Abstract: Silica Cements and Sequence Boundaries: The Same Story from Pores to Basins

Max L. Coleman, Andrew G. Robinson

Diagenetic effects in sandstones are a major problem in prediction of reservoir quality. Application of sedimentary geochemical techniques to quantify diagenetic processes give time and temperature of pore-filling cementation. One surprise of such studies is the scale and duration of cementation: basin-wide and very rapid. Fluid inclusion thermometry, stable-isotope geothermometry and potassium-argon dating (of associated illite), integrated with thermal history models, give time and temperature of cementation in reservoir sandstones. Samples from different facies and depths show similar times of cementation across a whole oil-field (e.g. Magnus field, North Sea), a sedimentary basin, and even a province (e.g. Southern North Sea).

Two findings disturb our accepted notions of cementation processes. Firstly, the pattern of increasing cement volume (in the same facies) from crest to flank in the oil-zone of some reservoirs suggests simultaneous silica cementation and oil emplacement: presence of oil precludes cementation. Secondly, quantifying the change of silica content between deposition and deep burial of sandstones showed diagenetic addition of 15% material. Rapid cement precipitation requires silica transport by large volumes of pore-fluid and cannot be modelled satisfactorily using conventional wisdom of relevant parameters. Previous understanding of either deep flow-rates, permeability or silica solubility is faulty.

We suggest a plausible scenario to produce higher flow-rates, where hydrologic head is enhanced by emergence; represented by major sequence boundaries. Thus, sequence boundaries, indicated by hardground surfaces at the palaeo-surface, may be represented by contemporaneous, widespread cementation at depth.

AAPG Search and Discovery Article #90986©1994 AAPG Annual Convention, Denver, Colorado, June 12-15, 1994