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- Volume 7, Issue 2, 2001
Petroleum Geoscience - Volume 7, Issue 2, 2001
Volume 7, Issue 2, 2001
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Investigation of the petrophysical properties of a porous sandstone sample using confocal scanning laser microscopy
Authors N. Petford, G. Davidson and J. A. MillerConfocal scanning laser microscopy (CSLM) is used to produce images of the two- and three-dimensional distribution and geometry of pore space in a reservoir sandstone and measure the 2D distribution of pore throat radii. Nondestructive serial sectioning of the rock using laser light at 100% illumination, combined with image thresholding and histogram equalization techniques allow the pore volume structure of the uppermost 100 μm of the sample to be reconstructed. Negative imaging of the pore volume gave superior depth and feature resolution compared to positive (reflection) imaging. Artefacts encountered in applying classical Medial Axial Transforms to CSLM images include branch networks dominated by coordination numbers of 3. Skeletonization using Euclidean distance maps gives increased accuracy in the description of the pore network. Measured pore throat size distribution in the rock is strongly exponential and described by the expression y=219e −0.25 x where y is the number of pore throats.
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Quantitative modelling of basin subsidence caused by temperature-driven silica dissolution and reprecipitation
Authors Olav Walderhaug, Per Arne Bjørkum, Paul H. Nadeau and Olaf LangnesEquations describing the rate of vertical thinning of sandstones due to precipitation of quartz cement produced at stylolites are derived for constant temperature and for a linear temperature change. All temperature histories can be approximated by a series of linear segments, and the equations therefore enable the diagenetic thinning of sandstones undergoing quartz cementation to be calculated as a function of temperature history. Application of the equations to interbedded sandstone–shale sequences indicate that for heating rates and geothermal gradients commonly encountered in sedimentary basins, thermally driven diagenesis leads to cumulative rates of sandstone thinning in the range of 1–10 m Ma−1. This implies that when effects of thermally driven shale diagenesis, mechanical compaction and isostatic adjustment are taken into account, thermochemical diagenetic thinning may explain a large proportion of the total generation of accommodation space in many basins. The equations describing the rate of sandstone volume reduction and, therefore, rate of fluid expulsion, could also be utilized for calculating overpressure development.
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Fluvial reservoir architecture in the Statfjord Formation (northern North Sea) augmented by outcrop analogue statistics
More LessOutcrop data from the fluvial/incised valley systems of the Cretaceous Straight Cliffs Formation of southern Utah, USA, are applied to the subsurface fluvial reservoirs of the Statfjord Formation. Aspect ratios (width:thickness) for fluvial sandbodies have been measured from large-scale cliff exposures. This database provides the lateral extent, or width, of any fluvial sandbody, given the thickness for that sandbody and the net-to-gross of the interval in which it is preserved. This allows prediction of a probability distribution for fluvial sandbody width from one-dimensional vertical well data.
The outcrop data are applied to one well in each of the Brent, Statfjord and Snorre fields, through similar stratigraphic intervals, to allow comparison of the various sandbody architectures which result from the same outcrop dataset. Various fluvial architectures are identified: from high net-to-gross and high connectivity, to low net-to-gross with low sandbody connectivity.
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High resolution geochemical and petrographical correlation of deep marine Palaeocene sandstones from the Foinaven Field, West of Shetland
Authors Alasdair Hutchison, Adrian Hartley, Malcolm Hole, Emma Whear and Jeremy PrestonCores from three wells in the Upper Palaeocene deep-marine reservoir interval of the Foinaven Field, West of Shetland have been analysed using trace element geochemistry and petrography. The 60 m thick turbidite-dominated succession is restricted to the T34 biozone and comprises a series of seismically defined channel and overbank deposits. Petrographic and trace element geochemical data indicate that wells 204/24a-3 and 204/25b-5 have strong similarities and that strata in the remaining well (204/24a-7) have distinctly different signatures. Of the two related wells, 204/25b-5 is dominated by a thick amalgamated sandstone succession, 204/24a-3 by more thinly bedded and finer grained sandstones considered to represent channel and associated overbank deposits respectively. Similarities in geochemical and petrographic data allow division of the biozone in the two related wells into four principal correlation zones with two additional sub-zones. The study has established a high resolution correlation scheme and constrained correlation lengths for reservoir and non-reservoir facies in a deep marine depositional system.
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Production of gas from waterflood residual oil: gas saturation build-up and relative permeabilities
Authors C. A. Grattoni, R. I. Hawes and R. A. DaweWhen solution gas is released from waterflooded residual oil by depressurization, the gas becomes mobilized after the critical gas saturation has been reached, but the gas saturation continues to increase as more gas is generated. The rate of gas saturation change plus the unrecoverable gas (gas saturation remaining at the end of the depressurization) are important in determining the economic performance of the process. The values depend upon the rate of gas generation and the gas relative permeability.
Experiments are reported to measure water and gas relative permeabilities when gas is released from waterflooded residual oil. The values for the gas phase were extremely low, approximately an order of magnitude lower than would be predicted using a Corey-type equation suggesting that gas relative permeabilities measured in normal gas–water displacement experiments are not applicable to the depressurization of waterflooded reservoirs.
