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- Volume 24, Issue 2, 2018
Petroleum Geoscience - Volume 24, Issue 2, 2018
Volume 24, Issue 2, 2018
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Hormuz salt distribution and influence on structural style in NE Saudi Arabia
More LessThis study uses previously unpublished reflection seismic data and wells to map part of the western margin of the Hormuz salt basin for the first time, and to link Hormuz facies distribution to the evolution of major structures in NE Saudi Arabia. Most of these major structures host giant or supergiant oil fields in Mesozoic reservoirs. This study is based on seismic interpretation of structural style because the Hormuz occurs at up to 10 km or more depth present day and is not penetrated by any wells. In the eastern part of the study area, seismically transparent zones with structural elements diagnostic of salt tectonics pass laterally into layered seismic facies with local clinoform geometries. The transparent facies are interpreted as mobile salt, the layered facies as immobile evaporite basin-margin strata. The layered facies display onlap and fault-bound relationships with older basement domains, and in map view the boundary between layered and transparent seismic facies at the Hormuz level forms embayments and promontories on the west margin of the salt basin. Areas of mobile salt underlie domal and periclinal structures, such as Karan, Hasbah, Dammam and Khursaniyah. These structures display steeply dipping reflections at depth that can be interpreted as salt pillow flanks, with base salt locally interpretable, and have plan-view aspect ratios of 2 or less. Beyond the limits of layered seismic facies, between the embayments and westwards towards the Arabian Shield, seismic and well data indicate that the major structures are not salt cored, including Berri, Manifa, Safaniya, Jauf, Juraybi'at and Haba.
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Evaluating a vintage play fairway exercise using subsequent exploration results: did it work?
Authors Fabio Lottaroli, Jonathan Craig and Andrea CozziThe rediscovery of the regional approach and of play-based evaluation has played a key role in the success of conventional exploration in new plays and frontier basins over the past two decades. In this paper, we compare the results of a vintage (1995) play assessment of onshore Colombia (Upper Magdalena Basin) with the actual results of exploration over the following 20 years, reconstructing the vintage risk assessment and recomputing yet-to-find (YTF) using different methodologies. The overall perception of chance displayed on the vintage play maps proved to be largely correct, with most of the discoveries made over the following 20 years being within the forecasted ‘sweet spots’ and the higher risk areas being confirmed by the subsequent, less successful exploration drilling. In contrast, the YTF calculated in the vintage evaluation was overestimated. Such an overestimation of YTF seems a persistent problem in the exploration and production (E&P) industry. Recreating and analysing the vintage assessment in light of subsequent exploration results highlighted that field size distribution (FSD), the number of future accumulations and the prospect-specific risk evaluation were the main variables responsible for the overestimation of the YTF. Clearly, calculating reliable YTF is only possible with sound geological, exploration and statistical knowledge of the analysed play.
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3D structural and thermal modelling of Mesozoic petroleum systems in the Po Valley Basin, northern Italy
Authors Claudio Turrini, Barbara Bosica, Paul Ryan, Peter Shiner, Olivier Lacombe and François Roure1D and 3D basin modelling was performed to investigate the Mesozoic carbonate petroleum systems of the Po Valley Basin (northern Italy), through integration of a recent 3D structural model of the study area with the distribution of potential Triassic source rocks, rock properties and heat flow models.
Results from standard 1D maturity models show significant overprediction of the thermal maturity of deep Triassic carbonates in the western Po Valley, unless the effect of the substantial overpressure observed in these sequences is incorporated into the model. In order to further test this observation, two thermal scenarios were applied to the Po Valley 3D geo-volume: one based on the actual geological heat flow and a second model based on a reduced heat flow as a proxy for the delaying effect of overpressure on hydrocarbon maturation. The predictions of these two models were then compared with the observed hydrocarbon distribution in the western Po Valley.
Both thermal scenarios are broadly consistent with the observed hydrocarbon distribution at the scale of the basin but, in detail, the overpressure model provides a better match between the predicted charge available from the kitchen area's post-critical moment and observed volumes of hydrocarbons initially in place within the traps, as well as with the observed and predicted hydrocarbon phases, as measured by the gas/oil ratio (GOR) of the fluids. Overpressure probably significantly delayed hydrocarbon maturation in the western domain of the basin, confirming results from previous studies.
Beyond regional implications, and despite its relative simplicity and inherent uncertainties, the adopted approach demonstrates the potential of a consistent 3D integration of the thermostructural history of sedimentary basins to constrain the geometry and structural evolution of hydrocarbon-bearing traps, as well as the generation and migration of hydrocarbons into these traps.
