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- Volume 27, Issue 1, 2021
Petroleum Geoscience - Volume 27, Issue 1, 2021
Volume 27, Issue 1, 2021
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The evolution of the Dowsing Graben System: implications for petroleum prospectivity in the UK Southern North Sea
Upper Permian (Zechstein Supergroup) evaporites have a major control on structural styles and prospectivity in the UK Southern North Sea (SNS). They form the regional super-seal for the main Rotliegend Group (Leman Sandstone Formation) reservoir play fairway immediately beneath. The evaporites have highly variable thicknesses due to the syndepositional basin architecture, differential loading and post-depositional deformation through diapirism and salt withdrawal. The halokinetic activity leads to touchdown (welding) of the supra-salt section onto the sub-salt strata and the development of narrow (up to 15 km-wide) graben systems. The interpretation and depth conversion of well-calibrated, high-quality, 3D post-stack time-migrated (PSTM) seismic data along the southwestern margin of the basin show that a NW–SE-striking elongate extensional Dowsing Graben System transects the area. The graben is defined by a series of large, overlapping, en echelon listric growth faults, with oblique secondary planar faults, which sole-out on two main (deep and shallow) décollement levels in the Zechstein Supergroup and the Middle Triassic Röt Halite Member. Whilst its initial formation was related to Mesozoic extension, the graben system also displays a contractional overprint resulting from regional compression and structural inversion during the Cenozoic. Detailed mapping of the Zechstein Supergroup has revealed that the evolution of the extensional system was influenced by the ESE–WNW-striking anhydrite–carbonate Zechstein shelf-margin. The occurrence of variable-thickness, low-velocity sediments within the graben impacts seismic imaging and depth conversion, leading to prospective structures being overlooked; something that has implications for prospectivity in the SNS and other evaporite basins where similar graben occur.
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Petroleum geochemical aspects of the Mandawa Basin, coastal Tanzania: the origin of migrated oil occurring today as partly biodegraded bitumen
The shallow-marine Upper Jurassic–Lower Cretaceous sedimentary successions of the Mandawa Basin, coastal Tanzania, are located about 80 km away from the offshore gas discoveries of Block 2, Tanzania. In this paper we present petroleum geochemical data, including bitumen extracted from outcrop samples which are relevant to the understanding of the onshore ‘Petroleum System’ and possibly also to the offshore basin. Despite some biodegradation and weathering, common to all outcrop samples, most bitumen samples analysed contain mature migrated oil. The maturity span of geomarkers (C13–C15 range) covers the entire oil and condensate/wet gas window (R c = 0.7–2% R c, where R c is the calculated vitrinite reflectance), with the biomarkers generally indicating the oil window (R c = 0.7–1.3% R c). This suggests that the bitumen extracts represent several phases of migrated oil and condensate, which shows that the samples are part of an active or recently active migration regime or ‘Petroleum System’. The source-rock facies inferred for the bitumen is Type II/III kerogen of siliciclastic to carbonate facies. This is oil-prone kerogen, typical for a marine depositional system with an influx of proximal-derived terrigenous material blended in with in situ marine algal organic matter (OM). Application of age-specific biomarkers such as the C28/C29-steranes, extended tricyclic terpane ratio (ETR), nordiacholestanes and the aromatic steroids suggest that more than one source rock have contributed to the bitumen. Possible ages are limited to the Mesozoic (i.e. excluding the Late Paleozoic), with the most likely source rock belonging to the Early Jurassic. More geochemical and geological studies should be undertaken to further develop the general understanding of the petroleum system of the Mandawa Basin and its implications to the ‘Petroleum Systems’ both offshore and onshore. This paper also presents a reinterpretation of published gas composition and isotope data on the Pande, Temane and Inhassoro gas fields (Mozambique) with implications for possible oil discoveries in the gas-dominated region.
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Applications of real-time chemical stratigraphy in support of the safe drilling of HPHT wells: examples from the Shearwater Field, Central North Sea, UK
Authors Daniel Atkin, Manuel Vieira and Ben TaylorX-ray fluorescence (XRF) data from a series of high-pressure–high-temperature (HPHT) wells drilled in the Shearwater Field, UK Continental Shelf (UKCS) are presented. These data comprise a total of 789 samples across a series of eight study wells. Chemical stratigraphy was utilized in conjunction with other geological data (i.e. well logs, ditch cutting descriptions and biostratigraphic analyses) to aid real-time stratigraphic placement. Systematic changes in geochemical composition were identified and used to build a chemostratigraphic zonation to aid delineation of lithostratigraphic boundaries.
