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- Volume 4, Issue 1, 1998
Petroleum Geoscience - Volume 4, Issue 1, 1998
Volume 4, Issue 1, 1998
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Predicting hydrocarbon accumulations below deep Permian salt in the Pricaspian Basin; the use of shallow geochemical indicators
Authors L. Anissimov and G. MoscowskyThe Pricaspian Basin in the southeast of the Russian Platform contains a sedimentary column up to 20 km thick comprising Palaeozoic subsalt formations, Permian salt and suprasalt Mesozoic and Cenozoic terrigenous formations. The huge oil and gas reserves of the Basin are concentrated in subsalt Upper Palaeozoic carbonate reservoirs. Geologists generally agree that the hydrocarbons in the numerous, generally small fields discovered in Mesozoic reservoirs migrated from deeper, subsalt strata. This suggests that traces of fluids at shallow stratigraphic levels may indicate the deep, subsalt sources of the hydrocarbons and associated components. Subsalt reservoirs at depths of more than 6000 m are targets for future exploration. The location of hydrocarbon pools in such reservoirs may be indicated by geochemical investigations of the salt and of the terrigenous rocks above the salt. The distribution of geochemical indicators in the post-salt section may aid the prediction of undiscovered hydrocarbon pools in deep Palaeozoic carbonate formations.
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Integrated whole-rock trace element geochemistry and heavy mineral chemistry studies; aids to the correlation of continental red-bed reservoirs in the Beryl Field, UK North Sea
Authors J. Preston, A. Hartley, M. Hole, S. Buck, J. Bond, M. Mange and J. StillCorrelating continental red-bed successions in the sub-surface is a common problem for the hydrocarbon industry. These successions are typically barren of fauna and often monotonous, leading to non-diagnostic wire-line log signatures. A high-resolution, high precision study of detrital garnet chemistry within Triassic reservoir sandstones from the Beryl Field of the North Sea failed to subdivide the sequence satisfactorily. However, the whole-rock concentrations of immobile trace elements such as Zr, Nb and Cr can be shown to be controlled primarily by the abundances of the heavy minerals zircon, rutile and chrome-spinel, respectively. The chemistry of detrital rutile and chrome spinel varies widely within any one sample, implying that the whole-rock concentrations of Nb and Cr are also a function of the chemistry of these heavy minerals. Having calibrated a type well with a detailed mineralogical and geochemical study, it was possible to correlate between wells using whole-rock geochemical cross-plots.
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The Rotliegend of the NE German Basin; background and prospectivity
By Tommy McCannThe NE German Basin contains approximately 2.5 km of Rotliegend sediments, subdivided into four formations. These were deposited following the cessation of the Late Carboniferous/Early Permian volcanic episode and a c. 20 Ma period of erosion and non-deposition. Initial deposition was confined to two areas, but with increasing thermal subsidence the basin extended to the south. Petrographic and geochemical analyses suggest that the sediments are derived largely from cratonic or recycled sources. Volcanic and sedimentary rock fragments predominate. The succession was deposited in a relatively stable tectonic environment with sediment input derived largely from the Lower and Upper Palaeozoic strata of the Variscan hinterland and the Late Carboniferous and Lower Permian volcanics. Hydrocarbon prospectivity is confined to two main areas, with traps being predominantly stratigraphic and subtle.
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The geological selection of drilling fluids in horizontal wells
By Iain HillierThe drilling of horizontal wells has led to new demands on drilling fluid design. Less damaging drill-in fluids are formulated after extensive geological testing of the productive formation. This paper describes the main tests undertaken and some of the fluids commercially available. Geological analysis of the formation is followed by the testing of a proposed fluid, including extended exposures of the formation and fluid in conditions imitating those found downhole. Potential production impact is assessed by a return permeability test. With a clear understanding of what causes formation damage, drill-in fluid chemistry and properties can be engineered to prevent damage. Glycol, formate and sized calcium carbonate particle technologies are described.
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Uncertainty estimation in volumetrics for supporting hydrocarbon exploration and production decision-making
Authors Frans J. T. Floris and Martin R. H. E. PeersmannA methodology is presented for uncertainty estimation in volumetrics. Firstly, we stress the need for an open hierarchical methodology. This allows for a flexible work process in estimating uncertainty throughout the asset life cycle, in which data of various scales and accuracy must be integrated. Secondly, a method is explained for the transfer of spatial uncertainty in structure and rock properties to uncertainty in hydrocarbon volume. Thirdly, a new technique is presented for calculating average water saturation. Application to a synthetic case study shows that scalar uncertainty calculation leads to an underestimation of the uncertainty compared to a spatial approach. Spatial mapping of standard deviation of net hydrocarbon column indicates extra potential in the field. Incorporation of correlations in the field between, for example, porosity, permeability and water saturation, increases the uncertainty range. Using extra wells in the uncertainty estimation reduces uncertainty. Now, the known volume lies within the estimated proven-to-probable range.
