An Integrated Modelling Workflow to Optimise Initial Production Rate and Well Spacing for Longmaxi Shale Gas Play

Yong, Rui (PetroChina Southwest Oil and Gas Company) | Zhuang, Xiangqi (Schlumberger) | Wu, Jianfa (PetroChina Southwest Oil and Gas Company) | Wen, Heng (Schlumberger) | Shi, Xuewen (PetroChina Southwest Oil and Gas Company)

OnePetro 

Abstract

Ning201 Longmaxi shale gas play is located on the southwest edge of Sichuan Basin. Block Ning201 surface is very mountainous and elevation range of drilling pads is between 400 meters and 1300 meters. The target layer of shale gas exploration and development is mainly the Wufeng Formation of the Ordovician system and the organic-rich shale interval of the Lower Longxixi Formation of the Silurian system. The total thickness is between 30m and 50m, and the overall buried depth is 2300~3200m. Field development of Ning201 shale gas play was geared up in 2014. During early appraisal phase before 2014, average testing results of wells were 10~15×104 m3/d. 7 vertical appraisal wells and 50 horizontal wells have been drilled and 38 horizontal wells among them have been put into production to evaluate optimized development strategy until middle of 2017. Changning area accomplished the construction of 15×108 m3/a production capacity. During production appraisal phase, different well spacing pads were configured, and some cross-well interference testing were performed to determine optimal spacing in Ning201 block. Only qualitatively understanding can be achieved with spontaneous field efforts and quantitative evaluation of long-term impacts on production with varying initial rate control and well spacing is still missing.

In this paper, an integrated modeling workflow was introduced to accurately simulate the production behavior of a representative shale gas well and to control production through a calibration model to optimize well spacing and maximize economic returns. The workflow begins with microseismic monitoring during shale gas well fracturing operations. Considering the fracturing pumping procedure, fluid and proppant volume and subsurface features, including formation, natural fractures and in-situ stresses, the heterogeneity of the hydraulic fracturing system propagation ensures that the simulated complex hydraulic fracturing network is in line with reality. After establishing a detailed hydraulic fracturing model, production performance is matched to history to better calibrate the conductivity of hydraulic fracture network in dynamic model as a relaible predicting tool.