- Home
- A-Z Publications
- Petroleum Geoscience
- Previous Issues
- Volume 24, Issue 3, 2018
Petroleum Geoscience - Volume 24, Issue 3, 2018
Volume 24, Issue 3, 2018
-
-
Geology and hydrocarbon potential of offshore SE Somalia
Authors L. M. Davidson, T. J. Arthur, G. F. Smith and S. TubbInterpretation of a 20 550 line km 2D seismic survey acquired in 2014 by Soma Oil and Gas in the deep water offshore area of SE Somalia has identified three previously undocumented sedimentary provinces – Jubba Deep, Mogadishu Deep and Mid Somalia High – all of which have distinctive geological characteristics. Well and stratigraphic controls are limited, with inferred lithologies largely based on seismic stratigraphic interpretation.
The Jubba Deep has a thick Late Cretaceous–Early Tertiary deltaic section deformed by major gravitational collapses in the Paleocene-age Kismaayo Thrust Belt (KTB) and the Pliocene-age Baraawe Thrust Belt (BTB). It is proposed that the KTB has significant hydrocarbon potential in deltaic and pro-delta sands trapped in thrust anticlines and sourced with oil from Mid-Cretaceous mobile shales.
The Mogadishu Deep Basin has a thick Mesozoic and Tertiary section but is missing the thick deltaics seen in the Jubba Basin. Volcanics are present in this basin.
The Mid Somalia High has a relatively thinner sedimentary section where Cretaceous and Jurassic reservoirs and potential source rocks are at moderate burial depths. An extensive post-rift Mid–Late Jurassic carbonate platform is developed here with potential hydrocarbon targets in interpreted reefs and shoal facies.
Supplementary material: Additional seismic examples and map figures are available at https://doi.org/10.6084/m9.figshare.c.3902650
-
-
-
Hybrid turbidite–contourite systems of the Tanzanian margin
More LessExtensive 3D seismic datasets acquired during exploration offshore southern Tanzania have revealed the complex architecture of two contrasting styles of hybrid turbidite–contourite deposits that formed in the Cretaceous (Albian–Early Campanian) and Paleogene (Paleocene–Oligocene). Both sequences are characterized by migrating channel-levee complexes, interpreted to record, and be diagnostic of, the synchronous interaction of eastward, downslope flowing turbidity currents and northerly, along-slope flowing contour currents. Flow stripping of the fine-grained suspended part of the turbulent flow by weak contour currents led to the formation of expanded levee-drifts on the northern (downstream) side of the channels, which prograded southwards (upstream), driving southwards migration of the turbidite channel axis.
The difference in the architecture of the two successions is due to the variation in slope topography at the time turbidite activity commenced and the frequency of coarse clastic input into the basin. Cretaceous (Albian–Campanian) turbidite systems were strongly controlled by the position of pre-existing contourite drifts and moats. The contorted geometry of the system provided loci for the deposition of Cretaceous reservoirs comprising thick, amalgamated channel deposits with a high net-to-gross ratio (N:G) and good vertical connectivity, and intra-slope fans with lower N:G and poor vertical connectivity.
Paleogene turbidite channels initially evolved on a smooth slope. Sustained southward channel migration produced Paleogene reservoirs comprising complexly laterally-connected sheets of channel and lobe deposits above a southward-younging, diachronous compound unconformity. In both hybrid systems, contour current influence modified the geometry of the turbidite systems, resulting in temporal and spatial partitioning of the depocentres on the slope.
