Tight-sandstone zones

Secondary porosity contributes more than half (6.7%) to the total porosity (average.of 11%, excluding tight-sandstone zones) of the Catalina Sandstone. Of the available drill cores from wells 0-35 and K-18, 45.7 and 17.5%, respectively, are completely cemented by early ferroan calcite. The difference between the two wells may be due to the fact that the sandstone beds are thicker in well K-18. Where the early ferroan calcite is absent, mechanical compaction and quartz overgrowths have reduced the primary porosity further. In K-18, the framework grains are largely coated by a micritic-calcite rim, approximately 25 pm thick, which prevented silica cementation. Dissolution of the early ferroan calcite cement contributed most of the... 

These include (1) tight sandstones, (2) Devonian shales. (3t geopiessured zones, (4) deep basins, (5) gas associated with coal seams, and (6) gas in the form of methane hydrates. 

Fig. 6. Thin section photomicrographs of Norphlet Formation sandstones from Mobile Bay. (a) The tight-zone occurs at the top of the Norphlet, Almost all intergranular pore space is filled with quartz cement which encases grain-coating chlorite and pyrobitumen (black), (b) Porous reservoir sandstones occur beneath the tight-zone and are characterized by open intergranular pores that are lined with chlorite and pyrobitumen (black).

Fig. 8. Porosity versus air permeability for Norphlet sandstones from Mobile Bay. The data plotted are from the reservoir interval and are divided according to stratification type (determined by examination of core). Tight-zone samples have porosity <8% and air permeability < 1 mD regardless of stratifieation type and are excluded from this plot.

Throughout much of the Norphlet section, the pores are lined with a non-extractable, solid carbonaceous residue (pyrobitumen) that gives the sandstones their dark grey colour in core (Dixon et al. 1989). The occurrence of this material implies the former presence of liquid hydrocarbon pore fluids. In several of the cores examined in this study, pyrobitumen is present in the uppermost portion of the section and disappears with depth. The transition may represent a previous oil/water contact within the Norphlet. It does not correspond with or bear any consistent relationship to present-day water levels or the base of the tight-zone. 

Fig. 17. Small discontinuities in chlorite grain coats are common in the tight-zone but very rare in the porous reservoir sandstones. Minor breaks in grain coatings (arrows) are almost without exception linked to quartz overgrowths (QC) in the adjacent intergranular space.

Variation in the thickness of the low porosity tight-zone (3-58 m) at the top of the Norphlet Formation in Mobile Bay limits net pay and strongly influences the rate of natural gas production in individual wells. The proportion of tight-zone to porous reservoir sandstone in the Norphlet is unrelated to depositional facies, sediment reworking, geopressures, development of secondary porosity, or inhibition of diagenesis due to hydrocarbon pore fluids. 

Most oil reservoirs (sandstone and carbonate) are heterogeneous with permeability varying from one layer to another. Acidizing such heterogeneous media is very difficult, because most of the injected acid will flow into the high permeability zones and only a small amount of the acid will flow into tight zones. This uneven distribution of the injected acid represents a major economic loss for the following reasons ... 

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