2014 GSA Annual Meeting in Vancouver, British Columbia (19–22 October 2014)

Paper No. 129-6
Presentation Time: 10:15 AM

ORGANIC GEOCHEMICAL EVALUATION OF THE MAASTRICHTIAN COAL AND SHALE FACIES OF GOMBE FORMATION, GONGOLA BASIN, NIGERIA


OJO, Olusola J.1, JIMOH, Ayoola1, AKANDE, Samuel O.2 and SOLA-OJO, Foluke E.3, (1)Geology and Mineral Sciences, University of Ilorin, Nigeria, P.M.B. 1515, Ilorin, Kwara State, Nigeria, Ilorin, 240001, Nigeria, (2)Geology Department, University of Ilorin, PMB 1515, Ilorin, 240003, Nigeria, (3)Department of Animal Production, University of Ilorin, Nigeria, P.M.B. 1515, Ilorin, Kwara State, Nigeria, Ilorin, 240001, Nigeria, solafoluk@yahoo.com

The Maastrichtian Gombe Formation is located within one of the inland basins of Nigeria (Gongola Basin) with relatively unknown petroleum potential. The coal and interbedded shale of this formation appear most prospective facies and is evaluated with respect to its hydrocarbon source rock potential in this study. At the Maiganga coal mine, about 35m thick coarsening upward section of the Gombe Formation consisting from base to top, coal and shale interbeds that grade upward into siltstone and sandstone were logged and interpreted as fluvial-deltaic deposits. Palynomorph assemblages; Buttinia andreevi, Proxapertites operculatus, and Retidiporites magdalenensis support the Maastrichtian age and reflect terrestrial fresh water dominated environment.

The organic geochemical results show that the organic carbon content of the coals is high (62.75-65.29 wt %) and moderate (1.78-2.99 wt %) for the shales. S2 values for the coals are high (57 to 103.21 HC/g rock) and relatively low (less than 3 HC/g rock) in the shales. The HI less than 200mgHC/gTOC for all the samples (29-64 mgHC/gTOC and 90-140mgHC/gTOC for shale and coal respectively) suggest Type III kerogen and plant contributions from terrestrial sources. Consequently, gaseous hydrocarbon potential is exhibited in the source beds. This is supported by the PI (< 0.1) and the ratio of S2/S3 ranging from (0.6-5.5).

The Tmax ranging from 425 to 430 0C and 416 to 422 0C for the shales and coals respectively (and generally less than 4350C) indicate pre oil window stage in spite of the high organic matter concentration. Plot of production Index PI versus Tmax based maturity indicate low level organic matter conversion. In conclusion, the samples constitute good source rock and have potential for gas but the kerogens are not thermally mature to generate oil.