So far, the factors affecting the development performance difference in horizontal wells, Daniudi gasfield, Ordos Basin, have not been made clear yet. Therefore, some data on reservoir types, sedimentary microfacies, production performance were analyzed comprehensively. Then, the time to reach the pseudo-steady state flow in a horizontal well and its main influential factors were studied by means of two methods, including unsteady-state flow analysis and numerical simulation. Finally, the chart to evaluate the time was established for different gas reservoirs. Results show that (1) in Daniudi gasfield, there are three kinds of reservoirs developed in the horizontal-well development area, from bottom to top including barrier island of Upper Carboniferous Taiyuan Formation, distributary channel of Lower Permian Shanxi Formation, and braided river of Lower Permian Lower Shihezi Formation; (2) as a whole the horizontal wells present the three-stage production performance, including stable production stage, fast decline stage, and long low-yield slow-decline stage with low pressure. For the horizontal wells in various gas reservoirs, their development performance is quite different, for example, the best production effect with high initial yield and stable production capacity for the horizontal wells in gas reservoirs of Taiyuan 2 Member whereas similar performance, not very good production effect, short stable production period, fast initial decline, and high liquid/gas ratio for those in gas reservoirs of both Shihezi 1 and Shanxi 2 members; (3) for these horizontal wells, their time to reach the pseudo-steady state averages 19 months, and the cumulative production for the corresponding wells averages 1235×104 m3; and (4) sensitivity analysis indicates that the poorer the permeability, the greater the gas layer thickness, the lower the water saturation, the higher the porosity, and the longer time it takes to reach the pseudo-steady state flow. In conclusion, the main factors influencing on this time are reservoir permeability and water saturation.

In order to increase not only the recovery factor of tight sandstone gas reservoirs but also the development effects, some gas reservoirs of Shiehezi 1 Member, Da 28 well block, Daniudi gasfield, Ordos Basin, were taken as objectives to analyze why their recovery factor was low. And several causes were figured out, including that isolated effective reservoirs with small size and complex superimposition, and unclear recognization on their distribution laws may bring about a lower drilling rate in gas layers and a lower efficiency in fracturing stimulation; and under insufficient control, there is interwell unproduced and vertically unconnected remaining gas in dispersed reservoirs resulting in the low recovery factor. So, reservoir configuration was studied to provide geological support for describing the remaining gas and formulating the later adjustment scheme. Based on the reservoir configuration, differential fracturing stimulation was carried out to maximize a reserve producing degree and guide an efficient adjustment for gas reservoirs. Results show that, (1) in view that some effective sweet spots are thin, scattered, and poor, a configuration method with “vertical staging, curve positioning, and lateral delineating” as the core is developed. As a result, fine description of beach bar width is realized and the drilling rate is increased from 54 % to 72 %; and (2) after applying both staged fracturing with dissoluble bridge plug and the differential stimulation measure based on the superimposition characteristics of effective sandbodies, the average single-well production rate is increased by 50 %. In conclusion, the efficient adjustment technology based on reservoir configuration developed for tight sandstone gas reservoirs may support the efficient adjustment in Da 28 well block and lay the foundation for the efficient adjustment and continuously stable production in Daniudi gasfield.

In order to sufficiently recognize an effect of smart foam drainage in cluster gas wells on drainage gas recovery in liquid-loading gas wells and provide theoretical and practical guidance data for formulating a strategy of drainage gas recovery in Yanbei project, the change trend of production parameters in some gas wells with smart foam drainage (e.g. tubing/casing pressure, temperature, and production rate) was analyzed by taking cluster gas wells with gradual liquid loading of Yanbei project as objectives. Then, it was economically compared with conventional manual injection. Results show that (1) during the smart foam drainage in cluster gas wells, the equipment is of convenient installation, and debugging and stable operation. Combined with digitalized gasfield of Yanbei project, the smart foam drainage can provide remote control and management (agent injection system adjustment, safety and efficiency), save manpower and material resource, realize all-weather injection of foam drainage agent at multiple wellheads of one cluster well by using only one pump, and completely meet the injection need of the foam drainage gas recovery in water-producing gas wells; (2) after its application, the gas-producing rate maintains stable and rises significantly, the casing pressure keeps stable and declines slowly, the tubing/casing pressure difference decreases continuously, and the average tubing/casing pressure difference is 1.4 MPa lower than that of manual injection, the temperature is also relatively stable, the drainage effect is remarkable, and the liquid loading is solved fundamentally; and (3) its comprehensive economic performance is good. Compared with manual injection, the expenditure is decreased by 22.4 %, the gas increment of cluster well pad is 13.6×103 m3/d, and the daily production is increased by 24.8 %. In conclusion, the smart foam drainage in cluster wells is not only remarkable in drainage gas recovery and significant in economic benefit, but also worth spreading.