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Correlation of fluid inclusions and reservoired oils to infer trap fill history in the South Viking Graben, North Sea
Authors G. H. Isaksen, R. J. Pottori and A. I. JenssenOrganic geochemical correlations between fluid inclusions and associated oils and oil-shows in Mesozoic reservoirs in the Sleipner area demonstrate generation from the same source rock organic facies (type II) for inclusions in wells 15/9-1 and 15/9-19. For well 15/9-9 the oil show is from a mixed type II/III source rock, whereas the fluid inclusion is from a type II source. All fluid inclusions are less thermally mature than the associated free oils and are thought to represent the earliest hydrocarbon yield from the source rocks. GC/MS/MS analyses of the fluid inclusions proved essential for resolving biomarker compounds and correlating them to reservoired fluids. Among the biomarkers, bisnorhopane contents in the fluid inclusions are consistently lower than in the associated reservoired oil. The expected dilution effect of bisnorhopane as progressively more hydrocarbons are generated from kerogen maturation is not observed. The difference in bisnorhopane amounts in fluid inclusions and oils is primarily due to varying relative hydrocarbon yields, through time, from different source rocks.
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The influence of fracture stiffness and the in situ stress field on the closure of natural fractures
More LessThe extent to which the aperture of natural fractures is reduced, and they are rendered closed and unproductive by the in situ stress field in the subsurface, is critical to planning the exploitation of naturally fractured reservoirs. The semi-log relation between stress and the reduction of natural fracture aperture is combined with the effective normal stress acting on fractures of varying alignment with respect to the horizontal stresses to yield the relation: delta = 1/q log(n+1/2n + n-1/2n cos2theta ) + logsigma ' H /q - p/q, where delta is the reduction of fracture aperture (fracture closure), p and q are constants in the semi-log fracture closure/stress relation, sigma ' H is the maximum effective horizontal stress magnitude, n is the ratio between the maximum and minimum effective horizontal stress magnitudes, and theta is the angle between the normal to the fracture and the sigma H direction. Key conclusions from this relation are: (i) for a given fracture, the sensitivity of fracture closure to the anisotropy of the in situ stress field can be constrained by the effective horizontal stress ratio; (ii) natural fracture closure is very sensitive to fracture alignment with respect to sigma H where the effective horizontal stress ratio is high; (iii) the sensitivity of natural fracture closure to its alignment with respect to sigma H decreases markedly as the effective horizontal stress ratio drops; (iv) except where the effective horizontal stress ratio is infinite, the rate of change of closure with changing alignment is relatively low at very low and at high misalignment angles, and much greater at intermediate angles. The above relation is applied to a number of fractures for which the closure/stress relations have been determined. With varying alignment with respect to sigma H , less stiff fractures show up to four times more closure than stiff fractures.
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Upper Cenozoic channels and fans on 3D seismic data in the northern Norwegian North Sea
More LessMiocene-Pliocene deposits of the northern Norwegian North Sea, quadrant 35, have been analysed on three 3D seismic surveys, 2D seismic sections and well logs to interpret the detailed stratigraphy, morphology and facies of regionally defined depositional systems. The interpretations might serve as analogues for subtle stratigraphic hydrocarbon traps in older deposits. A major Miocene channel system, possibly submarine formed, has been mapped. Analyses of the reflection heterogeneity attribute suggest sandy channel-fills and crevasse splays. Time-slices show pronounced Miocene-Pliocene incision close to the Norwegian continental North Sea margin. In a basinward direction mounded fans of high reflection intensity are identified at the mouths of narrow, sinuous feeder channels in the earliest Pliocene depositional sequence. Facies changes through prograding, deltaic systems tracts of the succeeding Pliocene sequence are identified from the reflection intensity attribute and logs. The systems were generally forced westward by Scandinavian uplift, while higher-order glacio-eustatic sea-level changes punctuated the westward prograding systems and formed high-frequency sequences.
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The role of faults in hydrocarbon migration
More LessIt is well known that the hydrodynamic behaviour of faults may be rather different from that of their surrounding beds. These characteristics may not be constant through time for a single fault and especially change during rupture events. Various numerical tests were performed using the TEMISPACK software to calculate the quantity of hydrocarbons that can migrate through damaged zones with high permeability in and near to a fault. The paper examines the influence on fluid flow of (1) the thickness of the fault zone, (2) the connectivity between fault and carrier beds, and (3) the opening time when permeability increases sporadically. The results confirm the importance of fault zones on hydrocarbon migration. Even when very narrow (2 meters), temporarily open (<100000 years), and moderately permeable (<10 mD), faults focus the migration of hydrocarbons. The flow is stronger in narrow, temporary faults but the quantities in circulation remain essentially the same. The nodes of the migration paths are the connections between faults and carrier beds (and/or source rock). This connection has a greater influence on the quantity of migrating hydrocarbons than does the intrinsic permeability of the fault. Given major hydrocarbon losses in the rock's porosity, thick drains are less efficient than are narrow zones for bringing the hydrocarbons to the reservoirs.
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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)