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  Subjects -> EARTH SCIENCES (Total: 654 journals)
    - EARTH SCIENCES (468 journals)
    - GEOLOGY (73 journals)
    - GEOPHYSICS (28 journals)
    - HYDROLOGY (22 journals)
    - OCEANOGRAPHY (63 journals)

EARTH SCIENCES (468 journals)

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Journal Cover Petroleum Geoscience
  [SJR: 0.604]   [H-I: 41]   [6 followers]  Follow
    
   Hybrid Journal Hybrid journal (It can contain Open Access articles)
   ISSN (Print) 1354-0793 - ISSN (Online) 2041-496X
   Published by Geological Society of London Homepage  [10 journals]
  • The impact of fine-scale reservoir geometries on streamline flow patterns
           in submarine lobe deposits using outcrop analogues from the Karoo Basin
    • Authors: Hofstra, M; Ponten, A. S. M, Peakall, J, Flint, S. S, Nair, K. N, Hodgson, D. M.
      Pages: 159 - 176
      Abstract: Improved prediction of the recovery of oil-in-place in basin-floor fan reservoirs requires accurate characterization and modelling of multiscale heterogeneities. The use of outcrop analogues is a key tool to augment this process by documenting and quantifying sedimentary architecture, hierarchy and sedimentary facies relationships. A 3D geological modelling workflow is presented that tests the impact of fine-scale heterogeneities within basin-floor lobe complexes on reservoir connectivity. Construction of geological models of a basin-floor lobe complex allows realistic depositional architecture and facies distributions to be captured. In addition, detailed models are constructed from channelized areas within a basin-floor lobe complex. Petrophysical modelling and streamline analysis are employed to test the impact on reservoir connectivity between lobe models with: (i) vertically stacked facies with coarsening- and thickening-upwards trends in all locations; and (ii) lateral facies changes with dimensions and distributions constrained from outcrop data. The findings show that differences in facies architecture and, in particular, lobe-on-lobe amalgamation have a significant impact on connectivity and macroscopic sweep efficiency, which influence the production results. Channelized lobe areas are less predictable reservoir targets owing to uncertainties associated with channel-fill heterogeneities. The use of deterministic sedimentary architecture concepts and facies relationships have proven vital in the accurate modelling of reservoir heterogeneities.
      PubDate: 2017-04-28T07:08:17-07:00
      DOI: 10.1144/petgeo2016-087
      Issue No: Vol. 23, No. 2 (2017)
       
  • Integration of facies architecture, ooid granulometry and morphology for
           prediction of reservoir quality, Lower Triassic Khuff Formation, Saudi
           Arabia
    • Authors: Eltom, H. A; Abdullatif, O. M, Babalola, L. O, Bashari, M. A, Yassin, M, Osman, M. S, Abdulraziq, A. M.
      Pages: 177 - 189
      Abstract: Prediction of the reservoir quality of oolitic carbonates is one of the main challenges for petroleum geology due to the inherited heterogeneity in pore systems. This study investigated and characterized the sedimentological, stratigraphic, morphological and granulometric data of oolitic outcrop strata of the Khartam Member of the Khuff Formation in Saudi Arabia, including the giant hydrocarbon reservoirs (Khuff reservoirs), and the results have implications for exploration and development. Linking ooid morphology to sequence stratigraphy revealed that the distribution of the oolitic beds and their pore systems are mainly controlled by stratigraphic position, morphology (controlled by primary mineralogy) and grain size. The systematic distribution of ooids with distinct original mineral compositions allows for the prediction of the porosity distribution and occurrence within analogous reservoirs. The ooids in the studied interval were aragonitic (lower interval), bimineralic (middle interval) and aragonitic (upper interval). Linking ooid grain size with depositional environments indicated that the ooid grain size increases with water energy and follows the upwards-shallowing pattern of the studied succession. These results can be used to improve the understanding and prediction of the reservoir quality of oolitic carbonates.
      PubDate: 2017-04-28T07:08:17-07:00
      DOI: 10.1144/petgeo2015-071
      Issue No: Vol. 23, No. 2 (2017)
       
