| Abstract |
Oil field reservoir formations are sampled for porosity and permeability on the tacit assumption that small scale well-log and well-core data are representative of the formation flow properties at arbitrary distances from the wellbore. In formal terms, this statistical assumption is valid only if the formation properties are adequately characterised by a mean and standard deviation, or, equivalently, if variations in formation properties are spatially uncorrelated on all scale lengths. This statistical validity condition is, however, violated by crustal rock; well-log and well-core data are spatially correlated over a wide range of scale lengths. It is, therefore, formally wrong to assume that small scale sample means and standard deviations adequately represent large-scale variation of aquifer reservoir/formation properties. As a practical matter, the formal failure of oil field well-log and well-core sampling to adequately estimate large-scale formation flow property variation is buffered by (i) the high energy density of hydrocarbons, (ii) lack of need for large drainage flow rates, (iii) ability to drill infill wells if de facto well drainage volumes are too small, and (iv) ability of time-lapse seismic imaging to detect fluid substitution volumes to determine large-scale formation flow structures that are not inferred from small-scale formation sampling strategies. As an equally practical matter, however, the above caveats do not apply to producing hot aquifer fluids: (i) geothermal energy density is far smaller than hydrocarbon energy content; (ii) high flow rates are essential to geothermal power production; (iii) infill wells are at high risk to not intersect large drainage volumes unless guided by reliable auxiliary information; (iv) time-lapse hot aquifer imaging has no fluid-substitution signal. An alternative strategy to aquifer production well-siting based on small-scale wellbore sampling of the aquifer focuses on measuring large-scale aquifer fracture-structures. Experience with magnetotelluric (MT) detection of in situ fracture volumes in geothermal fields suggests that MT surveys can form the basis for physically accurate sampling of large-scale aquifer fracture/flow structure. |