Autonomous inflow control device (AICD) completion has been applied in many conventional oil and gas reservoirs and has effectively controlled the water invasion. However, the method for designing and optimizing of AICD in sour gas reservoirs is still lacking. The objective of the proposed paper is to establish a numerical simulation and optimization method to evaluate and optimize the performance of AICD completion in water-bearing sour gas reservoirs. Firstly, a sulfur deposition saturation model is established considering non-darcy flow and stress sensitivity in sour gas reservoirs, meanwhile, time-varying skin factor is introduced to represent the influence of sulfur deposition on permeability. Secondly, a new type of AICD is designed, which has large flow channels and vortex chamber to satisfy the need of restraining water invasion and sulfur plugging in sour gas reservoirs. Finally, a reservoir-wellbore simulation method is established, which considers the sulfur deposition in the reservoir and the new AICDs in the wellbore, then the key parameters of AICD is optimized by orthogonal test and range analysis. The results of the numerical simulation show that the simulation and optimization method can effectively optimized the key parameters of AICD and the optimized AICD completion has good water invasion restriction capacity in water-bearing sour gas reservoirs. The optimized AICD completion causes little additional pressure drop compared to perforation completion in sour gas reservoirs, and the maximum additional pressure drop is less than 0.67 MPa, which means the optimized AICD completion is able to control water invasion as well as maintain normal gas production of sour gas wells. Besides, the optimized AICD completion decreases both the daily water production and the cumulative water production compared to perforation completion in sour gas reservoirs. In the last stage of the tenth year prediction period, the cumulative water production with AICD completion decreases by about 22.7% compared to that with perforation completion. In conclusion, the simulation and optimization method can be used for guiding the rational application of AICD completion in water-bearing sour gas reservoirs.

Shape memory sand control screen completion based on shape memory polymer not only has the advantages of simple process and easy to run in hole, like independent screen, but also can achieve the sand management effect of gravel filling. Therefore, shape memory sand control screen has wide application prospects. However, since the shape memory material is temperature-sensitive, a large number of laboratory experiments are needed to evaluate its expansion, seepage and sand retaining capabilities, as well as optimize the polymer system and screen structure. A performance evaluation experiment system for full-size shape memory screen prototype was developed. The device can describe the parameters of the shape memory screen during the expansion process and after expansion in real time and quantitatively, such as permeability, outer diameter and residual stress. The expansion behavior of screen prototype is controlled by step heating the passing through fluid to simulate the screen run in hole operation. 60 sets of experiments were carried out using the device. The expansion performance, seepage performance and sand control performance of shape memory screens were evaluated. Shape memory polymer formulation and screen structure are also optimized. The research shows that the optimized shape memory sand control screen densely filled annulus and effectively supports the wellbore after expansion. The permeability of the expanded screen can be up to 35µm2, the displacement pressure difference can be less than 1kPa, and the sand control precision can be up to 0.061mm. Therefore, shape memory sand control screen can be used for sand control completion of oil and gas wells with limited well site conditions such as long horizontal wells, complex wells and offshore wells. This paper presents an experiment device to evaluate the performance of shape memory screen, the dynamic expansion behavior is described during the expansion process and after expansion in real time and quantitatively.

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Current critical flow rate models fail to accurately predict the liquid loading statuses of shale gas horizontal wells. Therefore, a new critical flow rate model for the whole wellbore of shale gas horizontal wells is established. The results of the new model are compared to those of current models through the field case analysis. The new model is based on the dynamic analysis and energy analysis of the deformed liquid-droplet, which takes into account the liquid flow rate, the liquid-droplet deformation and the energy loss caused by the change of buildup rate. The major axis of the maximum stable deformed liquid-droplet is determined based on the energy balance relation. Meanwhile, the suitable drag coefficient equation and surface tension equation applied to shale gas horizontal wells are chosen. Finally, the critical flow rate equation is established and the maximum critical flow rate of the whole wellbore is chosen as the criterion for liquid loading prediction. The precision of liquid loading prediction of the new model is compared to those of the four current models, including Belfroid's model, modified Li's model, liquid film model and modified Wang's model. Field parameters of 29 shale gas horizontal wells are used for the comparison, including parameters of 18 unloaded wells, 2 near loaded-up wells and 9 loaded-up wells. Field case analysis shows that the total precision of liquid loading prediction of the new model is 93.1%, which is higher compared to those of the current four models. The new model can accurately predict the liquid loading statuses of loaded-up wells and near loaded-up wells, while the prediction precision for unloaded wells is high enough for the field application, which is 88.9%. The new model can be used to effectively estimate the field liquid loading statuses of shale gas horizontal wells and choose drainage gas recovery technologies, which considers both the complex wellbore structure and the variation of flowback liquid flow rate in shale gas horizontal wells. The results of the new model fill the gap in existing studies and have a guiding significance for liquid loading prediction in shale gas horizontal wells.