  • Depositional environment and age determination of oils and condensates
           from the Barents Sea
    • Authors: Lerch, B; Karlsen, D. A, Seland, R, Backer-Owe, K.
      Pages: 190 - 209
      Abstract: The Barents Sea hosts multiple source rocks from Palaeozoic to Cretaceous age. Attempts in the past to link individual oil and condensates directly to one type of source rock have often been complicated due to ‘blended-oil’ signatures. As a result of uplift, remigration, alteration and mixing of petroleums, deconvolution of primary petroleum signatures in terms of maturity, age and depositional environment is generally complicated. In this paper, we use 13C isotopes, and age- and source-related biomarkers to line out the main basin-scale trends concerning the depositional environments and source-rock ages, as well as the type of organic matter input that constitutes the inferred source-rock kerogen. Multivariate statistical analysis was applied as an auxillary tool to suggest petroleum families. Results classify the petroleums into four families: (1) Permian–Triassic-sourced petroleums; (2) Carboniferous-sourced petroleums; (3) Jurassic-sourced petroleums; and (4) phase-fractionated condensates charged from late mature Triassic–Jurassic source rocks. The inferred palaeo-environments for the petroleums cover marine, transitional and terrestrial depositional environments, and display geological variations that prevailed during Permian–Jurassic times. Isotope signatures and age-specific parameters suggest that many oils in the region should be considered as blends or mixtures derived from more than one source rock.
      PubDate: 2017-04-28T07:08:17-07:00
      DOI: 10.1144/petgeo2016-039
      Issue No: Vol. 23, No. 2 (2017)
       
  • History-matching surface-based property models using the ensemble Kalman
           filter
    • Authors: Trani, M; Graham, G. H.
      Pages: 210 - 222
      Abstract: Hydrocarbon reservoirs often contain thin and irregularly shaped low-permeability heterogeneities at the interface between sedimentary bodies that can act as barriers or baffles where they are aligned perpendicular to the flow. These heterogeneities are often not explicitly captured in simulation models because they occur over lengthscales smaller than a single simulation grid block and, as such, are ubiquitously captured in flow simulations using transmissibility multipliers. This parameterization implies that the properties of the fine-scale heterogeneities are a direct function of the properties in the adjacent grid cells. A new methodology is proposed where fine-scale heterogeneities are modelled using properties attached to surfaces and updated independently from other uncertain reservoir properties present during assisted history matching. This method is validated via a synthetic reservoir simulation model, using the ensemble Kalman filter to assimilate production history. The update of geometrical and petrophysical parameters related to fine-scale heterogeneity improves the history match and production forecast in comparison to traditional implicit techniques that do not honour the characteristics of the heterogeneity. The results indicate that, for history matching, it can be important to capture fine-scale heterogeneities independently from other uncertain reservoir properties even if the fine-scale heterogeneities do not exert a large control on reservoir response.
      PubDate: 2017-04-28T07:08:17-07:00
      DOI: 10.1144/petgeo2016-045
      Issue No: Vol. 23, No. 2 (2017)
       
  • Fluid-flow effects of compartmentalized distribution of compaction bands
           in an aeolian sandstone in three dimensions
    • Authors: Deng, S; Jiang, R, Karimi-Fard, M, Aydin, A.
      Pages: 223 - 230
      Abstract: It is well established that the depositional architecture of dunes (cross-bed orientations and dune boundaries) controls the formation and orientation of compaction bands (CBs) in three dimensions, resulting in a compartmentalized distribution of low-angle bed-parallel CBs and high-angle CBs in the Jurassic aeolian Aztec Sandstone, exposed in the Valley of Fire State Park, Nevada, USA. In this study, we used two idealized configurations to represent the characteristic compartmentalization of CBs in three dimensions and performed flow computations to investigate the fluid-flow effects of these configurations. The results suggest that the upscaled permeability of the compartmentalized compaction-band arrays is influenced significantly by the permeability of the compaction-band sets and their orientations and distributions. In particular, in Configuration A, which represents a combination of both the high-angle and bed-parallel domains, upscaled permeability in the direction normal to the dune trend is controlled primarily by the high-angle CB domain. In contrast, in Configuration B, in which the high-angle CB domain is distributed within a limited portion, upscaled permeability in the direction normal to the dune trend is controlled by both the high-angle CB domain and the bed-parallel CB domain. The upscaled permeability in the direction parallel to the dune trend in Configuration A is controlled by both high-angle CBs and bed-parallel CBs, but in Configuration B it is controlled mainly by bed-parallel CBs. In comparison, in both configurations A and B, upscaled permeability in the vertical direction is controlled primarily by the bed-parallel CB domain.The orientation of the major permeability component in both configurations A and B remains almost unaffected by the variation in permeability of CB sets, presumably because the preferred flow path crosses a minimum number of CBs. In contrast, the plunges of the minor permeability component changes significantly in Configuration A, but remains nearly the same in Configuration B. This suggests that the interplay between the spatial distributions of CB sets and their permeability exerts significant influence on the orientation of the minor permeability component in Configuration A, whereas the permeability of bed-parallel CBs has dominant control on the minor permeability component in Configuration B. The difference between the magnitudes of the major principal permeability component and the minor principal permeability component (permeability anisotropy) is about a factor of 2.5, 2.2 and 1.9 in Configuration A for cases 1, 2 and 3, respectively, and about a factor of 5.1, 3.4 and 1.3 in Configuration B for cases 1, 2 and 3, respectively. The parametric study implies that the range of potential variations in the permeability values in flow models would generally yield similar results for the major permeability component, but may yield different results for the minor permeability component.The results presented in this study clearly demonstrate that the compartmentalized distribution of CBs exerts strong influences on fluid flow through aeolian sandstone.
      PubDate: 2017-04-28T07:08:17-07:00
      DOI: 10.1144/petgeo2016-051
      Issue No: Vol. 23, No. 2 (2017)
       
