Use this URL to cite or link to this record in EThOS: http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.484813
Title: Molecular and isotopic constraints on oil accumulation in tertiary deltas
Author: Samuel, Olukayode James
ISNI:       0000 0001 3458 7047
Awarding Body: Newcastle University
Current Institution: University of Newcastle upon Tyne
Date of Award: 2008
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Abstract:
Deltaic basins of Tertiary age constitute a significant percentage of the sedimentary environments of the world's known hydrocarbon reserves and with more prospects of huge discoveries, renewed exploration activities are on-going in the progressively deeper waters of the continental shelf of deltaic basins (e.g. Gulf of Mexico, Niger Delta and Beaufort-Mackenzie Delta). Hydrocarbon exploration success depends on the knowledge of the petroleum systems (source rock, migration pathways, reservoirs, traps and seal) contributing to an oil accumulation. Although oil continues to be found in Tertiary delta reservoirs, multidimensional interpretation of literature data on crude oil geochemistry from these deltaic basins reveals a paradox in the geochemical characteristics of some of the reservoired oils with respect to the alleged Tertiary delta source rocks. Consequently there is no consensus on the origin of most of the deltaic petroleum accumulations. A poor understanding of the petroleum system (in particular the source rocks) escalates the risk of exploration as the presence, let alone the composition and phases, of petroleum could prove difficult to predict in undrilled prospects. Fairly representative crude oil samples taken from accumulations in Tertiary reservoirs of the Assam Delta (India), Beaufort-Mackenzie Delta (Canada), Gulf of Mexico (USA), Niger Delta (Nigeria) and the Kutei Basin (Indonesia) have been characterised for the purpose of predicting their source rock organic facies (organic matter type, depositional environment, age and thermal maturity). Biomarker and stable carbon isotopes analyses have been conducted on 120 samples from these basins in order to better understand the petroleum systems producing them. All the oils contain the angiosperm higher plant biomarker oleanane, in addition to other biomarkers like bicadinane and lupane which are not ubiquitous, thus providing evidence of higher plant inputs. Novel terpenoid biomarkers were discovered in many of the oils, whose relative abundances correlate strongly with those of conventional terrigenous biomarkers. Oils from Assam and the Kutei Basin are compositionally similar with pronounced terrigenous biomarker and stable carbon isotope characteristics that suggest expulsion from coaly to delta top shales deposited under highly oxygenated environments. Conversely, oils from the Gulf of Mexico show mixed marine-terrigenous and high marine algae source input biomarker and stable carbon isotopes signatures that suggest limited higher plant contribution to their organIc matter. Source rock deposition was under sub-oxic conditions (pristane/phytane) below a stratified water column (presence of gammacerane). On the basis of biomarker and stable carbon isotope data, oil accumulations from the Beaufort-Mackenzie and the Niger Deltas show greater diversity, grouping as dominantly terrigenous and dominantly marine algae sourced end-members, reflecting expulsion from source rocks deposited under oxic non-stratified and sub-oxic stratified water column conditions, respectively. These clear variations in the geochemistry of the oil accumulations can be attributed to oil sourcing from two discrete units: 1) Oils expelled from within the lean but thick source rock volume of deltas (intra-delta) which are characterised by abundant terrigenous biomarkers and stable carbon isotope signatures; 2) Oils expelled from source rocks rich in marine algal kerogen and envisaged as being laid down prior to the delta prograde, hence now buried below the Tertiary delta (sub-delta). The evidence suggests that sub-delta source rocks charge oil accumulations in the Gulf of Mexico, Beaufort-Mackenzie Delta and the deepwater Niger Delta. Bitumen extracts of core samples of the organic-rich late Cretaceous Araromi shale, from the Gbekebo well drilled in the Dahomey Basin on the western margin of the Niger Delta, are comparable both molecularly and isotopically to the deepwater Niger Delta oil set. This provides confirmatory evidence that similar sub-delta source facies may charge the deepwater Niger Delta accumulations.
Supervisor: Not available Sponsor: Petroleum Technology Development Fund (PTDF), Nigeria
Qualification Name: Thesis (Ph.D.) Qualification Level: Doctoral
EThOS ID: uk.bl.ethos.484813  DOI: Not available
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