Reservoir characterization and multiscale heterogeneity modeling of inclined heterolithic strata for bitumen-production forecasting, McMurray Formation, Corner, Alberta, Canada

A. W. Martinius*, M. Fustic, D. L. Garner, B. V.J. Jablonski, R. S. Strobl, J. A. MacEachern, S. E. Dashtgard

*Corresponding author for this work

Research output: Contribution to journalArticleScientificpeer-review

42 Citations (Scopus)

Abstract

Bitumen reservoirs dominated by inclined heterolithic stratification (IHS) formed in large point bars of the Aptian (Lower Cretaceous) McMurray Formation in the northwestern part of the Corner oil sand lease (Alberta, Canada) were investigated to establish their value. Hybrid production technologies were applied to thin pay, typified by homogeneous reservoir sand units thicker than 5 m at the base overlain by IHS (so-called ‘thin pay’), as well as IHS-dominated reservoirs in which the IHS extends down to the base of the reservoir. High-resolution seismic data and well data (core, dipmeter, HMI) were used to map four facies associations, comprising a total of 16 sedimentary facies, as well as various fluid contacts to assist in reservoir characterization and risk assessment. The conceptual depositional model was based on the analysis of the migration and re-orientation history of the IHS-dominated point bars reflecting lateral accretion, downstream migration, rotation and relocation of the bars. Multiple reactivation events, which control the heterolithic nature and reservoir quality of the deposits, create developable “pools”. Seven electrofacies (with generally increasing mud content) were defined and used as input to construct vertical proportion curves that relate the electrofacies distribution to geomodel statistics in the main reservoir zone. At the electrofacies scale, numerical effective porosity-permeability models were created using micromodeling and minimodeling concepts. The geometrical shape of the electrofacies in the geomodel was investigated using non-stationary Truncated Gaussian (TG) facies simulation to enforce the stacking patterns. Each geomodel area was characterized using one variogram to efficiently compute the horizontal and vertical variogram ranges and average azimuths. Sequential Gaussian simulation (SGS) was used to map the distribution of key petrophysical parameters such as effective porosity, effective water saturation and Vshale. Empirically derived saturation versus elevation profiles for each electrofacies were included in the modeling. The distributions from the micro- and mini-modeling were introduced using probability field (P-field) simulation. To investigate the amount of connected resources (the degree of connectivity of good sand as well as IHS) were extractable flow simulation studies were performed at the pad scale. In preparation for reservoir simulation, connectivity calculations within the local pool geomodel realizations were tailored for the reservoir heterogeneities (i.e., IHS) that are expected to have a major impact on the specific thermal and gravity drainage extraction processes. The geomodel realizations were ranked by expected pseudo-dynamic behaviour with connected exploitable pay as a critical parameter.

Original languageEnglish
Pages (from-to)336-361
Number of pages26
JournalMarine and Petroleum Geology
Volume82
DOIs
Publication statusPublished - 1 Apr 2017

Keywords

  • Bitumen pool
  • Inclined heterolithic stratification
  • McMurray Formation
  • Point bar geomodel
  • Reservoir characterization

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