This paper presents a process for analyzing production interference and interwell hydraulic fracturing pressure hits for multi-well horizontal pads in unconventional reservoirs. Ten wells with varied spacing in separate formations are evaluated. The analysis determines the degree of connectivity between the wells to help assess the extent and complexity of the stimulated network. Many of these connections persist through flowback and early production. The results of the study impact decisions regarding well spacing, injection rate, perforation design and frac order.A prescriptive completions program enabled observation of pressure interactions between wells during multi-stage hydraulic fracturing. Wellhead pressures are continuously recorded during all completions and flowback operations. The rate of pressure buildup plus the magnitude and frequency of the inter-well hits are studied. Pressure hits are then compared with production interactions between wells. Connections are mapped to form a comprehensive image of the fracture network.In the pad studied, all wells had multiple hits with varying degrees of communication across the fracture network. Observations confirm that fractures had significant vertical and lateral growth establishing a highly complex network. Interference analysis indicates the connections between wells often diminish over time. As a final validation, the high degree of interaction and fracture overlap are shown to be consistent with high-resolution microseismic observations.Establishing the extent of the effective fracture network is fundamental to deciding design variables. Multi-variable pad designs and production results can only be deciphered when viewed in conjunction with fracture interactions. The process discussed provides a simple way to observe and understand these interactions.

Recent success of commercial shale gas developments in a number of basins throughout North America can be attributed to the application of advanced technologies used to drill horizontal wellbores, stimulate the shale reservoir, and optimize productivity of shale-bearing formations. Many of the drilling and completion techniques learned from the thousands of wells drilled and stimulated in more mature shale basins, such as the Barnett, have been applied to newer shale discoveries such as the Marcellus and Haynesville in the United States, and both the Montney and the remarkable Horn River Basin in Canada. The unique properties of each shale, however, preclude a "cookie-cutter" development approach from being applied. Each play must be optimized as a unique reservoir.In order to utilize numerical simulation as a tool in optimizing well design, one needs to develop a model that appropriately represents the complex process of gas flow from the native reservoir to the hydraulic fractures and subsequently to the wellbore. This is challenging due to poor understanding of variables such as pressure dependent permeability variation, fluid cleanup, relative permeability effects, non-Darcy flow, methane desorption in a nano-Darcy shale matrix, and fracture conductivity variations from the dominant hydraulic fractures to the secondary induced and natural fractures. Another challenge is accurate representation of the hydraulic fracture. Is the fracture planar or complex? What is the fracture geometry? What is the fracture intensity within the stimulated volume? What is effectively propped? What is the proppant distribution within the fracture system? How does this tie to effective conductivity and does it vary with distance from the wellbore (three dimensionally)?Finding a unique match to historical production is very challenging. Shale gas operators collect a large amount of data including cores and logs (specialized for nano-Darcy rock), micro seismic, diagnostic fracture injection testing (DFIT), fluid and proppant tracers and more. This data is used to better characterize the reservoir and the natural and hydraulic fractures and can help to constrain model inputs.This paper discusses a workflow used in developing a numerical shale gas model for Nexen's Horn River shale gas reservoir. Presented is a practical and systematic approach to using surveillance data; specifically microseismic data in construction of the stimulated reservoir volume (SRV) and the network of hydraulic fractures in the model. Discussions will also focus on accurately modeling complexities such as non-Darcy flow in the hydraulic fractures, pressure-permeability dependencies, variations in hydraulic fracture conductivity and fluid cleanup. The objective is to gain understanding and insight into the uncertainties that have the greatest impact on well performance.

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