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- Volume 6, Issue 1, 2000
Petroleum Geoscience - Volume 6, Issue 1, 2000
Volume 6, Issue 1, 2000
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Downflank hydrocarbon potential identified using seismic inversion and geostatistics: Upper Maastrichtian reservoir unit, Dan Field, Danish Central Graben
Authors Ole Valdemar Vejbæk and Lars KristensenPorosities considerably higher than anticipated from porosity/depth trend models are encountered in a Maastrichtian reservoir unit on the western flank of the Dan Field. Because there is a good correlation between seismic impedance and well log porosity, inverted seismic data are used to infer that highly porous zones are widely distributed. The distribution of these high porosity zones is predicted using geostatistical methods based on the inverted seismic data. These predictions contradict the general assumption that porosity deteriorates with depth in the study area. Annealing cosimulation is applied using inversion-derived seismic impedances as soft data and well log porosities as hard data. The sensitivity of the porosity characterization to hydrocarbon in-place estimates is investigated through the calculation of water saturations using height above free water level and simulated porosity as input parameters. Multiple realizations show that calculated hydrocarbon in-place estimates are more sensitive to the location of the free water level than to uncertainties related to the geostatistical reservoir characterization.
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Nang Nuan oil field, B6/27, Gulf of Thailand: karst reservoirs of meteoric or deep-burial origin?
More LessKarst reservoirs in the Chumphon Basin of the Gulf of Thailand have produced oil at well rates exceeding 10 000 BBL/d. Meteorically karstified buried hills were recognized as a potential exploration play. The Nang Nuan discovery well appeared to confirm such a play, and the concept prevailed despite the accumulation of contrary and unusual data. By the time a subsequent well had produced nearly 4 × 106 BBL oil, there was a desire to better understand the prospectivity of the concession. The accumulated data indicate that the highs are probably syn-rift horsts and inversion features. Karst reservoirs occur in Ratburi carbonates, and Mesozoic and Tertiary clastics, apparently unrelated to subaerial exposure. The karstification appears to be primarily of deep-burial origin, as indicated by the nature of the karst, substantial pore volumes that are difficult to account for, and temperature and flow anomalies consistent with active geothermal circulation. There are granites and hot springs in the vicinity, and abundant CO2 in this and neighbouring basins. Such deep-burial karst reservoirs have different implications for reserves estimation, prospect ranking and well completions.
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Estimation of length distributions from outcrop datasets – application to the Upper Permian Cutler Formation, Utah
Authors Clemens A. Visser and Antonio G. ChessaMany outcrops have partially exposed sedimentary bodies that are cut by one or both edges of the outcrop. These so-called ‘partials’ contain important information on the size distribution of the bodies under study, and should be accounted for in a proper statistical sense. A new method was proposed elsewhere, based on the theory of conditional probability. The method estimates the expected complete length along outcrop for each ‘partial’, making use of the length distribution of completely exposed bodies in the same outcrop. The estimated lengths are then added to the set of observed complete lengths to yield a new, refined length distribution. This paper illustrates the practical application of the method on an outcrop dataset from the Permian Cutler Formation in southeastern Utah that may serve as an analogue for mixed fluvial–aeolian reservoirs. Solutions are proposed for some practical problems that can be encountered when dealing with outcrop data. The estimated length distributions show that ‘partials’ add considerable information about the larger length classes.
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Uncertainties associated with fault sealing analysis
Authors Jonny Hesthammer and Haakon FossenRecent advances in understanding how faults restrict fluid flow in sandstone reservoirs have led to improved models for reservoir simulation. Nevertheless, there are still many uncertainty factors that can render even the most detailed simulation model useless. On a detailed scale, these uncertainties include variations in lateral continuity of faults, properties and thickness of fault zones, and the influence of deformation bands within and outside damage zones. Subseismic features such as small-scale relay zones, drag features and frequency and distribution of small faults around the fault zone further decrease the confidence level of simulation modelling results. Detailed analyses of seismic and well data from the Gullfaks Field, Northern North Sea, have helped understand the detailed structural reservoir characteristics. The results from these analyses can, in many cases, be used as input to further enhance models for reservoir simulation in order to increase the validation of the models. Furthermore, the studies carried out on the Gullfaks Field demonstrate that a sound approach to knowledge management for increased oil recovery based on fault seal analysis requires sharing of gained knowledge from many oil and gas fields rather than monopolizing information that cannot be fully utilized by studies from a single field.