In the Lower Paleozoic sour gas wells, Daniudi gasfield, Ordos Basin, not only formation water has the characteristics of high salinity and rich Ca2+ and Mg2+ contents, but also natural gas contains a little H2S and CO2. Due to a slower water-producing rate, these gas wells are plugged to further affect productivity release. So, in order to effectively alleviate the plugging and remove the generated blockage, these Lower Paleozoic sour gas wells were taken as objectives to analyze their gas compositions, formation-water quality, and blockage compositions. Then, the blockage origin was made clear to guide some study on scale removing and inhibiting agent. Based on this, a new formula was prepared for the agent and its properties were evaluated. Results show that (1) in these sour gas wells corroded seriously, the formation water has high concentration of scaling ions, which may provide crystallization nucleus and material base for generating the blockage, resulting in serious scale plugging; (2) the newly prepared agent has better performance, which can dissolve more than 95 % blockage within 12 h while less corrosion to wellbore; and (3) for the scale removing and inhibiting agent, when its formula has the mass concentration of 50 mg/L, the inhibiting rate to various inorganic scales is over 80 %. In conclusion, this formula can slow down the scaling rate and remove the generated scale blockage, so as to improve production efficiency, which is of guiding significance to the development of similar gasfields.

In order to further understand the relationship between venting time of gas pipeline and operation control methods, Jingbian-Xi'an natural-gas pipeline was taken as an objective to study the venting operation control and venting-time calculation method by means of both numerical simulation of critical flow and transient simulation of TGNET Pipeline Studio 3.0. In addition, the simulation was compared with actual venting operation for verification. Results show that (1) the venting time is in close relationship with the opening of relief valve and it can be estimated by means of the numerical simulation model of critical flow, but the simulated result is usually less than the actual venting time. The reasonable transient model constructed by using TGNET Pipeline Studio 3.0 can calculate the venting time more accurately; (2) the control method of "slow firstly and then fast", which maintains the relative opening of the relief value within 20 % in the first half period of venting, can better meet the actual need; and (3) for some constructing pipelines, the venting is related to their intrinsic physical parameters, such as length, diameter, and pressure. However in the meantime, it is also influenced by the surrounding environment and the relief-valve operators' expertise. In conclusion, to calculate the venting time and to study the operation control methods are of practical significance. Moreover, it is necessary to summarize practical experience and further optimize the model by introducing environment impact factor, personnel impact factor, and comprehensive impact factor by means of big data, so as to guide some actual production.

During microscopic displacement, serious viscous fingering is likely to happen. So, the unsteady two-phase seepage mechanisms and the pressure propagation in porous media were figured out via both dynamic network simulation algorithm and unsteady seepage theory. After the reliability of the simulation was verified, several fluid-seepage and pressure-propagation laws in the process of unsteady two-phase seepage were analyzed, and the influences of fluid injection rate, adverse viscosity ratio, pressure propagation, and permeability gradient on the viscous fingering were clarified. Furthermore, some measures to inhibit viscous fingering were made so as to improve microscopic displacement efficiency. Results show that in the process of pore-scale seepage, the pressure propagation in pore fluid may affect the balance between viscous force and capillary force of fluid in a pressure sweep region, and then the migration of two-phase fluid contact. Therefore, introducing the pressure propagation in the pore-scale seepage model is an important premise to describe this migration accurately. In addition, the measures include that (1) at one direction toward permeability-gradient decrease, with a gradual decrease of pressure-propagation speed, some injected fluid can advance uniformly in the pressure sweep region, so as to improve the fluid sweep efficiency; and (2) at another direction toward a decrease of pore-throat radius, keeping a lower injection rate and injecting displacement medium can stabilize the displacement front, so as to improve the microscopic displacement efficiency.