for Journals by Title or ISSN
for Articles by Keywords
  Subjects -> EARTH SCIENCES (Total: 638 journals)
    - EARTH SCIENCES (463 journals)
    - GEOLOGY (68 journals)
    - GEOPHYSICS (27 journals)
    - HYDROLOGY (21 journals)
    - OCEANOGRAPHY (59 journals)

EARTH SCIENCES (463 journals)            First | 1 2 3 4 5     

The end of the list has been reached. Please navigate to previous pages.

  First | 1 2 3 4 5     

Journal Cover   Petroleum Geoscience
  [SJR: 0.962]   [H-I: 33]   [8 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]
  • Budge-Fudge method of pore-pressure estimation from wireline logs with
           application to Cretaceous mudstones at Haltenbanken
    • Authors: Sargent, C; Goulty, N. R, Cicchino, A. M. P, Ramdhan, A. M.
      Pages: 219 - 232
      Abstract: Using wireline logs to estimate pore pressure in mudstones at the chemical compaction stage is not straightforward because clay diagenesis proceeds independently of effective stress, and neither density nor velocity is uniquely related to the maximum effective stress experienced by the mudstones. We propose the Budge–Fudge method, in which we assume there is a unique trend on the sonic–density cross-plot for mudstones at the chemical compaction stage that have not been unloaded. In addition to the sonic–density chemical compaction trend, an initial guestimate of maximum effective stress previously experienced by the mudstones is required. Additional overpressure from unloading processes is then estimated from the sonic log, referenced to the density response. The initial guestimate of maximum effective stress may be adjusted to fit any available measured pressures or pressures estimated from geological knowledge. We have applied the Budge–Fudge method to Cretaceous mudstones at Haltenbanken, and find that estimated pressures match measured pressures and expected pressure–depth profiles. Furthermore, the analysis suggests that the lateral variations in mudstone porosity, previously reported, result from lateral variations in overpressure build-up immediately following rapid burial by glaciogenic sediments; subsequently, overpressures have increased through clay diagenesis and equilibrated laterally across the area.
      PubDate: 2015-10-16T09:36:57-07:00
      DOI: 10.1144/petgeo2014-088
      Issue No: Vol. 21, No. 4 (2015)
  • Stochastic structural modelling in sparse data situations
    • Authors: Cherpeau, N; Caumon, G.
      Pages: 233 - 247
      Abstract: This paper introduces a stochastic structural modelling method that honours interpretations of both faults and stratigraphic horizons on maps and cross-sections in conjunction with prior information, such as fault orientation and statistical size–displacement relationships. The generated stochastic models sample not only geometric uncertainty but also topological uncertainty about the fault network. Faults are simulated sequentially; at each step, fault traces are randomly chosen to constrain a fault surface in order to obtain consistent fault geometry and displacement profile. For each simulated fault network, stratigraphic modelling is performed to honour interpreted horizons using an implicit approach. Geometrical uncertainty on stratigraphic horizons can then be simulated by adding a correlated random noise to the stratigraphic scalar field. This strategy automatically maintains the continuity between faults and horizons. The method is applied to a Middle East field where stochastic structural models are generated from interpreted two-dimensional (2D) seismic lines, first by representing only stratigraphic uncertainty and then by adding uncertainty about the fault network. These two scenarios are compared in terms of gross rock volume (GRV) uncertainty and show a significant increase in GRV uncertainty when fault uncertainties are considered. This underlines the key role of faults in resource estimation uncertainties and advocates a more systematic fault uncertainty consideration in subsurface studies, especially in settings in which the data are sparse.
      PubDate: 2015-10-16T09:36:57-07:00
      DOI: 10.1144/petgeo2013-030
      Issue No: Vol. 21, No. 4 (2015)
  • Object-based modelling of avulsion-generated sandbody distributions and
           connectivity in a fluvial reservoir analogue of low to moderate
           net-to-gross ratio
    • Authors: Villamizar, C. A; Hampson, G. J, Flood, Y. S, Fitch, P. J. R.
      Pages: 249 - 270
