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HYDROCARBON POTENTIAL OF THE LATE CRETACEOUS GONGILA AND FIKA FORMATIONS, BORNU (CHAD) BASIN, NE NIGERIA
Author(s) -
Alalade B.,
Tyson R. V.
Publication year - 2010
Publication title -
journal of petroleum geology
Language(s) - English
Resource type - Journals
SCImago Journal Rank - 0.725
H-Index - 42
eISSN - 1747-5457
pISSN - 0141-6421
DOI - 10.1111/j.1747-5457.2010.00483.x
Subject(s) - kerogen , source rock , maturity (psychological) , organic matter , geology , oil shale , hydrocarbon , palynofacies , total organic carbon , cretaceous , geochemistry , structural basin , mineralogy , paleontology , environmental chemistry , chemistry , organic chemistry , sedimentary depositional environment , psychology , developmental psychology
The hydrocarbon potential of possible shale source rocks from the Late Cretaceous Gongila and Fika Formations of the Chad Basin of NE Nigeria is evaluated using an integration of organic geochemistry and palynofacies observations. Total organic carbon (TOC) values for about 170 cutting samples range between 0.5% and 1.5% and Rock‐Eval hydrogen indices (HI) are below 100 mgHC/gTOC, suggesting that the shales are organically lean and contain Type III/IV kerogen. Amorphous organic matter (AOM) dominates the kerogen assemblage (typically >80%) although its fluorescence does not show a significant correlation with measured HI. Atomic H/C ratios of a subset of the samples indicate higher quality oil‐ to gas‐prone organic matter (Type II‐III kerogens) and exhibit a significant correlation with the fluorescence of AOM (r 2 = 0.86). Rock‐Eval T max calibrated against AOM fluorescence, biomarker and aromatic hydrocarbon maturity data suggests a transition from immature (<435°C) to mature (>435°C) in the Fika Formation and mature to post‐mature (>470°C) in the Gongila Formation. The low TOC values in most of the shales samples limit their overall source rock potential. The immature to early mature upper part of the Fika Formation, in which about 10% of the samples have TOC values greater than 2.0%, has the best oil generating potential. Oil would have been generated if such intervals had become thermally mature. On the basis of the samples studied here, the basin has potential for mostly gaseous rather than liquid hydrocarbons.