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- Volume 4, Issue 3, 1998
Petroleum Geoscience - Volume 4, Issue 3, 1998
Volume 4, Issue 3, 1998
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The salt pillow to diapir transition; evidence from unroofing unconformities in the Norwegian-Danish Basin
By Kai SorensenSalt diapirs in the Norwegian Danish Basin are characterized by the occurrence of marked angular unconformities which dip towards the diapirs. These unconformities developed above salt pillows, showing that the pillows grew close to the surface, or even reached the surface, in the time interval predating diapir formation. By contrast, the unconformities above present-day pillows show that these pillows have never reached close to the surface, strongly suggesting that pillow growth to "near unroofing" was a necessary condition for a transition to diapirism. Evidence from pillows indicates that unroofing in some cases was an asymmetric process involving growth of the pillow on the footwall side of a fault which soles out on the top surface of the salt. A consequence of this mechanism is that a separate stage of salt structure growth, with a combination of both pillow and diapir features, must be included in a general model for the "classical" Zechstein basin salt structures.
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Reservoir development, sequence stratigraphy and geological modelling of Westphalian fluvial reservoirs of the Caister C Field, UK southern North Sea
Authors J. S. Ritchie, D. Pilling and S. HayesThe earliest Westphalian B reservoir of the Caister C Field (informally named the Caister Sandstone Unit consists of erosive conglomeratic sandstones deposited in stacked low sinuosity fluvial channels. Channel types and architectural elements demonstrate an upward change to more sinuous forms. The Caister Sandstone Unit is believed to contain incised valley-fill sediments deposited as late lowstand and transgressive systems tracts when rising base level generated accommodation space. The dominant control on reservoir quality is primary depositional texture with the best permeability found in higher energy coarse sandstone and pebbly intervals associated with basal channel-fill units; crevasse channel and splay sandstones offer poor reservoir properties. The robust correlation framework, which is based upon laterally extensive coal seams, enables a sequence stratigraphic model of the field to be developed, thereby allowing a better understanding of reservoir extent and sandbody continuity. A 3D geocellular geological model is built with reservoir architecture elements controlled by the sedimentological model. This is used for volumetrics calculations, input to a reservoir simulator and in the locating and planning of in-fill wells.
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Reservoir characterization of a shallow marine sandstone; the Lower Cretaceous Sandringham Sands (Leziate Beds) and Carstone formations, eastern England
More LessAn onshore shallow marine sandbody has been investigated in several extensive quarry outcrops in the Norfolk area of eastern England in terms of its sedimentology (sedimentary structures, geometry and architecture), sequence stratigraphy and reservoir-scale heterogeneity. In addition to conventional sedimentological logging techniques, vertical profiles were analysed using a steady-state electronic probe permeameter to investigate permeability heterogeneity. Permeability analysis was also complemented by spectral gamma ray profiles, which were used to characterize facies associations in terms of their total radioactivity and relative proportions of potassium, uranium and thorium. It was found that lithofacies type and bounding surface have the dominant control on permeability heterogeneity and thus flow unit compartmentalization. This study aims to complement pre-existing outcrop analogue datasets which attempt to model fluid flow more accurately in analogous subsurface reservoirs. It also serves to highlight the difficulty in accurately identifying and modelling subsurface shallow marine/estuarine tidal channel depositional systems for well/drainage and or production strategies.
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Palaeostructure and palaeogeography from 3D seismic interpretation; examples from the Permian Basin in Poland
Authors Maciej Gorski, Malgorzata Trela and Wieslawa Kunicka-GorskaThe Permian Basin is the main target of exploration in western Poland. Porous Rotliegendes sandstone and two Zechstein carbonate formations are the most important reservoirs. Every depositional system includes different lithofacies, and interrelations create patterns of trap/reservoir and sealing horizons. Combination traps, with both structural and facial elements involved in their closure, create a comparatively high risk for exploration. Palaeogeographic analysis based on 3D seismic data presents opportunities for improved interpretation leading to a significant reduction of risk in exploration and development drilling. There is no direct information in 3D seismic data, but they allow us to reproduce the palaeogeography and successive stages of structural redevelopment by means of flattened seismic sections and construction of the corresponding maps, i.e. pseudo-palaeogeographical maps.
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Facies related geological model; a reliable method to describe complex reservoirs
Authors M. Rovellini, F. Brega and C. MonicoThe proposed methodology utilizes the concept of facies as the basis for reservoir characterization. Facies represent the elementary units of the reservoir. They are objectively determined through a log-based cluster analysis, and are fully characterized with petrophysical properties from cores. A stochastic model is used to distribute facies and related petrophysical parameters (porosity, permeability and irreducible water saturation) within the reservoir volume. Several equally probable reservoir realizations are generated from the same model and tested in a flow simulator. The realization providing the best history match is selected for production forecasts.