The low values of gas relative permeabilities can be explained by the fact that the filaments which form the channels for gas flow are not stable, and that the flow is intermittent. Visual observations of the flow behaviour in micromodels have confirmed this. As a result, the effective total area for flow at any particular gas saturation is substantially reduced, thus reducing the permeability to the gas. New algorithms need to be introduced into the network models for estimating relative permeabilities in these situations before they can be used to represent the cyclical nature of filament rupture and reformation.
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The Cretaceous post-rift basin configuration of the northern North Sea
More LessThe present analysis suggests that three stages can be identified in the post-rift Cretaceous development of the northern North Sea, namely the incipient (Ryazanian–latest Albian), the middle (Cenomanian–late Turonian) and the mature (early Coniacian–early Palaeocene). The transition from syn-to post-rift configuration was strongly diachronous, suggesting that the thermal state of the system was not homogeneous at the onset of the post-rift stage. This is supported by observed differences between the early post-rift subsidence histories of the southern Viking Graben, the Stord Basin and the Sogn Graben.
The incipient post-rift stage was characterized by diverse subsidence. The major structural features inherited from the syn-rift basin (e.g. crests of rotated fault blocks, relay ramps and sub-platforms) had a strong influence on the basin configuration and, therefore, the sediment distribution. In the middle stage the internal basin relief became gradually drowned by sediments. This is typical for basins where sediment supply outpaces or balances subsidence, as was the case in the northern North Sea. Thus, the influence of the syn-rift basin topography become subordinate to the subsidence pattern which was determined by the crustal thinning profile which, in turn, relies on thermal contraction and isostatic/elastic response to sediment loading. The mature post-rift stage was characterized by the evolution into a wide, saucer-shaped basin where the syn-rift features finally became erased. Since thermal equilibrium was reached at this stage, subsidence ceased, and the pattern of basin filling became, to a larger degree, dependent on extra-basinal processes. This simple pattern was influenced by the structural inhomogeneity of the basin. This inhomogeneity may have included the graben units, in turn related to contrasting geometries of the lithospheric structure.
The incipient stage of post-rift development was halted by relative uplift/deceleration of subsidence, locally corresponding to 200 m. This is ascribed to a hitherto undescribed thermo-tectonic event. The mechanism of this event is not yet known.
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Underground gas storage: estimating gas column height and saturation with time lapse seismic
Authors Marie-Hélène Dumont, Cédric Fayemendy, Jean-Luc Mari and Frédéric HuguetSeismic monitoring is often used to check hydrocarbon movements during production. On the site of Céré-la-Ronde, an underground water-bearing gas storage facility developed by Gaz de France, a methodology has been implemented for estimating gas column height and saturation with time lapse seismic. The methodology is based on the Gassmann model, on the measurement of time-shifts and on the computation of a specific seismic function. The time-shifts obtained by cross-correlation techniques are used to derive the residual time-shift Δt induced by the presence of gas within the reservoir. A specific function is used to estimate both the gas bubble extension and the gas time thickness H t. It is shown that knowledge of H t and Δt and the use of a Gassmann model can lead to an estimation of the gas saturation. The methodology has been applied successfully on conventional seismic profiles as well as on vertical seismic profiles (VSP). The results obtained with seismic data are in good agreement with those obtained by logging (sonic and neutron logs) but with a lateral investigation, which is much larger than the one given by logging techniques. In our field example, the gas anomaly has been checked over a distance of 300 m with VSP data and over 2 km with surface seismic data.
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Outcrop-based stochastic modelling of turbidite amalgamation and its effects on hydrocarbon recovery
Authors Karl D. Stephen, Julian D. Clark and Andy R. GardinerIn sandstone-dominated successions of sheet-like turbidites, erosion of thin shale horizons during deposition of the overlying turbidite may lead locally to vertical amalgamation of sandstone beds, resulting in discontinuous thin fine-grained beds or, in the extreme case, thoroughly amalgamated sandstone. Measurements of discontinuous shale lengths from very well exposed turbidite successions have enabled the development of a mixed rule-based/stochastic model for the erosion of shales. Monte Carlo realizations of 2D cross-sections were used to examine the effects of shale discontinuities on both single-and two-phase flow, at the genetic sedimentary unit scale. Results demonstrate that the flow is strongly dependent on the balance of viscous, capillary and gravity forces, which can vary according to the distribution of amalgamation surfaces. The single-phase upscaled ratio of horizontal to vertical permeability and the fraction of mobile oil recovered can be related to the fraction of shale removed (amalgamation ratio) by log-linear and linear relationships respectively.
