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Evaluation
of Oil Bearing Fractured Reservoirs (Type I) Using Data
Acquired While Drilling
B. Douglas Bearinger
Nexen Petroleum International Ltd,
Calgary, AB
Fractured reservoirs that lack matrix porosity are very difficult to
evaluate with conventional petrophysical analysis. They are more readily
characterized by the hydrocarbons released during the drilling process. The
quantity of hydrocarbon released is mostly indicative of the amount of storage
(porosity) but is also influenced by the interconnectivity and conductivity of
the fracture network. Quantification of the movement of fluids between the
wellbore and the surrounding fractured reservoir provides an indication of the
production potential of wells.
Gaslogging provides a continuous record of hydrocarbons released from the
reservoir into the circulating drill fluid. Gas component ratios can be used to
characterize the hydrocarbon type and the reservoir quality. Oil stain and
fluorescence observed in drill cuttings provide further indications of
hydrocarbon saturation and reservoir quality.
Continuously recorded fluid loss/gain information allows accurate location of conductive fractures. A loss index (LI) can be calculated to estimate the productivity or injectivity of a well.
Image logs provide rock fabric information and help characterize the fracture network. Fracture intensities and apertures can also be used to calculate fracture porosity and estimate well productivity.
Conventional openhole log suites can be used to interpret
lithology/compositional changes, lithologic contacts, and to evaluate brecciated
fault zones and diagenetically altered zones where matrix porosity can be
developed.
Examples from a fractured granitic Basement reservoir located in Yemen
and being developed by Nexen International will be used to illustrate data and
techniques that can be used to evaluate a type I fractured reservoir
.
AAPG Search and Discovery Article #90039©2005 AAPG Calgary, Alberta, June 16-19, 2005