The natural gas reserves and gas recovery rate of tight gas sandstone reservoirs in the Sulige gas field in the Ordos Basin play a crucial role in China’s natural gas industry. This study aims to enhance the stable production time of the gas field by summarizing the geological characteristics of the tight gas sandstone reservoirs in the Sulige gas field, discussing the challenges in the development of the gas field, and providing recommendations for the development of the reservoirs. The results show that the matrix reservoir properties, effective sand body size, and gas-bearing properties of tight sandstone gas reservoirs in the Sulige gas field exhibit strong heterogeneity characteristics, and the western and northern parts of the basin edge are gas-water mixed storage areas. There are obvious differences in gas well production, cumulative production, production decline rate, and single well dynamic control reserves in different regions. The recovery of gas reservoirs is primarily influenced by reservoir quality and development well pattern. Increasing the well density increases from 1.5/km² to 4/km² in the gas field enrichment area, can raise the corresponding recovery rate from 26.0% to about 50% under the existing economic and technical conditions. Therefore, ensuring a stable production of the tight gas sandstone reservoirs in this gas field is challenging. To achieve a long-term stable production of the gas field, it is necessary to promote the refined reservoir description technology and improve the production through various measures such as replenishing fractures in wells with depleted fractures, sidetracking horizontal wells, and re-fracturing, thereby improving the reserve utilization degree. Moreover, implementing the negative pressure gas recovery technology as soon as possible can restore the production capacity of near-depletion wells.

The western Sulige gas field is a new and key reserve area for the rolling development of the Sulige gas field in China. However, due to the complex gas–water relationship and the difficulty in identifying gas and water formation, the scale and benefit deployment of the gas field are seriously restricted. In particular, almost all of the wells in the area produce water, and no water measurements have been carried out for any single well, which leads to an unclear understanding of the dynamic characteristics of the production wells, thus affecting the productivity calculations of the gas wells and the overall regional productivity evaluation. Based on the testing data for a gas well, the impacts of the reservoir property parameters on the gas and water production were analyzed by combining the production performance and static geological characteristics. It was determined that the physical parameters K, Kh, and φS_g had good positive correlations with gas production but not with water production; thus, effective prediction cannot be obtained for water production in gas well testing. After the analysis of the liquid-loading law, the gas wells were classified into three types: continuous liquid-carrying production, slight liquid-loading, and liquid-loading wells. In general, up to 96% of the gas wells were liquid-loaded. According to the different production performances exhibited in the different stages of the gas wells, five types of methods for diagnosing water production wells were proposed (gas testing, pilot production, gas–liquid two-phase measurement testing, liquid level detection, and production performance analysis), as well as the diagnostic criteria and corresponding solutions. To obtain real-time water production data for each well and investigate the change in the water–gas ratio (WGR) during the whole production process, a water production splitting method for gas wells based on three-dimensional geological modeling and numerical simulation combined with the constraints of the total water production of gas gathering stations was explored and established. The splitting results can be used to evaluate the water and gas productivity of gas wells and determine the best deliquification period. The gas well productivity when water production was considered was about 10% lower than that when water production was not considered. The best deliquification period was determined to be 125 days for wells with small water production, 20 days for wells with moderate water production, and 3 days for wells with serious water production. The results of this study could provide technical support for the scientific evaluation of gas well production indicators, reduction in development costs, and improvement in oil recovery.

The Dina 2 gas field in the Kuqa Depression of the Tarim Basin is one of China’s most critical oil and gas exploration areas. Natural fractures have played an important role in the low-permeability reservoirs in the Tarim area. Tectonic fractures are dominant in such reservoirs. In fact, the factors influencing tectonic fracture development have always been the source of important issues in tight reservoirs. Cores, thin sections, and borehole image logs were used to analyze the types, basic characteristics, and factors influencing tectonic fractures in the tight sandstone reservoirs of the Dina 2 gas field in the Tarim Basin. The results showed that the tectonic fractures are dominated by high-angle and upright shearing fractures, and they mainly show ENE–WSW strikes. The thin sections suggest that 60% of the fractures are fully filled with minerals, 20% are unfilled, and 20% are partially filled. The analysis also shows that lithology, faults, and in situ stress are the main factors controlling the development of the tectonic structures. Furthermore, the correlation between the unimpeded flow from a single well and the apertures of the tectonic fractures indicates that tectonic fractures play an important role in the production of hydrocarbons.

