Analogs

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In resource estimation, analogs are used (particularly in exploration and early development stages), where direct measurement information is limited. When using the analog methodology, remember that it's based on the assumption that the analogous reservoir is comparable to the subject reservoir with respect to reservoir and fluid properties, which control the ultimate recovery of petroleum. By selecting analogs that are appropriate for your needs, a similar production profile may be forecast (when performance data is based on comparable development plans such as well type, well spacing and stimulation).

Note that an analogous reservoir is defined by features such as approximate depth, temperature, reservoir drive mechanism, pressure, original fluid content, reservoir size, gross thickness, pay thickness, reservoir fluid gravity, net-to-gross ratio, lithology, heterogeneity, porosity, permeability, and its development plan. The formation of analogous reservoirs is based on similar processes with respect to sedimentation, pressure, diagenesis, temperature, chemical and mechanical history, and structural deformation.

Comparing several analogs can improve the estimates for recoverable quantities from the subject reservoir. Also, comparing reservoirs in the same geographic area with the same approximate age usually provides improved analogs. However, proximity alone may not be your primary consideration. In all cases, it's important to document analog and subject reservoir / project similarities and differences. For quality assurance, it's best to review analog reservoir performance at all stages of development.