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Reservoir identification and characterization through sequential horizon mapping and geostatistical analysis: a case study from the Gulf of Thailand
Authors B. Kongwung and S. RongheThe integration of sequential horizon slicing, attribute extraction, seismic facies characteristics, and wireline information from a Gulf of Thailand dataset enabled reconstruction of the depositional sequence, identification of reservoir units, and the analysis of reservoir geometry within an approximately 50 ms thick interval of seismic data. The depositional environment was verified to be fluvio-deltaic, with potential reservoirs comprising channel sands, associated point bars, thin crevasse splays and thin sand bars. Channel geometries were measured for five main channels using width/thickness ratios and sinuosity. Areal distributions of porosity, net sand thickness, gas saturation and hydrocarbon pore meter were predicted through geostatistical modelling. Collocated cokriged maps revealed high porosity and high sand thickness trends to relate to the main channel geometries. Collocated cokriged predictions of gas saturation and HPM distributions showed four potential areas of hydrocarbon accumulations where sand channels terminating against fault planes formed dip closures in structural highs.
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Tengiz oilfield: geological model based on hydrodynamic data
Authors Leonid Anissimov, Elena Postnova and Oleg MerkulovThe Tengiz oilfield, in the Precaspian Basin, western Kazakhstan, was discovered in 1981, but the size of the field and its large oil reserves were not fully estimated until many years later. Presently, it is known that the oilfield stretches over an area of almost 400 km2 but the thickness of the productive zone was not recognized untill recently. Formation pressure distribution in the Tengiz carbonate reservoir allows definition of the position of the oil–water contact. Reservoir characterization and hydrodynamic data are the basis for a dynamic model of the Tengiz oil accumulation which reflects the reservoir architecture, filling history of the reservoir and distribution of productive zones.
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Reservoir modelling sand-rich deep-water clastics: the necessity of down-scaling
Authors Andrew Hurst, Bryan Cronin and Adrian HartleyChannels, lobes and levees are inadequate architectural elements to describe sand body geometry in sand-rich deep-water systems. Sand sheets are the most common architectural element. Elutriation modifies primary sedimentary structures by mobilizing and reorganizing grains. This changes pore size distribution and permeability characteristics. Bed amalgamation and offset stacking of sand sheets makes problematic the use of bed thickness in correlation. A down-scaling approach for reservoir modelling is recommended, as a hierarchy of architectural elements that define up-scaling relationships cannot be established.
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Recognition and evaluation of low-resistivity pay
More LessA systematic procedure for the petrophysical identification and interpretation of low-resistivity and low-resistivity-contrast pay zones in intergranular reservoirs is founded upon an analysis of case histories for different reservoir types in diverse areas of the world. The approach acknowledges that a reservoir rock is a coupled physico-chemical system. The proposed method is generic and robust, it is conceptually simple, and it is structured in a manner that is easy to understand. The scheme is modular and it is arranged hierarchically to reflect maturing data scenarios: therefore, it can be progressively refined during the appraisal and development stages. The essence of the method is the definition and calibration of reliable interpretative procedures through quality-assured reference data from key wells by admitting only validated reservoir characteristics. Examples world-wide illustrate how failure to recognize low-resistivity pay can result in much loss of potential value.
A principal thrust is to facilitate the re-evaluation of other wells within the same reservoir system without the need for excessive acquisition of additional data. However, the proposed interpretation framework does allow the incorporation of new logging technology as this becomes established. The end-product is a flexible petrophysical interpretation scheme for these unconventional reservoirs that benefits from cost-effectiveness, portability, a higher degree of exactness and consequently a much reduced uncertainty.
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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)