There is little doubt that sediments of Upper Jurassic to lowermost Lower Cretaceous age, particularly those of the Kimmeridge Clay Formation and its equivalents, are the source of the vast bulk of the oil in the Central and Northern North Sea. This is true both of oil in conventional Mesozoic plays and in Tertiary clastic reservoirs. The timing of oil generation and migration ranges from the Late Cretaceous through to the present. The oil productivity of the Kimmeridge Clay Formation in the Central Graben, Moray Firth and South Viking, Graben areas of the North Sea is estimated to be in excess of 250 billion barrels, of which about 25% is accounted for in accumulations discovered to date. There is strong areal differentiation between oil trapped in Mesozoic reservoirs as opposed to Upper Cretaceous Chalk and Tertiary reservoirs. This paper is particularly concerned with hydrocarbons in Tertiary reservoirs, which have a wide range of compositions and appear to have complex accumulation and degradation histories. Migration to Chalk and younger Tertiary reservoirs occurs often through thick shale sequences. The evidence for the timing and mechanism of this process is considered and a preferred model for the vertical migration and subsequent lateral migration, mixing and degradation is proposed.
Detailed geochemical and geothermal studies have been carried out in the Red Sea and Gulf of Aden in order to understand the regional distribution of source rocks through time, and the effects of changing heat flow through time. These studies have shown the presence of generally thin developments of fair to very good quality source rocks. Most of the identified source rocks occur in syn‐rift sediments throughout the Red Sea area, but pre‐rift source‐rock occurrences have been identified in Yemen (Gulf of Aden). Somalia, and to a lesser extent in Egypt. Isolated occurrences of post‐rift source rocks have also been identified. The data can be interpreted in the regional context of the sedimentary facies of the region in order to predict possible geographic distribution of source rocks. Maturity gradients determined using vitrinite reflectivity and spore coloration range from low (often in post‐rift sections) to high (often in syn‐ and pre‐rift sections). The maturity gradients in many of the sections analysed show intersecting bi‐linear trends, suggesting very high palaeogeothermal gradients in sediments close to the rifting centres. In such areas, the oil and gas “windows” are relatively shallow and thin. In areas where crustal thickening has reduced heat flux. hydrocarbon generation may have occurred in the past, but has since ceased. The models derived during this project for source‐rock distribution and heat‐flow variations are consistent with the tectonic evolution of the basin, and show that there is good potential in parts of the study area for oil generation, accumulation and preservation in pre‐rift, syn‐rift as well as in post‐rift sediments.
Production allocation from petroleum geochemistry is defined here as the quantitative determination of the amount or portion of a commingled fluid to be assigned to two or more individual fluid sources (e.g., a pipeline, field, reservoir, well) at a particular moment in time, based on the fluid chemistry. It requires: i) knowledge of the original chemical compositions of each of the fluids prior to mixing (referred to here as the "end members"), and ii) that statistically valid differences in their chemistries can be identified. Petroleum geochemical-based methods for production monitoring and allocation are much lower cost than using production logging tools, as there is no additional rig time or extra personnel required at the well site. Additionally, no intervention to the production of hydrocarbons from a well is required and, hence, there is none of the risk entailed in additional operational activity. Geochemical methods are applicable to a wide range of fields, irrespective of pressure, temperature, reservoir quality and reservoir fluid type. The method has been in existence for over 30 years, during which time a number of different analytical methods, data pre-processing and treatment approaches have been applied. This paper summarises these approaches, and provides examples, but also describes a "best practice" which is not a "one size fits all" approach, as is sometimes seen in the literature. A successful production allocation study consists of the following steps: i) Selection of end member samples that contribute to the commingled production fluid; ii) Determination of the differences in chemical composition of the end members through laboratory analysis of the end members (e.g. by WO-GC), replicate analyses of samples and statistical treatment of the data (e.g. PCA); iii) If statistically significant differences exist, laboratory analysis of the end members and commingled fluids with appropriate replicate analyses of samples; iv) Data selection, pre-processing (e.g. selection of ratios or concentrations of components); v) Determination of end member contributions by solving equations (e.g. least squares best fit) and uncertainty estimation (e.g. Monte Carlo or Bootstrap methods). The differences in approach for conventional versus unconventional plays are also discussed.
The assessment of a Petroleum System includes several steps, which comprise: detailed evaluation ofsource rock, charge history, trap, seal and reservoir. As a result, a multi-scale and multi-disciplinary approach was necessary to obtain a final cohesive product. This paper aimed to improve basin modelling and prospectivity evaluation thanks to the integration of structural geology analysis, geochemical analysis, petrophysical analysis, geophysical interpretation of seismic data, stratigraphic correlations and reservoir quality evaluations. An area in onshore SE Abu Dhabi was chosen for the 12-months Petroleum System Study, where fiveteams underwent rigorous technical work independently and in combination. All the analyzed data were combined to define potential leads and prospects and assess the areal risking at different stratigraphic intervals. The limitation of data availability on the eastern side of the study area, affected the confidence of the main results, but we were able to accomplish an advanced view of the risk and opportunity in the exploration for hydrocarbons within onshore SE Abu Dhabi. The Thamama F reservoir, TH_LK_3 (Lekhwair Formation), has been identified as a key explorationtarget. Thamama F is also a good regional migration carrier bed due to (1) high continuity and very good reservoir properties and, (2) it has a thick very continuous regional top seal. The Thamama B reservoir zone (TH_KH_2 – Kharaib Formation), Thamama A reservoir zone (TH_SH_1 – Shuaiba Formation) and Habshan Formation (HA_2, Sequence 3) also have good exploration potential but the POS at these intervals is relatively lower. Overall, leads in the SSE Abu Dhabi are impacted by a higher risk on hydrocarbon charge, principally due to long distance migration from the source kitchen to the north. Stratigraphic leads have been identified in the Shuaiba Formation, specifically the Upper Bab Member (TH_SH_3) and the Habshan (HA_2). They are high risk but high reward exploration opportunities, which require further work to de-risk. A detailed study of this kind has not been conducted before within onshore SE Abu Dhabi. The outcome of this extensive technical work resulting from the integration of the six distinct sub-surface disciplines and the integrated approach allow us to mature drillable prospects, which will surely be of interest for any other operating company in the same area or in different areas.
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