Huangingba shale gas field is located at south edge of Sichuan basin. It has more complex structures, in-situ stresses and natural fracture corridors than its adjacent areas. Tested wells show huge variations of testing results. To identity production controlling factors is essential for optimizing productive drilling and completion in order to boost well productivities further. This paper presents a case study of Huangjingba shale gas field.
Firstly, production data was analyzed to identify which parameter can be the best indicator of the current well productivities across the field. Secondly, data mining was conducted to correlate this indicator with reservoir quality, completion quality, and drilling and hydraulic fracturing operation parameters. The focus is on those factors that can be managed through drilling and completion optimization. Finally, after the most influential parameters were identified, rigorous simulations using a representative fine model were performed to reproduce observations and investigate their interactions and sensitivities on production. The model was refined from a three-dimensional (3D) field model, which integrates geology, natural fractures, reservoir and geomechanics together. It was calibrated by history matching of pumping history of hydraulic fracturing, microseismic data, and production history.
Total gas content normalized to pore pressure and porosity can be a single-best factor for sweet-spot identification. Data analysis reveals the best interval for lateral placement. Simulations reproduce this observation and investigate what means can be taken to reduce negative impacts if one stage was outside the best interval. Proppant volume has the strongest correlation with production indicator for this high-stress field although other parameters of hydraulic fracturing are also analyzed. Results of production logging support this correlation. In order to increase effectively placed proppant volume, parametric study of hydraulic fracturing through simulation were completed. Field experiences and measurements suggest that natural fracture corridors can result in early screen-out, constrained stimulation volume, and duplicated stages. Unconventional fracturing modeling was utilized to investigate the optimal design and operational parameters of hydraulic fracturing.
Our study suggests some key observations agree with the industrial best practices gathered from North America high-pressure shale plays. Yet abundant natural fracture corridors with complex patterns and distributions, formed through multiple tectonics in geological history, may present a unique feature of our field. It is also fundamentally different because of high in-situ stresses with extreme variations of heterogeneities and anisotropies. They require special cares on optimizing hydraulic fracturing in order to develop local best practice. Recent wells with newly proposed completion methodology achieve improved productivities.