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Integrated Triassic stratigraphy of the greater Culzean area, UK Central North Sea
Authors Christoffer Mouritzen, Matthew A. Farris, Andrew Morton and Susan MatthewsThe Culzean Field, located in UK CNS Block 22/25a between the Lomond Deep and the Heron Cluster, was discovered in 2008 by the 22/25a-9Z well and subsequently appraised by wells 22/25a-10, 22/25a-10Z, 22/25a-10Y and 22/25a-11. The primary reservoir is the Triassic Skagerrak Formation, with a secondary reservoir in the Middle Jurassic Pentland Formation. Total recoverable reserves are estimated to be 250 – 300 MMBOE. One principal challenge concerning the Skagerrak reservoir in Culzean is the stratigraphy, and especially how it relates to adjacent wells in Quadrant 22. Historically, biostratigraphic age determinations of the Skagerrak Formation in Quadrant 22 have been unsuccessful, unlike in Quadrant 30 where biostratigraphic recovery is good and ages are well established. However, good recovery in the Culzean discovery well 22/25a-9Z enabled identification of the Jonathan Mudstone Member, the Joanne Sandstone Member, the Julius Mudstone Member, the Judy Sandstone Member and Marnock Mudstone. The Joanne Sandstone Member and the Jonathan Mudstone Member are therefore more widely distributed in Quadrant 22 than has been hitherto recognized. The Skagerrak Formation in Culzean also has a well-defined heavy mineral stratigraphy, enabling correlation into the adjacent Marnock, Skua, Egret and Heron fields. This correlation shows that the reservoir succession in Egret and Heron is largely equivalent to the Joanne Sandstone Member, whereas Marnock and Skua contain the Judy Sandstone Member overlain by truncated Joanne Sandstone Member and Julius Mudstone Member intervals.
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Two-step wireline log analysis of overpressure in the Bekapai Field, Lower Kutai Basin, Indonesia
Authors Agus M. Ramdhan and Neil R. GoultyAs part of our effort to improve pore-pressure estimation in diagenetically altered mudstones, we have used wireline logs to estimate disequilibrium compaction and unloading contributions to the hard overpressure encountered in the Bekapai Field, Lower Kutai Basin. The maximum vertical effective stress that the overpressured mudstones have experienced is estimated from the density log using Dutta's relationship between vertical effective stress and void ratio. The sonic–density cross-plot is then used to estimate the sonic reference trend: that is, the expected sonic response if the mudstones were currently at maximum vertical effective stress. Finally, comparison of the sonic log with the sonic reference trend gives the unloading contribution to overpressure using Bowers’ unloading relationship between the vertical effective stress and velocity. In spite of poor data quality, fair results were obtained showing a steady increase in disequilibrium compaction overpressure below the top of the sharp pressure ramp. Immediately below the pressure ramp, the unloading contribution to overpressure dominates, with gas generation being the most likely cause. Our interpretation explains the pressure and wireline log data in this deltaic setting satisfactorily, resolving a debate on overpressure-generation mechanisms in the shelfal area of the basin that has been ongoing for 25 years.
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Horizontal variogram inference in the presence of widely spaced well data
Authors Mehdi Rezvandehy and Clayton V. DeutschThe variogram is a key parameter for geostatistical modelling. Inferring a stable variogram model from widely spaced well data is a longstanding challenge due to an often unreliable experimental horizontal variogram. The main aim of this paper is to improve the horizontal variogram inference in the presence of limited data by quantifying variogram uncertainty and reducing this uncertainty with secondary data. A new approach of variogram uncertainty is presented by computing the number of independent variogram pairs (degrees of freedom) for each lag. A methodology to improve the horizontal variogram uncertainty is developed considering the horizontal variogram of the seismic data and the vertical well variogram since these variograms are well defined in most cases. Seismic data provide constraints on the horizontal variogram of the well data. The constraints are inferred from the covariance between the well and seismic data. The vertical variogram of the well data can be scaled to scenarios of the horizontal variogram. Improved horizontal variogram realizations honouring the correlation between lags are attained by merging variogram distributions for each lag distance considering the constraints from the horizontal seismic variogram. A realistic case study is presented.
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Grain and pore microtexture in sandstone sill and depositional sandstone reservoirs: preliminary insights
Authors Feng Wu, Andrew Hurst and Antonio GrippaPetrographical microtextural analysis and conventional core-plug analysis of samples from a depositional sandstone and a sandstone sill are used to compare with similar data derived from micro-CT (MCT) analysis of the same samples. A remarkable richness of information derived from the MCT data identifies isotropic granular and pore fabrics at the micrometre-scale in the sandstone sill that contrast markedly with the laminated fabric in the depositional sandstone. In the sandstone sill, porosity and permeability are more homogenous than in the depositional sandstone, in which lamination creates approaching two-orders of magnitude difference in permeability and enhances horizontal permeability relative to vertical permeability. In the sill, lower pore- and throat-shape factors and larger pore coordinate numbers are present than in the depositional sandstone. Preservation of the isotropic pore and grain structure in the sandstone sill is indicative of significant fluidized flow normal to the fracture margin during emplacement.
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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)