An Overview of Hydraulic Fracturing Stimulation Practices of a Joint Cooperation Shale Gas Project in Sichuan Basin
Authors: Gao Yi , Pickles Mike , Yuan Roger , Liu Deng Feng , Qu Qingguang , Ji Peng , Zhou Ming , Ouyang Yong , Zhang Zhiyi , Wu Lin , Lin Dai Hong , Alan Rolph 
Published: May 2016

Abstract
Shell China Exploration and Production Company and its affiliates are operating in the pioneering Joint Cooperation Project (JCP) in the Sichuan Basin that targets unlocking the Lower Silurian Longmaxi shale gas play. Since 2010, both verticals and horizontals have been drilled and completed with various hydraulic fracturing technologies implemented. Supported by extensive data gathering and analysis, the hydraulic fracturing stimulation practices have significantly evolved to improve the quality and repeatability of completion results. This paper reviews the development of hydraulic fracturing stimulation practices in Longmaxi shale gas play in the studied area.
Unlike most of the North American shale gas plays, the Longmaxi shale gas play is characterized by high formation pressures, close-to-overburden in-situ minimum stresses, low horizontal stress anisotropy, and regionally active tectonics, the combination of which presents unique challenges to hydraulic fracturing stimulation. The combination of these geologic, geomechanical and petrophysical characteristics result in high treating pressure, difficulty in proppant placement, constrained fracture height and complex fracture geometry. However, successful fracturing executions have been achieved by applying technologies including, but not limited to, limited entry perforation design and hybrid fluid systems, advanced monitoring including microseismic and Diagnostic Fracture Injection Test (DFIT) technique, etc. The completion parameters such as lateral length, stage spacing, number of clusters per stage, perforation shots per cluster, fluid type, fluid/proppant volume, treating rate, proppant selection have all been optimized as part of the learning curve.
Key fracture design parameters such as the preferred treating rate, customized fluid design and pumping schedule for the play are discussed. This paper also demonstrates the learning of the fit-for-purpose hydraulic fracturing stimulation design from the perspective of successful and repeatable delivery of the fracture treatment.

Introduction
The lower Silurian Longmaxi black shale, characterized by organic-rich calcareous-siliceous shale with higher brittleness as well as abundant natural fractures distribution, is the main target for this joint cooperation project. High quartz and TOC content in conjunction with favorable porosity and permeability makes the lower section of Longmaxi shale the prime interval of interest.
Comparing to shale gas play in North America, the TVD of Joint Cooperation Project (JCP) wells range from 3050m to 4500m; the pore pressure gradient is greater than 0.9 psi/ft, which is also higher than most of its counterparts in North America. However, the other geological and petrophysical parameters like formation thickness, Young's modulus and Poisson ratio are comparable.
Due to the low anisotropy of Shmax and Shmin (Yuan et al. 2013), the Longmaxi shale demonstrates diverse present-day horizontal stress direction across the block, reflecting the observed structural complexity. The in-situ stress, namely Shmin, overburden stress and Shmax are nearly isotropic resulting in mixed stress regimes. In some areas the Shmin can be close to or even higher than the overburden stress, which is confirmed by the closure gradients from DFIT. This may cause the fracture geometry to be "bed parallel" or "pancake" like. Meanwhile, complex fracture geometry (SRV type), rather than typical "bi-wing", are diagnosed by microseismic monitoring. The total fracture height as diagnosed by non-radioactive tracers (NRT) and temperature logging in a vertical well indicated the hydraulically created fracture covering about only one thirds of total target thickness.