During the development of multi-layer tight sandstone gas reservoirs in Ordos Basin, China, it has not been easy to calculate accurately the production of each individual layer in gas wells. However, production allocation provides a vital basis for evaluating dynamic reserves and drainage areas of gas wells and remaining gas distributions of gas layers. To improve the accuracy and reliability of production allocation of gas wells, a new model was constructed based on the seepage equation, material balance equation, and pipe string pressure equation. In particular, this new model introduced the seepage equation with an elliptical boundary to accurately capture the fluid flow characteristics within a lenticular tight gas reservoir. The new model can accurately calculate the production and reservoir pressure of each individual layer in gas wells. In addition, the new model was validated and applied in the Sulige gas field, Ordos Basin. The following conclusions were drawn: First, The gas production contribution rates of pay zones based on the new model are fairly close to the measurements of the production profile logging, with errors less than 10%. Second, The overall drainage area of a gas well lies among those of each pay zone, and the total dynamic reserves of the well are close to the sum of the dynamic reserves of pay zones. Third, Higher permeability may lead to higher initial gas production of the pay zone, but the ultimate gas production contributions of pay zones are affected jointly by permeability and dynamic reserves. Finally, The new model has been successfully applied to the SZ block of the Sulige gas field, in which the fine evaluation of dynamic reserves, drainage areas, gas production, recovery factors, and remaining gas distributions of different layers was delivered, and the application results provide technical support for the future well placement and enhanced gas recovery of the block.

The injection of carbon dioxide (${\mathrm{CO}}_2$) into gas reservoirs has become an important way to enhance gas recovery and reduce ${\mathrm{CO}}_2$ emissions. Large discrepancies are observed when predicting natural gas compressibility factors with high ${\mathrm{CO}}_2$ content by several well-known empirical correlations. An explicit correlation is proposed to improve the prediction accuracy in the estimation of compressibility factors on condensate gases with variable ${\mathrm{CO}}_2$ contents. The analysis of the results is carried out on the basis of 202 experimental data from 9 various mixtures of natural gases. The results show that relative deviations of compressibility factors predicted by conventional empirical correlations increase with the increase in ${\mathrm{CO}}_2$ mole fraction with an average error of 8%. The average error of the new method is less than 4%. The effect of compressibility factors on the estimations of dynamic reserves is studied and the compressibility factor causes a 3% reduction in dynamic reserves estimation. The proposed correlation has fewer uncertainties and more accurate results than other correlations that involve the iterative process in calculating compressibility factors of natural gases with variable ${\mathrm{CO}}_2$ contents.

The western Sulige gas field is a new and key reserve area for the rolling development of the Sulige gas field in China. However, due to the complex gas–water relationship and the difficulty in identifying gas and water formation, the scale and benefit deployment of the gas field are seriously restricted. In particular, almost all of the wells in the area produce water and no water measurement has been carried out for any single well, which leads to an unclear understanding of the dynamic characteristics of the production wells, thus affecting the productivity calculations of the gas wells and the overall regional productivity evaluation. Based on the testing data for a gas well, the impacts of the reservoir property parameters on the gas and water production were analyzed by combining the production performance and static geological characteristics. It was determined that the physical parameters K, Kh, and φSg had good positive correlations with gas production but not with water production; thus, effective prediction cannot be obtained for water production in gas well testing. After the analysis of the liquid loading law, the gas wells were classified into three types: continuous liquid carrying production, slight liquid loading, and liquid loading wells. In general, up to 96% of the gas wells were liquid loaded. According to the different production performances exhibited in the different stages of the gas wells, five types of methods for diagnosing water production wells were proposed (gas testing, pilot production, gas–liquid two-phase measurement testing, liquid level detection, and production performance analysis), as well as the diagnostic criteria and corresponding solutions. To obtain real-time water production data for each well and investigate the change of water-gas ratio (WGR) during the whole production process, a water production splitting method for gas wells based on three-dimensional geological modeling and numerical simulation combined with the constraints of the total water production of gas gathering stations was explored and established. The splitting results can be used to evaluate the water and gas productivity of gas wells and determine the best deliquification period. The gas well productivity when water production was considered was about 10% lower than that when water production was not considered. The best deliquification period was determined to be 125 days for wells with small water production, 20 days for wells with moderate water production, and 3 days for wells with serious water production. The results of this study could provide technical support for the scientific evaluation of gas well production indicators, reduction of development costs, and improvement of oil recovery.