      Abstract: Data from a large-scale outcrop analogue (Upper Cretaceous Blackhawk Formation, Wasatch Plateau, central Utah, USA) were used to construct three-dimensional, object-based reservoir models of low to moderate net-to-gross (NTG) ratios (11–32%). Two descriptive spatial statistical measures, lacunarity and Ripley’s K function, were used to characterize sandbody distribution patterns in the different models. Lacunarity is sensitive to sandbody abundance and NTG ratio, while Ripley’s K function identifies clustered, random and regular spacing of sandbodies. The object-based modelling algorithm reproduces sandbody dimensions and abundances, but patterns of sandbody distribution generated by river avulsion are poorly replicated because pseudo-well spacing provides only limited constraint on sandbody positions. In common with previous studies, the connected sand fraction in the reservoir models increases with increasing NTG ratio and increasing range of sandbody orientations, but there is significant stochastic variation around both of these trends. In addition, low NTG reservoir models in which sandbodies exhibit strong clustering may also have a low connected sand fraction across the model volume because the sandbody clusters are widely spaced and, thus, tend to be isolated from each other. Consequently, connected sand fraction could be overestimated if avulsion-generated sandbody clusters are not identified and replicated in models of such reservoirs.
      PubDate: 2015-10-16T09:36:57-07:00
      DOI: 10.1144/petgeo2015-004
      Issue No: Vol. 21, No. 4 (2015)
  • Quantitative seismic interpretation using inverse rock physics modelling
    • Authors: Bredesen, K; Jensen, E. H, Johansen, T. A, Avseth, P.
      Pages: 271 - 284
      Abstract: Extracting information about reservoir quality from seismic data is a key challenge in exploration, appraisal and production of hydrocarbons. We demonstrate how to perform quantitative reservoir characterization by using inverse rock physics modelling on seismic inversion data. This allows us to evaluate the non-uniqueness of our predictions. We demonstrate our methodology on a gas–condensate Norwegian Sea field under appraisal and production, and perform reservoir quality predictions along a selected seismic cross-section where we have well control. Even though such a seismic dataset is more uncertain than well log data, which have been used previously in similar analysis, we still achieve reasonable and consistent predictions of reservoir quality.
      PubDate: 2015-10-16T09:36:57-07:00
      DOI: 10.1144/petgeo2015-006
      Issue No: Vol. 21, No. 4 (2015)
  • Magnetotelluric imaging integrated with seismic, gravity, magnetic and
           well-log data for basement and carbonate reservoir mapping in the Sao
           Francisco Basin, Brazil
    • Authors: Solon, F. F; Fontes, S. L, Meju, M. A.
      Pages: 285 - 299
      Abstract: We evaluate the use of the magnetotelluric (MT) method to locate crystalline basement and overlying carbonate reservoir rocks underneath a thick overburden in the São Francisco basin in Brazil. Mapping the complex basement and the carbonate reservoir using seismic reflection is a major problem in hydrocarbon exploration in this intracratonic basin, and it is expected that MT will provide useful complementary information. In the present study, we analysed 31 MT soundings along four survey lines in the central region of the basin. The MT soundings covered a period range of 0.001–100 s, probing the subsurface resistivity structure down to a maximum depth of about 15 km. The MT data were inverted using a regularized two-dimensional (2D) inversion algorithm with a variety of a priori data for comparison. For model appraisal, we analysed well log (gamma ray, deep resistivity and neutron porosity) data as well as seismic, gravity and magnetic profiles coincident with one MT line passing through the well. We found that shallow geological boundaries separating zones of strong resistivity contrasts also coincide with seismic boundaries in the inversion models with or without a priori data. Using gravity data, it was also possible to define the compartmentalized basement in this sector of São Francisco Basin, not clear in the seismic section. However, only by integrating all available information were we able to map the Lagoa do Jacaré and Sete Lagoas carbonate member-formations of the Bambuí Group, which are considered to host both the source and reservoir rocks identified from past exploratory history of this basin. We also imaged a basement structural high with thinned or disrupted conductive cover rocks over a known zone of hydrocarbon microseepage and a buried conductive (source rock?) channel at its NW margin, the trace of which coincides with the present-day River Paracatu along which gas bubbles have been observed. This suggests that MT may be fruitfully integrated with gravity, magnetic and seismic data to study the structural controls on hydrocarbon occurrence in this basin.
