The purpose of this study is to identify the source rock, reservoirs and non-productive zones in the Lower Cretaceous Mauddud Formation in Kuwait, using geochemical methods. This formation is one of the major Cretaceous oil reservoirs. It is composed mainly of calcarenitic limestone interbedded with marl and glauconitic sands. Its thickness ranges from almost zero in the south to about 100 m (328 ft) in the north. A total of 99 core samples were collected from six oil fields in Kuwait: Raudhatain, Sabiriyah and Bahra in the north, and from the Burgan, Ahmadi and Magwa in the south. Well logs from these fields (gamma ray GR, sonic, resistivity, density) were correlated and used in the study. The core samples were screened for the amount and nature of the organic matter by Rock-Eval 6 pyrolysis (RE6) using reservoir mode. A set of samples was selected to study the properties of the organic matter including the soluble and insoluble organic parts. The geochemical characterisation was performed using different methods. After organic solvent extraction of rock samples, the solvent soluble organic matter or bitumen was characterised in terms of saturates, aromatics and heavy compounds (resins and asphaltenes). Then the hydrocarbon distribution of saturates was studied using gas chromatography (GC/FID) and gas chromatography-mass spectrometry (GC/MS) for tentative oil-source rock correlation. After mineral matrix destruction of previously extracted rocks, insoluble organic matter or kerogen was analysed for its elemental composition to identify kerogen type. The geology and the analytical results show similarities between the wells in the southern fields and the wells in the northern fields. Average Total Organic Matter (TOC) in the carbonate facies is 2.5 wt.% and the highest values (8.0 wt.%) are in the northern fields. The clastic intervals in the northern fields show higher total organic matter (1.3 wt.%) relative to the southern fields (0.6 wt.%). The total Production Index is higher in the carbonate (0.6) than the clastic section (0.3). This reflects the amount of extractable hydrocarbons, which are usually associated with the carbonate section in this formation, representing its reservoir section. Although the carbonate rocks are dominated by richer total organic matter, there are some intervals, with low total organic matter values (0.07 wt.%), representing its poor reservoir sections. The kerogen type varies between type II-III and III in the shales with a slightly better quality in the carbonate section. It is immature in almost all the studied fields. The composition of the rock extract has no relation with the ro ck type. Some sandstone show similar extract composition to the carbonate rocks in the reservoir intervals. The extracts from these intervals show different genetic nature than those in the shales. The maturity level in the reservoir extract is much higher than in the shale intervals. Thus, the oil accumulated in the reservoir might be largely related to migrated oil from a more mature source rock deposited in a clearly different environment than the associated shaly intervals. The best candidates being a more deeply buried Early Cretaceous Sulaiy Formation and Upper Jurassic Najmah Formation.
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