stress difference,the fracturing discharge rate and the fracturing fluid viscosity.The results show that these factors affect the gas and water production by influencing the fracture size.The interlayer stress difference can effectively control the fracture height.The greater the stress difference,the smaller the dimensionless reconstruction volume of the reservoir,while the flowback rate and gas production are lower.A large displacement fracturing construction increases the fracture-forming efficiency and expands the fracture size.The larger the displacement of fracturing construction,the larger the dimensionless reconstruction volume of the reservoir,and the higher the fracture-forming efficiency of fracturing fluid,the flowback rate,and the gas production.Low viscosity fracturing fluid is suitable for long fractures,while high viscosity fracturing fluid is suitable for wide fractures.With an increase in the fracturing fluid viscosity,the dimensionless reconstruction volume and flowback rate of the reservoir display a non-monotonic behavior,however,their changes are relatively small.

Predicting gas-bearing distribution using DNN based on multi-component seismic data: Quality evaluation using structural and fracture factors

The tight-fractured gas reservoir of the Upper Triassic Xujiahe Formation in the Western Sichuan Depression has low porosity and permeability. This study presents a DNN-based method for identifying gas-bearing strata in tight sandstone. First, multi-component composite seismic attributes are obtained.The strong nonlinear relationships between multi-component composite attributes and gas-bearing reservoirs can be constrained through a DNN. Therefore, we identify and predict the gas-bearing strata using a DNN. Then, sample data are fed into the DNN for training and testing. After optimized network parameters are determined by the performance curves and empirical formulas, the best deep learning gas-bearing prediction model is determined. The composite seismic attributes can then be fed into the model to extrapolate the hydrocarbon-bearing characteristics from known drilling areas to the entire region for predicting the gas reservoir distribution. Finally, we assess the proposed method in terms of the structure and fracture characteristics and predict favorable exploration areas for identifying gas reservoirs.

Feasibility study on application of volume acid fracturing technology to tight gas carbonate reservoir development

How to effectively develop tight-gas carbonate reservoir and achieve high recovery is always a problem for the oil and gas industry.To solve this problem,domestic petroleum engineers use the combination of the successful experiences of North American shale gas pools development by stimulated reservoir volume(SRV)fracturing with the research achievements of Chinese tight gas development by acid fracturing to propose volume acid fracturing technology for fractured tightgas carbonate reservoir,which has achieved a good stimulation effect in the pilot tests.To determine what reservoir conditions are suitable to carry out volume acid fracturing,this paper firstly introduces volume acid fracturing technology by giving the stimulation mechanism and technical ideas,and initially analyzes the feasibility by the comparison of reservoir characteristics of shale gas with tight-gas carbonate.Then,this paper analyzes the validity and limitation of the volume acid fracturing technology via the analyses of control conditions for volume acid fracturing in reservoir fracturing performance,natural fracture,horizontal principal stress difference,orientation of insitu stress and natural fracture,and gives the solution for the limitation.The study results show that the volume acid fracturing process can be used to greatly improve the flow environment of tight-gas carbonate reservoir and increase production;the incremental or stimulation response is closely related with reservoir fracturing performance,the degree of development of natural fracture,the small intersection angle between hydraulic fracture and natural fracture,the large horizontal principal stress difference is easy to form a narrow fracture zone,and it is disadvantageous to create fracture network,but the degradable fiber diversion technology may largely weaken the disadvantage.The practices indicate that the application of volume acid fracturing process to the tight-gas carbonate reservoir development is feasible in the Ordovician Majiagou Formation of lower Paleozoic,which is of great significance and practical value for domestic tight-gas carbonate reservoir development and studies in the future.

The Newly Discovered Yanchang Gas Field in the Ordos Basin, Central China

The Yanchang gas field is located in the Ordos Basin of central China to the southeast of the Yishan Slope, covers an exploration area of 2.6× 10~4 km^2 and has approximately 3.5× 10^（11） m^3 of gas reserves. The gas field is dominated by lithologic gas reservoirs but also has a few structural gas reservoirs. Sand bodies were deposited in the Carboniferous Benxi Formation around offshore barrier islands and in distributary channel fillings in the delta front of the P_1s_2 and P_1s_1 divisions of the Permian Shanxi Formation. The P_2h_8 division of the Shihezi Formation contains the main reservoirs. The depths of the reservoirs are between 1 970 and 3 500 m. The Yanchang gas field can be classified as a typical tight sandstone gas reservoir filed because its porosity is lower than 10% and permeability lower than 1 mD. The discovery and development of the Yanchang gas field has led to a great increase in total natural gas reserves in the Ordos Basin. Its exploration has improved methods of locating large gas fields in deep-water depositional environments in the south part of the basin.