In order to make clear the engineering factors influencing on the production rate in shale gas wells during depletion production and solve such problems that these influencing factors after fracturing are not understood completely, especially considerable ambiguity about primary and secondary influencing factors, typical TY shale gas reservoirs were taken as objectives. A kind of solution software was developed on the basis of one multi-dimensional, multi-scale mathematic percolation model. Furthermore, both primary and secondary relationships among these factors, including fracture height, horizontal-well length, fracture length, number of fracturing clusters, and stage spacing were analyzed. It is indicated that an increasing amplitude of cumulative production rate in shale gas wells is quite different under these distinct influencing factors, for example, 138% for fracture height, 109% for horizontal-well length, 103% for fracture length, 17% for number of fracturing clusters, -8% for stage spacing, individually. It is concluded that (1) the primary influencing factor should be fracture height induced by fracturing, and the secondary ones include horizontal-well length, fracture length, number of fracturing cluster, and stage spacing; (2) both stable production time and cumulative production rate increase with the increase of fracture height, horizontal-well length, fracture length, and number of fracturing cluster, along with the decrease of stage spacing; and (3) for typical TY shale gas reservoirs in TY1H well, the optimized parameters for a rational development should be fracturing clusters of 3 , stage spacing of 80 m, fracture height of 35 m, fracture length of 120 m, and horizontal-well length of 1750 m.

For all shale gas fields, new wells are needed constantly, and the pressure of both wellhead and surface pipeline network is characterized by continuous variation. So, it is necessary to determine the pressurization timing of shale gas wells quickly and accurately. Taking N201 wellblock in Changning shale gas field as an objective, this study determined the target gas well and the pressurization time node, based on a comprehensive calculation and analysis on reservoir and surface engineering, by means of one method of reservoir-surface integration analysis. Firstly, the initial wellhead pressure in this wellblock was classified. Many pressure prediction curves were selected for four well types according to pressure-decline velocity. The well pressure in the fast decline period was fitted on the basis of lateral translation of power index model to calibrate one pressure prediction model. Then, the node pressure of surface pipeline network was predicted via modeling of surface gathering pipeline network. Finally, the pressurization timing which needed pressurizing was determined by comparing the predicted wellhead pressure and the node pressure of pipeline network. Results show that (1) additional shale gas wells are drilled constantly, and the pressure of both wellhead and surface pipeline network changes continuously. Therefore, in order to determine the pressurization timing, it is necessary to analyze reservoir engineering and surface gathering engineering comprehensively; (2) one model to predict the pressure of shale gas wells and another model of shale-gas surface gathering pipeline network are established. Pressurization target and time node can be determined by comparing calculation results from these two models; and (3) the calculation results exhibit that for most gas wells in Changning block, it takes about 10-14 months for the wellhead pressure decline to 0.5-1 MPa higher than the transportation pressure, meaning that the pressurization of one shale gas well shall be taken into consideration after about one-year production.

In order to reduce fracturing cost, this study analyzed the feasibility of two-proppant combination of both quartz sand and ceramsite, optimized its type and proportion, and carried out some evaluation on its application to low-permeability tight reservoirs, Daniudi gasfield. Results show that, (1) the two-proppant combination of 30/50-mesh quartz sand and 20/40-mesh ceramsite can meet the demand on flow capacity of fracturing in this gasfield; (2) compared with another sanding method of quartz sand firstly and then ceramsite, the sanding method of two-proppant combination has stronger flow capacity; (3) at the sanding concentration of 5 kg/m2, the flow capacity cannot satisfy the requirement when the quartz sand/ceramsite ratio is higher than 4:6, so the ratios of 3:7 and 4:6 are selected to perform an early test; (4) the two-proppant combination of quartz sand and ceramsite has been applied to 14 gas wells, which realizes the cumulative cost saving of 4.8437 million yuan; (5) its application shows that single-well gas production doesn't change when the proportion of quartz sand is increased from 30% to 40%; and (6) compared with the production rate in other gas wells with similar petrophysical property and fracturing scale, this combination cannot decrease gas production in the early stage or in the longer term. In conclusion, the two-proppant combination of quartz sand and ceramsite can reduce fracturing cost greatly. And it is worth popularizing and applying to Daniudi gasfield and also provides technical reference for domestic similar low-permeability tight reservoirs.

In order to optimize long-cementing tieback cementing used for Shunbei block of Tarim Basin and solve some cementing difficulties of low displacement efficiency and poor seal integrity, one wildcat of S7 well in Shunbei block, was taken as an objective to analyze the effects of centering degree of long casing, displacement rate, and flushing fluid volume on the displacement efficiency. Results show that (1) at a constant displacement efficiency, the casing centering degree is in a positive correlation with the displacement efficiency of slurry and in a negative one with the slurry blending degree in wellbore. This efficiency in hole section with high centering degree increases faster while that with low degree increases more slowly. It cannot be increased greatly unless this degree is kept over 60%; (2) at a constant centering degree, the displacement efficiency is obviously positively correlated with the displacement efficiency of slurry and negatively with the slurry blending degree in wellbore. This efficiency cannot be increased greatly unless the displacement rate is over 2.0 m³/min; and (3) at constant centering degree and displacement efficiency, the flushing fluid volume is also obviously positively correlated with the displacement efficiency of slurry and negatively with the slurry blending degree in wellbore. The displacement efficiency in the upper wellbore cannot be increased greatly unless the flushing fluid volume is kept over 30 m³.