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Akihisa, Kunio (Japan Oil, Gas and Metals National Corporation) | Knapp, Levi (Japan Oil, Gas and Metals National Corporation) | Uchida, Shinnosuke (Japan Oil, Gas and Metals National Corporation) | Shimokawara, Mai (Japan Oil, Gas and Metals National Corporation) | Akita, Yasuyuki (Japan Oil, Gas and Metals National Corporation) | Wood, James M. (Encana Corporation) | Ardakani, Omid Haeri (Natural Resources Canada - Geological Survey of Canada) | Sanei, Hamed (Natural Resources Canada - Geological Survey of Canada)
This study was carried out to investigate the relationship between rock properties and gas wetness, in order to better identify and characterize sweet spot areas. The study was conducted in two horizontal wells penetrating across a local CGR anomaly in the Montney Formation silty sand tight gas reservoir.
First, the relation between mud gas components and CGR distribution was surveyed to confirm the applicability of mud gas wetness as a proxy for CGR of initial production gas. Second, permeability indices of drill cuttings were analyzed by laboratory NMR measurements and the relationship of permeability to solid bitumen saturation was examined. In addition, MICP-derived properties and QEMSCAN mineralogy are discussed. The results were examined with respect to changes in mud gas wetness in the surveyed wells.
In the study area, a strong positive correlation was found between produced gas CGR and mud gas wetness ratio. Mud gas wetness was negatively correlated to cuttings permeability and permeability was negatively correlated to bitumen saturation, suggesting methane migration occurred along high permeability, low bitumen saturation pathways. Based on these observations, both mud gas wetness and cuttings permeability indices were confirmed to be effective for detecting liquids-rich areas in under-developed areas.
The liquid content of produced hydrocarbon gas (or condensate gas ratio, CGR) is an important factor for detecting sweet spot areas in tight gas reservoirs.
The Lower Triassic Montney Formation is currently a prolific gas producer in the Western Canadian Sedimentary Basin and is projected to continue as a major energy resource in the future. Gaseous hydrocarbons are said to be originally accumulated as oil and then thermally transformed to gas during further burial of the reservoir horizon (Sanei et al., 2013).
Goodarzi, Fariborz (FG&Partners Ltd, 219 Hawkside Mews, NW, Calgary, Alberta, Canada, T3G 3J4) | Ardakani, Omid Haeri (Geological Survey of Canada - Calgary) | Pedersen, Per-Kent (Department of Geoscience, University of Calgary, Calgary, Alberta, Canada, T2N 1N4) | Sanei, Hamed (Geological Survey of Canada - Calgary, Department of Geoscience, University of Calgary, Calgary, Alberta, Canada, T2N 1N4)
Canada has vast oil shale resources (estimated at 180 billion barrels proved recoverable oil shale reserve) similar to the estimated Canadian oil reserve of 179 billion barrels. These deposits consist of various oil shale types deposited in terrestrial, lake, and marine environments. These Canadian oil shale deposits are assessed under auspices of Canada/Israel Industrial Research and Development Program and Geological Survey of Canada for their possible use for extraction of hydrocarbon. The organic rich oil shale deposit with thickness of 60m are suitable for this purpose. This paper reviews the oil shale deposits of Arctic Canada from Ordovician to Carboniferous age. Ordovician shale of Baffin Island, Southampton Island, and Akpatok Islands consist of organic lean, calcareous deposits with variable thickness. The Devonian cannel and canneloid deposit of Melville Island, Arctic Canada are liptinitic rich, but are thin and therefore have low mining potential. The Lower Carboniferous Emma Fjord oil shale deposit is the only promising deposit for in-situ extraction of hydrocarbon from Arctic Canada at present.