-
-
-
3D source-rock modelling in frontier basins: a case study from the Zambezi Delta Depression
Authors Alice J. Butt and Kathleen GouldRegional modelling is vital for the preliminary analysis of a basin's hydrocarbon potential, especially when working on incomplete datasets. The Zambezi Delta Depression is a frontier basin that was selected to demonstrate how limited, publically available depth data can be used to evaluate source-rock maturity and hydrocarbon expulsion using 3D basin modelling. A geological framework was built with multiple datasets correlated using a global sequence-stratigraphic model. The identification of key events in the geological history of the region and the basin geometries allowed interpretation of intervals of organic enrichment within the basin during the Bajocian, Kimmeridgian and early Aptian. The results from the pressure and temperature modelling show that these potential source-rock horizons are currently overmature to gas mature in the Zambezi Delta Depression. Using the most likely heat-flow scenario, the timing of maturity and expulsion of the potential source rocks are strongly controlled by the geometry of the basin, with ages decreasing towards the SW. Expulsion modelling suggests that the Late Cretaceous plays are most likely to be charged by the early Aptian source rock, with older potential plays charged by the Jurassic source rocks. As the heat-flow model was poorly constrained, warmer and cooler temperature scenarios were also applied to qualitatively compare the impact on maturity, expulsion and accumulation of hydrocarbons in the basin. The modelling results, when compared with sparse published data, favour the most likely and warmer scenario.
Supplementary material: Details of the model input data, source-rock definitions and software used in this project are available at https://doi.org/10.6084/m9.figshare.c.3970863
-
-
-
Shale gas resources of the Bowland Basin, NW England: a holistic study
Authors Huw Clarke, Peter Turner, Robert Marc Bustin, Nick Riley and Bernard BeslyNew data from three shale gas exploration wells in the Bowland Basin of NW England contribute to the understanding of the stratigraphy, tectonic history and unconventional hydrocarbon resource potential of Lower Carboniferous strata. Three main prospective shales dominate the identified unconventional reservoirs: the Upper Bowland and Lower Bowland shales and the Hodder Mudstone, which are recognized by their distinctive lithology, corresponding log signatures and key zonal ammonoids. With a combined thickness of over 5000 ft (c. 1500 m), this sequence of shales is one of thickest known potential self-sourced, unconventional hydrocarbon resources. The strata are organic rich with total organic carbon (TOC) values of between 1 and 7%, with an average of 2.65%, and organic maturity that ranges from the upper oil window (pyrolysis T max c. 450°C) in the higher part of the section to dry gas (Ro = 2.4%; pyrolysis T max >470°C) in the Lower Bowland Shale. The sequence is strongly heterolithic, and up to 60% free gas is stored in thinly bedded carbonate and clastic silty turbidites. Adsorbed gas is concentrated in more organic-rich, hemipelagic shales which are distributed throughout the sequence. Near maximum burial temperatures of c. 130°C are inferred from vitrinite reflectance (Ro) and are consistent with fluid-inclusion microthermometry of carbonate-filled fractures. This indicates oil generation in the Late Carboniferous, prior to Variscan uplift. Renewed subsidence through the early Mesozoic resulted in increased maturity and gas generation. In the Bowland Shale the gas per unit volume of rock ranges from about 0.6 to 1.5 Bcf (billion cubic ft) per metre per square mile. The thick interval of gas-charged strata provides the opportunity to exploit these major hydrocarbon resources by using stacked multilateral wells from a common, strategically located and environmentally optimized surface pad.
-
-
-
Micropore network modelling from 2D confocal imagery: impact on reservoir quality and hydrocarbon recovery
More LessMicroporosity in carbonate reservoirs is globally pervasive and commonly used to explain high-porosity, low-permeability reservoirs, higher than expected water saturations, low resistivity pay zones and poor sweep efficiency. The potential for micropores to store and produce hydrocarbons has long been recognized, yet limitations on tools to evaluate microporosity has prevented rigorous evaluation. Here we demonstrate a workflow for evaluating microporosity through a combination of laser scanning confocal microscopy (LSCM) and pore network modelling. Specific values for microporosity and permeability calculated in our study should not be applied explicitly, as these are simulated values, but they demonstrate the viability of micropore networks to store and flow hydrocarbons. Carbonate reservoir assessment is critical not only in the petroleum industry, but also for applications in hydrothermal and mineral resources, carbon capture and storage, and groundwater supply. This approach can be applied to understand the potential for any reservoir to hold and transmit fluids.
