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AAPG Distinguished Lecture Program:Lecture Slide Library

2001-02 Tour

Salmon Bloch

Consultant
Houston, Texas

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Anomalously High Porosity and Permeability in Deeply-Buried Sandstone Reservoirs

Increasing exploration for deeper targets requires adequate predrill assessment of reservoir quality in deeply buried sandstones. Numerous deep (> 4km, or approximately 13,000ft of effective burial depth) sandstone reservoirs are characterized by “anomalously-high” porosity and permeability (j&k). In such sandstones the overall porosity distribution is bimodal. The primary mode comprises the “non-anomalous” sub-population whereas the secondary mode reflects the presence of the “anomalous” sub-population. On a porosity histogram the secondary mode exceeds the maximum value of the primary mode.

There are four major causes of anomalously high porosity and permeability: (1) grain coats and grain rims on detrital quartz grains, (2) “early” emplacement of hydrocarbons, (3) “early” development of overpressure, and (4) secondary porosity.

Evaluation of the potential for occurrence of anomalous porosity due to authigenic grain coats and detrital rims is heavily dependent on empirical data. The three-dimensional distribution pattern of the coats and rims is a function of their origin. Although the occurrence of anomalously high porosity and permeability is clearly associated with intervals consisting of coated or rimmed quartz grains, the correlation is highly complex

Retardation, or even cessation, of pore cementation in sandstones by emplacement of hydrocarbons is seemingly a logical consequence of the very low relative permeability of water in hydrocarbon-saturated sandstones. However, some cements (e.g., quartz, illite) may continue to precipitate following emplacement of hydrocarbons into the reservoir. Nevertheless, in many reservoirs there is compelling evidence for preservation of porosity due to “early” hydrocarbon filling. For example, available data from a well on the northwestern shelf of Australia suggest not only that emplacement of hydrocarbons into a highly quartzose reservoir can preserve porosity but also that the extent of porosity preservation in quartzose reservoirs can be quantified prior to drilling.

At identical depths, sands overpressured due to the disequilibrium compaction process commonly have higher j&k than their hydrostatically-pressured lithologic equivalents. Preservation of j&k is heavily dependent on the timing (depth range) of fluid overpressure development. In overpressured Plio-Pleistocene sands porosity and permeability are generally equal to the j&k of hydrostatically-pressured sands at shallower depths that are subjected to the same effective stress. Porosity and permeability preservation in older sandstones varies as a function of overpressure history.

The ubiquity of secondary porosity in sandstones is unquestionable but its impact on reservoir quality is not. The presence of secondary porosity does not significantly affect the accuracy of empirical predictions in many sandstones for two reasons: (1) the extent of secondary porosity preservation is controlled by the same geological parameters as that of primary porosity, and (2) on a reservoir scale its impact on total porosity is limited because of re-precipitation of the dissolution products.

This presentation is based in large part on work done at Arco’s Exploration and Production Research Center in collaboration with John Duncan, Steve Franks, Ken Helmold and Joe McGowen, and at Norsk Hydro’s Research Center in collaboration with Tom Dryer and John Gjelberg.