RELATIONSHIP BETWEEN DIAGENESIS AND PORE FLUID CHEMISTRY IN NIGER DELTA OIL‐BEARING SANDS

The sandstones of the Niger delta oil reservoirs are predominantly quartz arenites, yet silica cementation in the form of quartz overgrowth is at a minimum. This apparent lack of cementation is attributed among other things to the low concentration of silica in formation water, which results in low bulk‐volume reduction, little pressure‐solution and consequently, under‐compaction. Under‐compaction is aided by early calcite cementation which probably occurs at the boundary between the fresh waters of the Benin formation and the brackish to saline pore‐waters of the paralic sequence. Early cementation may have aided the discriminate entry of hydrocarbons into the reservoirs of the area. Entry of hydrocarbon into reservoirs appears to inhibit diagenetic processes as significant differences in mineral assemblages exist between hydrocarbon and non‐hydrocarbon reservoirs. Kaolinite is the dominant authigenic mineral in most hydrocarbon reservoirs whereas kaolinite, siderite, pyrite, calcite as well as minor amounts of smectite and illite occur in many non‐hydrocarbon reservoirs. The presence of mainly kaolinite in most reservoir rocks is suggestive of early entry of hydrocarbons into them. This deduction is at variance with the presently‐accepted theory of hydrocarbon generation within the deeply buried section of the paralic Agbada formation and the overpressured marine Akara shales. Instead, it suggests generation and migration of hydrocarbons from the paralic shales adjacent to the reservoirs. Lack of cemetation in most hydrocarbon reservoirs results in the production of very fine materials (“fines”) with the oil. It is proposed that most of the kaolinite present in many petroleum reservoirs is produced with such fines. The removal of kaolinite, in this way, reduces the hazard of permeability loss which would have occurred due to blocking of throat‐passages by floating kaolinite platelets.