-
-
-
Using simulation and production data to resolve ambiguity in interpreting 4D seismic inverted impedance in the Norne Field
Authors Masoud Maleki, Alessandra Davolio and Denis José SchiozerThe Norne Field started production in 1997 and up to 2006 the field experienced intense production activity, making the Norne benchmark case an ideal candidate to explore the challenges in interpreting complex time-lapse seismic data. Seismic amplitude changes and time-shifts are used as the first level approach to interpret the time-lapse differences and to update reservoir models. A common alternative is to invert the seismic data and obtain acoustic impedance variations caused by production activity, and to evaluate their possible interpretations. For this case study, we use a 4D inversion approach to invert the base (2001) and monitor (2006) seismic surveys in order to provide field-wide insights for the Norne benchmark case. We extensively interpret the observed 4D inversion anomalies and decouple, as much as possible, the effects of fluid and pressure variations, supported by production and reservoir engineering data. Moreover, we compare the inversion results with the simulation model from the Norne benchmark case to suggest areas of future modification to the simulation model. This research is intended as a resource to improve the quality of history matching or other 4D inversion methods applied to the Norne benchmark case, and to demonstrate a detailed time-lapse seismic interpretation within the reservoir segments of the Norne Field.
Supplementary material: Well-history data of six producer and injector wells is available at https://doi.org/10.6084/m9.figshare.c.3890251
-
-
-
Thermal maturity, hydrocarbon potential and kerogen type of some Triassic–Lower Cretaceous sediments from the SW Barents Sea and Svalbard
Rock-Eval and total organic carbon (TOC) analyses of 144 samples representing Triassic–Lower Cretaceous intervals from the SW Barents Sea (the Svalis Dome, the Nordkapp and Hammerfest basins, and the Bjarmeland Platform) and Svalbard demonstrate lateral variations in source rock properties. Good to excellent source rocks are present in the Lower–Middle Triassic Botneheia and Steinkobbe, and Upper Jurassic Hekkingen formations, 1 – 7 wt% and 6 – 19 wt% TOC, respectively. Hydrogen indices of 298 – 609 mg HC/g TOC in the Botneheia Formation from Svalbard, and 197 – 540 mg HC/g TOC in the Steinkobbe Formation of Svalis Dome suggest Type II (oil-prone) and Type II/III (oil/gas-prone) kerogens, respectively. The Kobbe Formation (Botneheia/Steinkobbe-equivalent) is organic-lean and generally gas-prone (Type III kerogen) on the Bjarmeland Platform and in the Nordkapp Basin, and is a good source rock with Type III/II kerogen in the Hammerfest Basin. In the investigated wells, the Hekkingen Formation is more oil-prone on the Bjarmeland Platform than in the Nordkapp Basin, while Lower Cretaceous samples have poor potential for oil. Upper Triassic samples show potential mainly for gas; however, coal/coaly-shale samples in well 7430/07-U-01 (Bjarmeland Platform) are oil/gas-prone. Most samples analysed are immature to early mature; thus, the variation in petroleum potential and kerogen type is a function of organic facies rather than maturity levels.
-
Volumes & issues
-
Volume 30 (2024)
-
Volume 29 (2023)
-
Volume 28 (2022)
-
Volume 27 (2021)
-
Volume 26 (2020)
-
Volume 25 (2019)
-
Volume 24 (2018)
-
Volume 23 (2017)
-
Volume 22 (2016)
-
Volume 21 (2015)
-
Volume 20 (2014)
-
Volume 19 (2013)
-
Volume 18 (2012)
-
Volume 17 (2011)
-
Volume 16 (2010)
-
Volume 15 (2009)
-
Volume 14 (2008)
-
Volume 13 (2007)
-
Volume 12 (2006)
-
Volume 11 (2005)
-
Volume 10 (2004)
-
Volume 9 (2003)
-
Volume 8 (2002)
-
Volume 7 (2001)
-
Volume 6 (2000)
-
Volume 5 (1999)
-
Volume 4 (1998)
-
Volume 3 (1997)
-
Volume 2 (1996)
-
Volume 1 (1995)