Recently Imperial Oil Limited has been pursuing gas plays in North-Eastern British Columbia where single wells have the potential to recover gas in the 30-300 Bcf range. The tie-in costs for these wells are very high due to acid gas content, mountainous terrain and long distances to tie-in points. A reliable prediction of the recoverable reserves helps determine if a tie-in is economic and manage the business over the long-term. The intent is to demonstrate how the long-term recovery from naturally fractured gas wells can be accurately evaluated with buildup tests and a conventional finite difference reservoir simulator.

The decision to tie in a well is strongly based upon its initial deliverability. However, this is not generally appropriate since the initial deliverability and the longterm recovery are controlled by different factors. The initial deliverability is a function of the fracture system around the wellbore while the long-term recovery is related to the fracture system's extent and the ability of the reservoir matrix to recharge the fracture system. Other evaluation techniques such as open hole logs and core can only evaluate the fracture system at the wellbore which again only relates to the initial deliverability. Properly planned and executed production tests, in conjunction with reservoir simulation, can provide accurate evaluations of long-term recovery potential. However, the current suite of dual permeability/porosity simulators are either too simplistic to be of any use or very complex and difficult to use. Considerable lime and money could be saved if a conventional finite difference reservoir simulator could be used.

Two example wells will first be presented to demonstrate how a conventional reservoir simulator can be used to model the long-term production from a naturally fractured reservoir. It will then be demonstrated how a properly conducted flow and buildup test used in conjunction with a conventional simulator can be used to predict the longterm deliverability.

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