The application of chemical stratigraphy provided a valuable source of data, particularly through critical ‘drill-in-liner’ sections that are devoid of conventional logging while drilling (LWD) data. The identification of key geochemical zones and provision of a synthetic gamma-ray (Synth GR) profile were utilized in the placement of key casing points and identification of challenging top reservoir picks (Fulmar Formation). These data also served as a backup during LWD tool failure resulting from excessive temperatures. The successive addition of geochemical data accumulated with each well-site exercise permitted continued refinement of the zonation framework, with derived Synth GR profiles exhibiting an extremely close relationship with subsequent wireline logs. Chemical stratigraphic data are shown to be robust and repeatable within the Shearwater Field, enabling close stratigraphic control through critical sections, whilst also providing a low-cost backup in the event of conventional logging tool failures.
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Defining lithic patterns within river-dominated delta deposits for geostatistical simulation
Authors Brian J. Willis, Subhash Kalla and Tao SunReservoir development forecasts depend on accurate descriptions of the spatial distribution of rock properties that impact subsurface fluid-flow pathways and volume connectivity. Reservoir models constructed using geostatistical methods combine analogous facies dimension data with sparse subsurface data to predict spatial variations in rock properties. This study uses a physics-based depositional process model to define realistic facies variations within a river-dominated delta deposit formed during multiple shoreline regressions and transgressions. Geostatistical models are conditioned to varying amounts of information extracted from the depositional model to examine how well they reproduce the facies patterns. Reservoir simulation is used to examine the impact of analogous dimension data and varying conditioning constraints on reservoir performance predictions of water displacing oil. The dimensions of surface depositional features underestimate the continuity of preserved facies patterns, proportional grids following major flooding surfaces allow significantly better predictions than uniform rectangular grids, and trend constraints are more important when defined facies correlation length is significantly less than well spacing. When geostatistical model parameters are poorly chosen, reservoir simulation of the resulting weakly-structured facies patterns overpredict recovery and water breakthrough time. It is demonstrated that process-based depositional models can be used to optimize geostatistical model construction methods and input parameters to reduce uncertainty of reservoir development assessments.
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Stratigraphic palynology of the Middle–Late Triassic successions of the Central North Sea
Authors Roger Burgess, David Jolley and Adrian HartleyHistorically, the continental Triassic successions of the Central North Sea have proven difficult to correlate, in part due to the poor palynomorph recovery associated with these sedimentary rocks. The existing framework for correlation is lithostratigraphic and, whilst this has proven effective in United Kingdom Continental Shelf (UKCS) Quad 30 where the mudstone members are well defined, elsewhere in the basin it is more problematic with confident identification of stratigraphic units becoming more difficult. Samples from 32 wells within UKCS Quads 22, 29 and 30, and Norwegian Quads 7, 15 and 16 underwent palynological analysis in which a processing method was utilized that was designed to concentrate palynomorph recovery from Triassic strata.
The results of this analysis allowed the proposal of a new zonal scheme consisting of eight biozones. These biozones can then be used to correlate the Triassic successions of the Central North Sea (CNS), helping to provide both clarity and age constraint on previously disputed stratigraphic units, particularly the J-members of the Skagerrak Formation. Within the correlation framework outlined here, the Julius Mudstone Member is shown to be a productive horizon for palynomorph recovery, representing a widespread swamp environment. Here, its lateral extent is defined which is an important consideration when correlating the Triassic stratigraphy of the CNS given that this member can compartmentalize potential reservoirs contained within these successions. The stratigraphic palynology outlined here also allows clarity on the J-member equivalence of some of the informal units previously described within Triassic successions of the CNS, including the Marnock Shale and Heron Shale.