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Physical constraints on hydrocarbon leakage and trapping revisited
Authors Per Arne Bjorkum, Olav Walderhaug and Paul H. NadeauIn a water-wet petroleum reservoir with a water-wet seal, a continuous water phase will extend from the reservoir into the seal, and the pressure difference between the water phase in the uppermost pores of the reservoir and the water phase in the lowermost pores of the seal can therefore only be of an infinitesimal magnitude. This implies that any overpressure in a water-wet reservoir will not contribute to pushing the hydrocarbons through a water-wet seal, and overpressured water-wet reservoirs should therefore not be considered more prone to capillary leakage than normally pressured reservoirs. Within a water-wet petroleum reservoirs, the overpressure in the hydrocarbon phase relative to the water phase is balanced by the elastic forces at the fluid interface (interfacial tension). The overpressure in the hydrocarbon phase relative to the water phase therefore does not increase the risk of hydrofracturing the reservoir's seal. This implies that the risk of hydrofracturing should not be increased as a function of hydrocarbon column height, and should not be considered to be higher for gas than it is for oil. When an upward-directed hydraulic gradient is present from a reservoir unit into the overlying seal, water will continuously move upwards from the reservoir unit and into the seal if both rocks are water-wet. This movement of water may lead to exsolution of gas above the reservoir unit, and the presence of free gas may be detected as gas chimneys on seismic sections. This mechanism will operate regardless of whether or not a hydrocarbon accumulation is present below the gas chimneys, and fracturing of the reservoir unit's seal or capillary leakage of hydrocarbons are therefore not necessary conditions for the development of gas chimneys.
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Representation and scaling of faults in fluid flow models
Authors J. J. Walsh, J. Watterson, A. E. Heath and C. ChildsFault representation and scaling in flow models are examined with respect to fault zone properties, the accuracy with which they can be determined, and how these variables and fault geometries can be incorporated realistically in to flow models. Outcrop data show that fault displacement/thickness ratios and permeability vary widely. For simple single fault models, results for numerical models are compared with analytical and statistical methods. Representation of a fault as a transmissibility surface conflates the effects of four variables--fault zone thickness and permeability, grid-block size and matrix (host-rock) cell permeability. Random spatial variation of transmissibility factor values is well represented by a uniform transmissibility factor which is the arithmetic mean of the values representing log-normally distributed permeability and thicknesses. Realistic ranges of fault zone thicknesses can be represented without grid-block refinement by an upscaling method based on simple transformation of transmissibility factor curves derived from a range of coarse grid-block models. Sub-seismic faults have significant effects on effective permeability of model volumes at kilometre scales only when the faults are assigned a permeability less than c. 0.001 of the matrix permeability.
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The Bahar oil and gas-condensate field in the South Caspian Basin
Authors A. A. Narimanov, N. A. Akperov and T. I. AbdullaevThe Bahar Field was discovered in 1968 and contains oil and gas-condensate in sandstones and sandy siltstones belonging to the middle Pliocene Productive Series. This has a total thickness of 3600 m. It consists of alternating sandstones, sandy siltstones and shales, with thicknesses between 5 m and 50 m and is of deltaic origin. The reservoir rocks have porosities of 13-18% and permeabilities of 45-250 mD. Biomarker geochemical analyses of onshore and offshore fields show that the Pliocene oil and gas fields in the South Caspian Basin have been charged primarily from epigenetic hydrocarbons. The hydrocarbons have migrated vertically along faults from older source rocks, probably including organic-rich shales of Oligocene to early Miocene age. The Bahar Field is quite mature. Of the original hydrocarbons in place, 72% of the gas has been produced, 39% of the condensate and 11% of the oil. The main oil-bearing horizons, the Pereriv Suite (SP) and Balakhany X, are developed with reservoir pressure maintenance by longitudinal and marginal (up-dip) flooding of surfactant-added sea water.
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A reservoir model for the main Pliocene reservoirs of the Bahar Field in the Caspian Sea, Azerbaijan
In this paper the results of a reservoir evaluation study of the Bahar Field, one of the most important oil and gas fields in the Azerbaijanian sector of the Caspian Sea are presented. The study has concentrated on the most important reservoir sections, Balakhany X and Pereriv Suite, encompassing (i) sedimentological and stratigraphic interpretation, (ii) petrophysical analysis, (iii) structural interpretation, (iv) assessment of hydrocarbon distribution, (v) geochemical characterization of the hydrocarbons, (vi) assessment of reservoir compartmentalization, (vii) establishment of static and dynamic reservoir models in digital format, as a basis for calculating in-place resources and assessing the potential for improved oil recovery. The study has provided new and detailed insight into the reservoir architecture and properties of the Bahar Field. In a broader context this detailed information and data analysis is believed to provide an improved basis for evaluating other tested and untested structures in this prolific hydrocarbon province.
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The palingenesy of the Piper oil field, UK North Sea
By S. D. HarkerPiper was discovered in 1972 by the 15/17-1A well, located on a 4-way dip closed structure on the northern flank of the Witch Ground Graben. Appraisal drilling through 1973 showed the field to comprise four gently folded, tilted fault blocks with productive reservoirs in Late Jurassic paralic to shallow marine sandstones (Sgiath and Piper formations). Production commenced in 1976 and until the Piper Alpha disaster of 1988, the field had produced 834X10 6 bbl oil out of the then estimated recoverable reserves of 952X10 6 bbl. Redevelopment started by pre-drilling 1 injection and 7 production wells based on 1990 reprocessed 3D seismic, prior to the installation of the Piper Bravo platform in 1993. A study of permeability repartition and sweep efficiency, combining existing and new well data from cores, logs, pressures and fluid distribution, aided the optimization of well locations. In addition, a new 3D seismic survey was acquired in 1992-3. Advantageous fluid redistribution and natural aquifer repressurization of the reservoirs occurred during the 4 1/2 years of production shutdown. By mid-1996, 12 production and 4 injection wells were in operation. Piper Bravo wells redeveloped three of the four fault panels, using half of the number of wells in operation at the time of the Piper Alpha disaster. The production rate has been significantly increased over the projected 1988 decline and a much lower water cut achieved. The ultimate recovery for the Piper field is now estimated at 1014X10 6 bbl oil (-3.4%), an increase of 62X10 6 bbl over the pre-redevelopment figure.
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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)