  • Causes and mitigation strategies of surface hydrocarbon leaks at heavy-oil
           fields: examples from Alberta and California
    • Authors: Schultz R. A.
      Pages: 231 - 237
      Abstract: Identification and mitigation of leaks of subsurface fluids such as hydrocarbons at many heavy-oil fields is a first-order concern to operating companies, their regulators and the public. A variety of leaks have been documented at heavy-oil fields in Alberta (Canada) and California (USA). Although the petroleum geology and tectonic framework of fields in these areas differ significantly, production-related uplift of overburden and dilation of pre-existing fractures due to cyclic steam injection are likely to have facilitated the leakage events. As a result, integration of overburden characterization and monitoring with management of steam pressures may provide an effective means of risk mitigation of major leakage events.
      PubDate: 2017-04-28T07:08:17-07:00
      DOI: 10.1144/petgeo2016-070
      Issue No: Vol. 23, No. 2 (2017)
       
  • Quantifying remaining oil saturation using time-lapse seismic amplitude
           changes at fluid contacts
    • Authors: Alvarez, E; MacBeth, C, Brain, J.
      Pages: 238 - 250
      Abstract: Our study shows that time-lapse changes in the amplitude of the seismic reflection at an oil–water contact (OWC) and/or produced OWC can be used to estimate directly the displacement efficiency of water displacing oil, ED, without the need of a rock and fluid physics model. From this value, it is possible to determine the remaining oil saturation if required. A preliminary application is performed using several published literature examples, which are reinterpreted to assess the average ED and ensure that the theory is consistent with expectations. Next, a North Sea field model with a known ED is used to create fluid-flow predictions and the corresponding synthetic time-lapse seismic data. Application to these data again confirms the basic principles of the method and defines the accuracy when applied to 4D seismic data. Finally, an observed 4D seismic dataset from a producing field in the North Sea is analysed. The results suggest a displacement efficiency of between 21 and 65% with an accuracy of 3% due to data non-repeatability (with a NRMS of between 11 and 13%). Given an average irreducible water saturation of 0.32, this calculates the remaining oil saturations at between 24 and 53% for this field. A prerequisite for use of the proposed OWC approach is that a discrete contact be interpreted on either the 3D or 4D seismic datasets. Therefore, successful application of this technique requires moderate- to high-quality seismic data and a fairly thick reservoir sequence without significant structural complexity.
      PubDate: 2017-04-28T07:08:17-07:00
      DOI: 10.1144/petgeo2016-037
      Issue No: Vol. 23, No. 2 (2017)
       
