A reservoir characterization technique is presented which can significantly lower the risk involved in developing naturally fractured gas reservoirs. It is shown that depletion ratios can be used to delineate the limits of a field, highlight the prolific trends often associated with naturally fractured reservoirs, and provide a simple, yet accurate, means of assigning reserves to undrilled locations.
A field case history is described and the results of a successful twenty well drilling program are presented. Pre-drill reserve estimates for the entire program were within seven percent of the actual post-drill reserve estimates from production decline analysis.
In the current economic environment facing the oil and gas industry, reducing the cost of finding hydrocarbons is at the top of every operators priority list. One of the ways to lower finding costs on a field wide basis priority list. One of the ways to lower finding costs on a field wide basis is to lower the risk involved in drilling infill and extension locations. Less money spent drilling dry holes and marginal wells results in more reserves added for each dollar spent.
In the following discussions, a synergistic, multi-discipline approach is presented in which a reservoir is first described geologically. Next, the presented in which a reservoir is first described geologically. Next, the resulting pore systems are characterized with respect to productivity and fluid flow. Finally, an engineering technique is developed to exploit and delineate the more prolific trends within the field. The depletion ratio, defined as cumulative gas volume produced per net change in average reservoir pressure, is proposed as a characterization parameter for use in naturally fractured or fracture enhanced dual porosity reservoir systems. In such reservoirs, formation evaluation through electric log analysis is often unreliable. Thus, conventional net pay and porosity-thickness mapping techniques cannot be used to evaluate development drilling locations.
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