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Understanding Hydraulic Fracturing and Tight Gas Sands
The role of unconventional reservoirs in maintaining security of gas supplies has been the subject of much attention recently, but these resources have very different requirements from conventional reservoirs, and present a range of technical challenges. Researchers at Colorado School of Mines have been working to increase understanding of fracture treatment in fluvial tight gas sands with a project that is due to be completed next month. The work was supported by five operating companies following submission of a proposal to ITF.
Fluvial tight gas sands are one of a number of reservoir types categorised as “unconventional" They have ultra low in situ permeabilities, and require hydraulic fracture stimulation for their production, but the pattern of hydraulic fracture growth is complex and varies in different geological settings. Ultra-low permeabilities combined with complex hydraulic fracture growth, means that in tight gas sands many more wells are required to drain a given reservoir section than in conventional sands. For example, whereas in a conventional sand reservoir, well-spacing is generally 65-130 hectares per well, in a tight gas sand, (onshore) well-spacing can be as little as four hectares per well, thus requiring an additional 16-32 wellbores. Developing this many onshore wells can be cost prohibitive and environmentally invasive; in an offshore setting, the problems are even greater.
The Colorado School of Mines project is focused on improving the understanding of 3D hydraulic fracture growth in tight gas sands to facilitate development in both onshore and offshore settings. It combines data from an outcrop in Northwest Colorado, which is representative of fluvial architecture, with hydraulic fracture modelling.
Dr Jennifer Miskimins, who is leading the project explains further “From a mechanical aspect, fracture growth in unconventional reservoirs can be extremely complex, and beyond our current capabilities to completely predict. The main outcome of this project will be to determine how different tight gas fluvial depositional environment systems, such as crevasse splays, channels, and point bars affect hydraulic fracture growth in three-dimensions. Such an understanding will lead to improvements in hydraulic fracture treatment designs and, subsequently, improved reserve recoveries. Onshore developments will benefit from this knowledge due to a better understanding of the necessary well-spacing to recover associated reserves. However, offshore developments will profit at an even greater level since down-spacing in such environments can be cost-prohibitive and any improvement in the understanding of three-dimensional drainage patterns will aid overall reservoir management."
The research group spent 18 months in the Rocky Mountains where fluvial based geology (old river systems) is common. The first phase of the project used data from these outcrop studies to build a detailed 3D (GOCAD) model which gives an improved insight into how hydraulic fractures develop in vertically and laterally constrained wells. The researchers then secured funding for a second phase of work, currently ongoing, which aims to incorporate the GOCAD model and hydraulic fracture growth parameters into full 3D reservoir simulation, and determine dynamic flow conditions and optimum reserve recovery practices based on this model.
Colin Sanderson, Senior Technology Analyst at ITF said “Tight gas sands represent a significant resource but development can be economically marginal. This important research will result in better understanding of hydraulic fracture growth a key factor in reservoir management that could ultimately improve reserve recoveries. Furthermore, the progression of this project through to reservoir simulation should enable its practical benefits to be realised."
ITF is turning its attention to unconventional oil reservoirs during 2011. A technology challenge workshop on the topic was held in Houston in April, and a call for proposals will be issued this month.
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