  • Coal architecture, high-resolution correlation and connectivity: new
           insights from the Walloon Subgroup in the Surat Basin of SE Queensland,
           Australia
    • Authors: Morris, J. R; Martin, M. A.
      Pages: 251 - 261
      Abstract: The Middle Jurassic (Aalenian–Oxfordian) Walloon Coal Measures are the focus of major coal seam gas projects in the Surat Basin, SE Australia. The ever-growing abundance of well data linked with ongoing coal seam gas exploitation has provided an opportunity to investigate coal body lateral extents and their associated geometries. From 120 wells over a 67.4 km2 area, 25 coal horizons were correlated establishing a local coal seam area–thickness relationship. Individual plies (coal beds) average less than 30 cm and seams reach up to 10 m thick. In this heterogeneous succession, it is evident that coal correlation does not necessarily equate to coal continuity/connectivity as coal quality locally degrades from coal- to clay-rich facies. During a QGC Pty Ltd gas storage pilot test, offset well pressure response to gas injection provided evidence for coal connectivity and local faulting. By studying the relationships of the coals and interrelated facies, fluctuations in field-scale (local) accommodation space generation can be recognized. These intuitively convey information about the scale of the coal bodies, their possible correlatability and, ultimately, their connectivity. The presented methodology – specifically, the generation of areal extent v. thickness graphs and maps of coal heterogeneity – could be carried out in other basins to better understand the variability in coal body lateral extent, geometry and connectivity (connected permeability). In the context of this coal seam gas project, our workflow can be a useful tool for static reservoir characterization and selection of optimal well spacing; suggestions that it may also be useful for dynamic characterization will require further studies to assess.
      PubDate: 2017-04-28T07:08:17-07:00
      DOI: 10.1144/petgeo2016-028
      Issue No: Vol. 23, No. 2 (2017)
       
  • Softening of organic matter in shales at reservoir temperatures
    • Authors: Emmanuel, S; Eliyahu, M, Day-Stirrat, R. J, Hofmann, R, Macaulay, C. I.
      Pages: 262 - 269
      Abstract: The elastic modulus of organic matter can strongly influence the mechanical behaviour of source rocks. Although recent advances have shed crucial light on the mechanical properties of natural organic matter under ambient conditions, the elastic properties of kerogen and bitumen at reservoir temperatures remain poorly constrained. In this paper, we use a novel atomic force microscope technique to measure the changes to organic matter during the heating of an organic-rich shale. Our measurements show that bitumen becomes more compliant with heating and in an experiment during which the temperature was increased from 25 to 225°C, the reduced elastic modulus dropped from 6.3 to 0.8 GPa. In contrast to bitumen, we were unable to discern any significant changes to the elastic modulus of kerogen with increasing temperature. Our results suggest that the temperature dependence of the elastic properties could be used as an additional method to differentiate between bitumen and kerogen in shales. Moreover, our analysis indicates that temperature should be taken into account when modelling the elastic properties of bitumen under reservoir conditions.
      PubDate: 2017-04-28T07:08:17-07:00
      DOI: 10.1144/petgeo2016-035
      Issue No: Vol. 23, No. 2 (2017)
       
  • Data-driven surrogates for rapid simulation and optimization of WAG
           injection in fractured carbonate reservoirs
    • Authors: Agada, S; Geiger, S, Elsheikh, A, Oladyshkin, S.
      Pages: 270 - 283
      Abstract: Conventional simulation of fractured carbonate reservoirs is computationally expensive because of the multiscale heterogeneities and fracture–matrix transfer mechanisms that must be taken into account using numerical transfer functions and/or detailed models with a large number of simulation grid cells. The computational requirement increases significantly when multiple simulation runs are required for sensitivity analysis, uncertainty quantification and optimization. This can be prohibitive, especially for giant carbonate reservoirs. Yet, sensitivity analysis, uncertainty quantification and optimization are particularly important to analyse, determine and rank the impact of geological and engineering parameters on the economics and sustainability of different Enhanced Oil Recovery (EOR) techniques.We use experimental design to set up multiple simulations of a high-resolution model of a Jurassic carbonate ramp, which is an analogue for the highly prolific reservoirs of the Arab D Formation in Qatar. We consider CO2 water-alternating-gas (WAG) injection, which is a successful EOR method for carbonate reservoirs. The simulations are employed as a basis for generating data-driven surrogate models using polynomial regression and polynomial chaos expansion. Furthermore, the surrogates are validated by comparing surrogate predictions with results from numerical simulation and estimating goodness-of-fit measures.In the current work, parameter uncertainties affecting WAG modelling in fractured carbonates are evaluated, including fracture network properties, wettability and fault transmissibility. The results enable us to adequately explore the parameter space, and to quantify and rank the interrelated effect of uncertain model parameters on CO2 WAG efficiency. The results highlight the first-order impact of the fracture network properties and wettability on hydrocarbon recovery and CO2 utilization during WAG injection. In addition, the surrogate models enable us to calculate quick estimates of probabilistic uncertainty and to rapidly optimize WAG injection, while achieving significant computational speed-up compared with the conventional simulation framework.
      PubDate: 2017-04-28T07:08:17-07:00
      DOI: 10.1144/petgeo2016-068
      Issue No: Vol. 23, No. 2 (2017)
       
 
 
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