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The potential of a sandstone to serve as a reservoir for producible hydrocarbons is closely related to its diagenetic history, which, in turn, is dependent upon its composition. Convergent plate-margin basins, which formed on the flanks of contemporaneous or precursor andesitic volcanic arcs, received large volumes of detritus reworked from either the arc of its tectonically uplifted plutonic roots. Arc-derived sands of the Bristol, Gulf of Alaska, Queen Charlotte, and Grays Harbor-Chehalis basins (northeast Pacific) are mineralogicaUy similar suites dominated by plagioclase, and by volcanic rock fragments. Diagenesis of these mineralogically immature sands at shallow to moderately deep burial (15,000 feet or 5,000 m) produced a systematic sequence of authigenic cements that include (1) localized, early calcite pore fill; (2) clay rims; (3) laumontite or phyllosilicate pore fill; and (4) late calcite pore fill/replacement and siliceous overgrowths. Each diagenetic stage reduced reservoir porosity and permeability and, correspondingly, increased bulk density and interval velocity of sand sections. Well-developed clay rims in fine-grained sand reduced maximum permeability to a few tens of millidarcys; samples containing stage 3 laumontite or phyllosilicate typically have less than 10 millidarcys permeability.

Authigenesis of stage 2 and 3 cements is, in part, temperature controlled. Reservoir properties thus degenerate systematically with increasing depth of burial and increasing degree of heating, and they may produce a diagenetically controlled economic basement well within the range of normal drilling. Generation of oil is also temperature controlled, and the optimum thermal window lies mainly within sediments characterized by stage 3 diagenesis and consequent poor reservoir quality. Prediction of a diagenetic economic basement is necessary for realistic early assessment and systematic exploration of convergent arc-related plate-margin basins.

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