R. H. Worden

Location of an oil-water contact is crucial for estimating reserves and for designing production strategies. Identifying hydrodynamic barriers or baffles is also important for optimizing both recovery and flow rates. In some oil fields, identifying fluid contacts and barriers is not always possible using conventional wireline and formation testing methods. We have used a novel technique, fluid inclusion stratigraphy (FIS), to tackle these problems in the Upper Jurassic Magnus oil field in the North Sea. This technique involves systematic cleaning and crushing of small quantities of a large number of drill-cuttings or core samples followed by mass spectrometry without prior GC (gas chromatography) separation. The quantity and specific types of petroleum fluid trapped in pores in mineral grains are determined and the stratigraphic and spatial pattern of organic compounds constructed. For this case study, these data were integrated with quantitative mineralogical data derived from gamma-ray, density, sonic, and neutron porosity logs, together with electrical resistivity. The conventional resistivity data resulted in ambiguity concerning the oil-water transition zone in both wells; interpreting the resistivity logs was locally hampered by vertical changes in reservoir lithology. The FIS data suggested more complex transition zones (locally variable water saturations in the transition zone controlled by shales and dolomites) and petroleum extending deeper than suggested by the resistivity log (possibly due to lack of sensitivity of the latter to low petroleum saturations in water-wet reservoirs). The FIS data also suggested the presence of potential stratigraphic (shale) and diagenetic (dolomite) barriers or baffles to fluid flow within the reservoir, illustrated by changes in abundance and composition of petroleum-bearing inclusions.

Ductile, clay-rich sand grains control porosity and permeability in the fluvio-deltaic Oligocene and lower Miocene sandstones of the South China Sea. Ductile grains account for between approximately 5 and 50% of the original sand grain population. There is a pronounced loss of porosity with increasing burial depth in the basin. At depths of less than 3000 m this is due solely to ductile grain compaction where the rate of porosity loss with depth increases with increasing ductile grain content. At depths greater than 3000 m, the steep porosity loss with depth is due to combined ductile grain compaction and quartz cementation. The amount of quartz cement increases with increasing burial depth; however, cleaner sandstones tend to have greater amounts of quartz cement at any given depth below 3000 m. This leads to convergence of porosity evolution for the clean and ductile-rich sandstones below 3000 m. There is a rapid loss of permeability with decreasing porosity because compaction of ductile grains smears them between rigid quartzose grains leading to blocked pore throats. A consequence of this process is that the lowest permeabilities are found in sandstones with the highest ductile grain contents. Quartz cement does not have a clear and discernible control on permeability. The pronounced loss of porosity with increasing depth and permeability with decreasing porosity leads to low permeability at relatively shallow burial depths. Reservoir quality is thus controlled by the nature of the primary sand and depth of burial. The sediment supply system led to systematic changes in ductile grain content across the basin with ductile content increasing into the more distal part of the sediment system. The consequence is that depth of economic basement (in terms of porosity or permeability) can be predicted as a function of ductile grain content and burial depth for prospects across the basin.