      PubDate: 2015-10-16T09:36:57-07:00
      DOI: 10.1144/petgeo2013-013
      Issue No: Vol. 21, No. 4 (2015)
  • Geochemical characterization of oils and their source rocks in the Barmer
           Basin, Rajasthan, India
    • Authors: Farrimond, P; Naidu, B. S, Burley, S. D, Dolson, J, Whiteley, N, Kothari, V.
      Pages: 301 - 321
      Abstract: The Barmer Basin is a failed continental rift of late Cretaceous–Eocene age in Rajasthan, NW India, containing prolific hydrocarbon resources, with 33 discoveries having been made in the last decade. The basin is predominantly oil-prone, although gas discoveries have been made in the deeper parts of the basin. Oils in the Barmer Basin are highly waxy, a result of the lacustrine nature of the source rocks that dominate the sedimentary fill of the basin. Detailed interpretation of the molecular composition of the oils defines three main oil groups that can be related to differing sources. The oils are all distinctively lacustrine in origin, although differing in specific source-facies characteristics. All of the oils are isotopically light, mostly in the –29 to –33 range. Most oils in the northern Barmer Basin (groups 1A and 1B) are interpreted to have been generated from the Late Paleocene Barmer Hill Formation, an excellent oil-prone source rock with predominantly Type I lacustrine algal and bacterial kerogen. Group 2 oils are subordinate in abundance, occurring only in the southern part of the basin, and are interpreted to be at least partly sourced from the overlying Early Eocene Dharvi Dungar Formation, which is characterized by mixed Type I and Type III kerogen, and attains oil maturity only in the southern basin. Group 3 oils are less common, and are of higher maturity than the Group 1 oils, but also appear to have been generated from the Barmer Hill Formation where it was buried more deeply in the central and southern parts of the basin. However, recognition of probable Mesozoic sediments in sub-basins beneath the Tertiary Barmer Basin introduces a further source-rock candidate for the Group 3 oils. A high maturity hydrocarbon charge that is recognized in the gasoline-range hydrocarbons in the Group 2 oils of the southern Barmer Basin may also be from a Mesozoic source rock, or from the Barmer Hill Formation that is much more deeply buried in this part of the basin than in the north, and represents a more mixed oil- and gas-prone source.
      PubDate: 2015-10-16T09:36:57-07:00
      DOI: 10.1144/petgeo2014-075
      Issue No: Vol. 21, No. 4 (2015)
  • Estimating barrier shale extent and optimizing well placement in heavy oil
    • Authors: Lajevardi, S; Babak, O, Deutsch, C. V.
      Pages: 322 - 332
      Abstract: Shale barriers within the bituminous oil sand deposits of the McMurray Formation have a detrimental effect on the steam-assisted gravity-drainage chamber growth and oil recovery. Typically, the non-net shale barrier lateral extents are too small to be detected with a few widely spaced delineation wells. The information on net reservoir and shale interval thicknesses collected from wells, along with a vertical indicator variogram, provide limited information about the horizontal extent and connectivity of these intervals. In this paper, a novel quantitative approach for predicting the lateral extents of the barriers, using thickness information provided by well log data, is proposed. The proposed approach is based on moments of inertia (MOI) applied to the shale objects to determine their effective size. The MOI calculation is aimed to simplify the almost infinite complexity of shale bodies into summary size parameters that can be readily understood and calibrated to production parameters. A case study is presented for optimal well placement accounting for uncertainty in the shale barrier sizes.
      PubDate: 2015-10-16T09:36:57-07:00
      DOI: 10.1144/petgeo2013-039
      Issue No: Vol. 21, No. 4 (2015)
School of Mathematical and Computer Sciences
Heriot-Watt University
Edinburgh, EH14 4AS, UK
Tel: +00 44 (0)131 4513762
Fax: +00 44 (0)131 4513327
About JournalTOCs
News (blog, publications)
JournalTOCs on Twitter   JournalTOCs on Facebook

JournalTOCs © 2009-2015