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Title: Unconventional offshore petroleum-extracting oil from active source rocks of the Kimmeridge Clay Formation of the North Sea
Author: Raji, Munira
ISNI:       0000 0004 7230 9971
Awarding Body: Durham University
Current Institution: Durham University
Date of Award: 2018
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The organic-rich Upper Jurassic Kimmeridge Clay Formation is the major source rock for conventional oil and gas in the North Sea with a maximum thickness of 1,100 m. TOC values range from 2 wt.%-10 wt.% and predominantly Type II (bacterially-degraded algal, and a mix of Type I (mainly algal) kerogens. The δ13Corg values for the investigated samples range from -29.73 ‰ to -26. 88 ‰, these values are characteristic of marine organic matter with terrestrial input. Sixteen billion barrels of commercial reserves have been discovered in conventional reservoirs in the UK Viking Graben area with 29 billion barrels discovered in the Norwegian sector of the North Sea. However, this principal UK conventional hydrocarbon province is reaching the maturity phase of field exploration, leading to a growing interest for unconventional hydrocarbons in the UK and some part of Europe. The purpose of this study is to evaluate the unconventional hydrocarbon potential of the Kimmeridge shale to identity sweet-spot areas using multidisciplinary analogues from successful unconventional resource plays in North American. Conventional and unconventional source rock analyses show that the Kimmeridge Clay Formation contains a significant amount of un-expelled residual oil both within the source rock and in the interbedded sandstone in the South Viking Graben area. As a consequence, this source rock and juxtaposed non-source lithofacies (sand interbeds) can form a hybrid shale resource system. Due to its high organic richness and favourable sweet-spot reservoir properties such as lithology, thickness, kerogen type, level of thermal maturity and hydrocarbon generative potential, the Kimmeridge Clay Formation could be the first offshore unconventional resource in the future. TOC, Rock-Eval S1, Tmax, mineralogical content and the formation of organic, interparticle and intraparticle porosities at peak oil maturity are all factors that have influenced the retention and drainage of the observed oil. The examination/analysis of their interrelationships provides a useful framework and signature for future prediction of sweet spot areas for viable unconventional resources.
Supervisor: Not available Sponsor: Not available
Qualification Name: Thesis (Ph.D.) Qualification Level: Doctoral
EThOS ID:  DOI: Not available