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Stress orientation, pore pressure and least principal stress in the Norwegian sector of the North Sea
Authors Balz Grollimund, Mark D. Zoback, David J. Wiprut and Linn ArnesenWe have compiled data on stress orientation, pore pressure and least principal stress from over 300 wells in the Norwegian sector of the North Sea. Well-defined regional variations are observed in all three parameters. Incorporation of precise stress orientation data from drilling-induced tensile borehole wall fractures shows that the orientation of maximum horizontal stress is approximately E–W between 60°N and 62°N but tends to be NNW–SSE south of 58°N, similar to the average stress direction seen throughout Great Britain and continental NW Europe. We believe this rotation is due to the superposition of plate-driving stresses with those associated with lithospheric flexure caused by deglaciation. Regional variations of the magnitude of the least principal stress and pore pressure also appear to support the hypothesis that the stress field in this region has been strongly affected by deglaciation.
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Regression analysis and C7+ description for accurate PVT data calculations with equations of state
Authors Dan Vladimir Nichita, Florea Minescu and I.o.n. CretuSimulation of improved recovery processes from gas condensate and volatile oil reservoirs is significantly affected by the match of experimental PVT data. Therefore, a proper characterization of the mixture composition and tuning of the equation of state used are crucial for the accuracy of the reservoir model. This paper presents an efficient method for phase behaviour matching by non-linear regression. The constraints introduced by the boundaries of the regression variables are eliminated by a suitable change of variables. This leads to an unconstrained optimization problem, solved by an original implementation of the Levenberg–Marquardt algorithm. The C7+ fraction is described by a continuous (semi-infinite or truncated) distribution function. A new, rigorous generalized quadrature method is developed for the characterization of the continuous portion of the mixture, which can be applied to any distribution function.
The regression was applied to PVT data for several gas-condensate, including near-critical, and volatile oil systems subjected to different types of expansion and swelling tests, as well as multistage separation processes. The calculated results indicate very good agreement with experimental values. The regression algorithm proves to be robust and efficient.
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Geochemistry and thermal maturation of Triassic to Eocene source rocks in the Central Taurus Belt, SW Turkey
Authors A. Sari, N. Sonel and M. AlbayrakTriassic–Middle Eocene sedimentary sequences in the Central Taurids contain sufficient organic matter to constitute potential source rocks. Geochemical data are used to examine the amount, type and maturation of organic matter and the hydrocarbon potentials of the Triassic Tarasci Fm Limestone, the Late Jurassic–Early Cretaceous Akkuyu Fm limestones and shales and the Middle Eocene Gumusdamla Fm shales. During the extensive Senonian and Lutetian horizontal movements, sub-thrust units of these formations attained higher maturity values in the north (Seydisehir) than in the south (Akkuyu) of the study area. The TOC, S2, and HI values decrease with increasing thermal maturity (365–569°C). Therefore, the geochemical data indicate that the formations are gas and oil source rocks and may produce gas with some oil.
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Isotope geochemistry of oils from fields and mud volcanoes in the South Caspian Basin, Azerbaijan
Authors Ibragim S. Guliyev, Akper A. Feizulayev and Dadash A. HuseynovThis study is based on the isotope-geochemical characteristics of oils from 53 fields in the South Caspian Basin – from Upper Cretaceous, Eocene, Oligocene–Lower Miocene (Maykop), Middle and the Upper Miocene (Diatom) and Pliocene. The isotopic composition of carbon (δ13C) allows two main groups of oils to be identified: (1) isotopically heavy and (2) isotopically light oils. The first group includes oils assumed to be generated by Upper Cretaceous, Eocene and Oligocene–Lower Miocene sources. The second group consists of oils assumed to be generated by Diatom (Middle and Upper Miocene) sources. Isotope-geochemical and biomarker parameters demonstrated that oils in the Pliocene reservoirs are not syngenetic to their enclosing deposits. The isotopic composition of carbon in oils and hydrocarbon gases in mud volcanoes and fields and the biomarker parameters of oils allow several isolated stratigraphic oil- and gas-producing complexes (source rocks) in the Mesozoic, Palaeogene–Lower Miocene and Middle–Upper Miocene to be postulated. Oils in the Pliocene reservoirs and in mud volcanoes consist of mixed oils generated by the Pre-Diatom and Diatom deposits and of oils from only one of the above-mentioned complexes.
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Permeability prediction using stress sensitive petrophysical properties
Authors C. Jones, J. M. Somerville, B. G. D. Smart, O. Kirstetter, S. A. Hamilton and K. P. EdlmannThe correlation of stress sensitivity to various petrophysical parameters was studied by analysis of experimental results from a range of sandstone core plugs tested hydrostatically at room temperature. The parameters measured were: compressional wave velocity, porosity, permeability and electrical resistivity. More detailed information on the effects of sorting and grain size distributions was obtained from experiments on artificial, unconsolidated sandstone cores. The measurements showed a high degree of stress sensitivity, which was different for each core but, broadly, could be classified as either high or low stress sensitivity. Cores from the high permeability clean sand were less stress sensitive than the cores from the low permeability coarsening-upwards sequence and the petrophysical values when combined into a synthetic log distinguished between the two lithologies. The results were compared to the predictions of a simple asperity deformation model. The experimental results and the model suggested a possible logging strategy to deduce permeability, by varying wellbore pressure.
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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)