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Liquid and hydrate blockages often occur in natural gas pipelines, reducing pipeline transportation efficiency. When blockages completely occupy the pipeline, major production and safety accidents can occur, such as production shutdowns and overpressure damage. This study comprehensively describes in detail the technical principles and characteristics of 12 natural gas pipeline blockage detection methods and lists the challenges they face in practical applications. Moreover, common techniques for eliminating blockages in gas pipelines are presented. Then, whether the different detection techniques can realize the five functions of blockage quantity, blockage location, blockage length, blockage area, and continuous detection is theoretically discussed. Furthermore, the advantages, disadvantages, and limitations of different detection techniques are evaluated from six aspects: detection speed, accuracy, adaptability, anti-interference, impact on pipeline operation, need for historical information, and cost. Transient wave reflection and inverse transient analysis methods deserve more studies in this field. Finally, recommendations for future work are presented based on five aspects: morphology and number of blockages, acquisition of initial pipeline parameters, remote detection, signal processing, and blockage media. This study serves as a useful tool for gaining insights into recent advances in natural gas pipeline blockage detection methods. • The basic principle and research status of blockage detection technology are introduced. • The performance of different blockage detection techniques is discussed. • The detection speed, accuracy and applicability of different methods are compared. • The challenges and future work in this research field are discussed. [ABSTRACT FROM AUTHOR]

The liquid-phase pipeline is the optimal choice for large-amount and long-distance ethane transportation. Selecting the optimal diameter is necessary for the economical design of the pipeline. However, the special critical temperature 32.2 °C and critical pressure 4.87 MPa of ethane makes it easy to become liquid-vapor phase change, which is not considered in the traditional natural gas or crude oil pipeline design. In this paper, a new mathematical model is built to calculate the optimal diameter of the ethane pipe by using the 'pump station + pipeline' unit as the research object. The model selects the lowest total pipeline construction and operation costs as the objective function, and the constraints include the ethane liquid-vapor phase change, the pipe maximum allowable stress, and pipe specifications. In particular, the liquid-vapor phase change constraint is added to the traditional model to avoid the ethane liquid-vapor phase change, which is obtained by quantitatively analyzing the variation of physical parameters of ethane close to the pressure-temperature phase boundary. The optimization model is solved by use of the genetic algorithm. Finally, optimal pipe diameters are calculated for the conditions of transmission capacity from 1000 t/d to 10,000 t/d. Comparisons of calculated pipe diameter with eight actual cases show that the results are feasible with the average and maximum deviations being less than 5% and 8%, respectively. The effects of pipe materials and electricity prices on the pipe diameter are analyzed. It is demonstrated that the pipe material has a negligible effect on the optimal diameter, whereas increasing the electricity price will lead to the increase of the optimal diameter in the case of large transmission volumes. • An optimal diameter model for the liquid-phase ethane pipeline is built. • The liquid-vapor phase change constraint ensures ethane pipeline safety. • The fitness function of the genetic algorithm is improved. • The optimal diameter is obtained and successfully applied to eight real cases. [ABSTRACT FROM AUTHOR]

• A new algorithm is proposed to calculate methane recovery factors through a hydrate P–T multiphase flash method. • A new hydrate phase fraction and composition estimation method is developed to guarantee a stable solution. • The algorithm is validated by experimental data at various conditions. • Variations of CH 4 recovery factors with injected CO 2 concentrations are revealed. Injecting CO 2 into the hydrate reservoirs to replace CH 4 is an effective method for the natural gas hydrate (NGH) exploitation and CO 2 sequestration. The accurate prediction of the CH 4 recovery factor under different pressures, temperatures, and CO 2 injection amounts are essential for the design of the CO 2 replacement process. However, conventional multiphase flash algorithms are not stable for CO 2 -containing hydrate system calculations because of inappropriate initial estimations on the hydrate phase fraction and composition. This paper proposed a new multiphase flash algorithm by developing a new initialization method for the hydrate phase fraction and composition as well as the solution procedure. A total of 61 sets of experimental data at pressures from 8 MPa and 16 MPa are applied to validate the new method. Results demonstrate that the new method successes in all the 61 cases, while the software PVTsim and CSMGem do not converge for 16 and 20 cases, respectively. Also, the average relative deviation between the calculated phase compositions and experimental values is less than 18 %, which represents a comparable accuracy to the above two software. Moreover, case studies are designed to research the variations of the CH 4 recovery factor with the injected CO 2 concentration in the hydrate reservoir. The most economical injected CO 2 concentrations are discussed at specified reservoir conditions. [ABSTRACT FROM AUTHOR]