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A contribution to the petrophysical knowledge of the Lourinhã Formation as an analogue for the Statfjord Formation in the North Sea oil and gas fields
More LessThe Lourinhã Formation in the western region of Portugal is an analogue for the Statfjord Formation in the oil and gas fields of the Norwegian Northern North Sea. This petrophysics study encompasses a specific sandstone variety (M variety) of the Lourinhã Formation. This lithic arkose shows an average value of effective porosity of 18.5% and a permeability range of 20–30 mD, and is representative of the distribution range in the petrophysics models of the reservoirs of the Statfjord Formation. The petrographical, physical and mechanical characterization of the M variety sandstone is compared with the main features of the oil- and gas-producing sandstones of the Statfjord Formation in a reference well in the Norwegian Northern North Sea. Efficient enhanced oil recovery (EOR) projects in the oil and gas fields of the Norwegian Gullfaks hub are always needed, and this study intends to provide a contribution to that endeavour.
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Deformation and sedimentation processes, and hydrocarbon accumulations on upturned salt diapir flanks in the Lusitanian Basin, Portugal
Authors Ian Davison and Pedro BarretoThe onshore Lusitanian Basin is dominated by two large diapiric salt walls which extend for up to 100 km. Seismic sections indicate that stratal onlap onto an intervening salt pillow initiated in Early Jurassic times. Well-exposed diapir flanks reveal three types of halokinetic-related unconformities (hook, low-angle wedge and high-angle flap-onlap – a new term) of Kimmeridgian to Turonian age, indicating that diapirism was active throughout this period. Stratal dip-fanning and wedge-thinning is predominantly caused by original sedimentary depositional processes with multiple low-angle unconformities (1°–5° pinchout angles) in both carbonate- and clastic-dominated sequences. No significant sedimentary slumping was observed in the clastic-dominated strata but important slumping of flank material is present in the carbonate-dominated sequences.
Two tar accumulations are derived from oil trapped in sandstones on the flanks of the São Pedro de Moel and Santa Cruz salt diapirs. These are interpreted to be exhumed, but now biodegraded, oilfields. To our knowledge, these are the only exposed examples of salt-flank hydrocarbon accumulations that have been documented in the literature.
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Hydrocarbon-bearing characteristics of the SB1 strike-slip fault zone in the north of the Shuntuo Low Uplift, Tarim Basin
Authors Ziyi Wang, Zhiqian Gao, Tailiang Fan, Hehang Zhang, Lixin Qi and Lu YunThe SB1 strike-slip fault zone, which developed in the north of the Shuntuo Low Uplift of the Tarim Basin, plays an essential role in reservoir formation and hydrocarbon accumulation in deep Ordovician carbonate rocks. In this research, through the analysis of high-quality 3D seismic volumes, outcrop, drilling and production data, the hydrocarbon-bearing characteristics of the SB1 fault are systematically studied. The SB1 fault developed sequentially in the Paleozoic and formed as a result of a three-fold evolution: Middle Caledonian (phase III), Late Caledonian–Early Hercynian and Middle–Late Hercynian. Multiple fault activities are beneficial to reservoir development and hydrocarbon filling. In the Middle–Lower Ordovician carbonate strata, linear shear structures without deformation segments, pull-apart structure segments and push-up structure segments alternately developed along the SB1 fault. Pull-apart structure segments are the most favourable areas for oil and gas accumulation. The tight fault core in the centre of the strike-slip fault zone is typically a low-permeability barrier, whilst the damage zones on both sides of the fault core are migration pathways and accumulation traps for hydrocarbons, leading to heterogeneity in the reservoirs controlled by the SB1 fault. This study provides a reference for hydrocarbon exploration and development of similar deep-marine carbonate reservoirs controlled by strike-slip faults in the Tarim Basin and similar ancient hydrocarbon-rich basins.
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Volumes & issues
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Volume 30 (2024)
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Volume 29 (2023)
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Volume 28 (2022)
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Volume 27 (2021)
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Volume 26 (2020)
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Volume 25 (2019)
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Volume 24 (2018)
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Volume 23 (2017)
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Volume 22 (2016)
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Volume 21 (2015)
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Volume 20 (2014)
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Volume 19 (2013)
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Volume 18 (2012)
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Volume 17 (2011)
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Volume 16 (2010)
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Volume 15 (2009)
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Volume 14 (2008)
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Volume 13 (2007)
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Volume 12 (2006)
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Volume 11 (2005)
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Volume 10 (2004)
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Volume 9 (2003)
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Volume 8 (2002)
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Volume 7 (2001)
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Volume 6 (2000)
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Volume 5 (1999)
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Volume 4 (1998)
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Volume 3 (1997)
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Volume 2 (1996)
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Volume 1 (1995)