The boom in the development of shale gas reservoirs is being fueled by continued improvements in completion and stimulation technologies for horizontal wells. Horizontal wells are playing a key role in improving gas recovery and production economics in unconventional gas reservoirs, and fracture stimulation is the key to success. However, fracture growth and reservoir characteristics are much more complicated in many unconventional reservoirs and there may still be significant improvements possible in stimulation design and completion strategies (Maxwell et al 2002, Warpinski et al 2005). This paper investigates the relationship between well performance and fracture complexity, fracture conductivity, and completion strategies.
The key to success when developing many unconventional gas reservoirs is to generate very complex fracture networks that contact a large reservoir volume (Mayerhofer et al 2006, 2008). However, the network must have sufficient conductivity to efficiently drain the gas (Warpinski et al 2008). Understanding the relationship between fracture network size, fracture spacing, proppant distribution and fracture conductivity is critical to stimulation and completion design. Previous work has shown that un-propped fracture conductivity may be a primary factor that controls well productivity in unconventional gas reservoirs, as there is a likelihood that much of the fracture network is un-propped due to an inability to transport proppant from the primary or main fracture into the complex network or due to insufficient proppant volumes to effective prop the network (Cipolla et al 2008). This previous work has also shown that the conductivity of the primary or main fracture can significantly impact vertical well performance. This paper presents a reservoir simulation study to evaluate the impact of fracture complexity (i.e., fracture spacing), proppant distribution, propped and un-propped fracture conductivity and staging on horizontal well performance. This study examines a realistic range of un-propped fracture conductivity based on previous work that suggests un-propped fracture conductivity of 1-10 md-ft is possible if fractures have some shear offset, but conductivity could be less than 0.1 md-ft if the fractures are aligned (Fredd et al 2001).
The results of the reservoir simulation study provide insights into un-propped network fracture conductivity requirements and the impact of primary fracture spacing (i.e., staging and perforating strategies) and conductivity on horizontal well performance. The results suggest that achieving adequate primary fracture conductivity (~50 to 200 md-ft) can significantly increase gas recovery and initial production rates, while minimizing the impact of un-propped network fracture conductivity and primary fracture spacing (i.e., distance between perforations). In all cases, horizontal well performance is improved when network fracture spacing is smaller (more complex network with larger surface area), and the impact of matrix permeability is reduced when network fracture spacing is small (~50 ft). The paper includes production histories for Barnett shale completions that illustrate the production profiles for horizontal wells in unconventional gas reservoirs, providing evidence that suggests that primary fracture conductivity may be low and significant increases in gas production may be possible by increasing primary fracture conductivity.
Author(s): C.L. Cipolla and E. P. Lolon; Stratagen Engineering, M.J. Mayerhofer and N.R. Warpinski; Pinnacle Technologies
Paper Number: SPE 121528