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TitleOrganic petrology and geochemistry of Tournaisian-age Albert Formation oil shales, New Brunswick, Canada
AuthorGoodarzi, F; Haeri-Ardakani, OORCID logo; Gentzis, T; Pedersen, P K
SourceInternational Journal of Coal Geology vol. 205, 2019 p. 43-57,
Alt SeriesNatural Resources Canada, Contribution Series 20180442
PublisherElsevier BV
Mediapaper; on-line; digital
File formatpdf
ProvinceNew Brunswick
NTS21H/10; 21H/11; 21H/12; 21H/13; 21H/14; 21H/15; 21I/02; 21I/03; 21I/04
AreaBoudreau; Taylor Village; Mapleton; Urney
Lat/Long WENS -66.0000 -64.5000 46.2500 45.5000
Subjectsfossil fuels; geochemistry; mineralogy; Lower Carboniferous; Tournaisian; petroleum resources; hydrocarbon potential; hydrocarbon generation; hydrocarbons; oil; bedrock geology; sedimentary rocks; oil shales; shales; bitumen; carbonates; organic geochemistry; microscopic analysis; pyrolysis; mass spectrometer analysis; calcium geochemistry; thorium geochemistry; depositional environment; lacustrine environments; stratification; hydrocarbon migration; organic carbon; isotope ratios; uranium thorium ratios; uranium geochemistry; inclusions; vitrinite reflectance; fluorescence analyses; hydrocarbon maturation; maturation indicators; temperature; hydrogen index; kerogen; thermal maturation; Horton Group; Albert Formation; Frederic Brook Member; Moncton Subbasin; Maritimes Basin; Albert Mines; Antigonish Basin; Rights River Formation; Big Marsh Oil Shale; Phanerozoic; Paleozoic; Carboniferous
Illustrationslocation maps; geoscientific sketch maps; stratigraphic charts; tables; photomicrographs; profiles; plots; diagrams; graphs; spectra
ProgramGeoscience for New Energy Supply (GNES) Shale Reservoir Characterization
Released2019 03 01
AbstractLacustrine oil shale and shale samples of the Tournaisian-age Albert Formation in New Brunswick, Canada, taken from six locations, were analyzed by organic petrology using reflected white and fluorescence light microscopy and by Rock-Eval pyrolysis to determine their depositional environment and hydrocarbon generating potential. Calcium, Th, and Ca contents of the samples were also determined using ICPMS. The results were compared to the Big Marsh lacustrine oil shale of Carboniferous age in Nova Scotia.
Organic matter consists mostly of filamentous alginite, bacterial remains, and matrix bituminite, which fluoresce green to dark-yellow. Organic matter was deposited in a lake basin. The regular layering of algal remains and wrapping around mineral particles indicate deposition in a low energy setting below wave base, which resulted in the stratification of the organic matter and the enclosing mineral matrix. There are also fluorescing to non-fluorescing bitumens present in parts of the Albert oil shale. The bitumens were incorporated as a result of hydrocarbon migration during deposition of the oil shales (the two are considered to be synsedimentary) because the bitumens are part of the regular rock layering and the fact that the organic matter is wrapped around mineral grains. The bitumens in the Albert oil shales consist of fluorescing wurtzilite and nonfluorescing albertite.
The Albert oil shales have lower input of terrestrial sediments containing Th and are carbonate-rich. The variation of Th/U ratio and TOC (wt%) indicates that the Albert oil shales have different mineralogy than those from the Big Marsh ones. There are two types of carbonates particles in the Albert oil shale; a) syngenetic angular particles, which are suspended in the organic matter but may also occur as micrite, and b) rounded to angular and possibly transported particles containing oil inclusions. As a result, variations in Th/U and calcium divided the oil shales into: a low-calcium lacustrine type (which includes the Big Marsh oil shale); the Albert oil shale and shale deposited far from the Albert Mine; and few samples from a deposit close to the Albert Mine that have high calcium content and some of them contained oil inclusions. The higher TOC of samples collected from the bitumen mining area in the Albert Mine is related to bitumen impregnation due to hydrocarbon migration. Variation of HI (mg HC/g/TOC) and authigenic uranium in the Albert oil shale indicates that depositional environment was more anoxic than most of the oil shales in the Big Marsh deposit.
Rock-Eval pyrolysis data and accompanying organic petrology analysis indicate that the samples are mostly immature to marginally mature as indicated by %Ro, ran of 0.60-0.68 and variation in the fluorescence Red/Green and Blue/Green and Blue (R/G, B/G, B) quotients. Variations in maturity indicators (such as HI and Tmax) are caused by other factors, such as quantity of organic matter in the samples. The Hydrogen Index (HI) vs. Tmax plot of the oil shales displays a wide range of HI within a narrow Tmax range of 438-442 °C indicating immature to marginally mature Type I kerogen. There is a slight trend of increasing Tmax into the oil window with increasing HI, likely due to the extreme mass of hydrocarbons in these samples, which requires higher energy to breakdown, rather than burial-related thermal maturity. Maturity of the Albert oil shale increases from east to west within the study area as indicated by the westward increase of all three fluorescent quotients of both filamentous algae and matrix bituminite and in the %Ro. The reflectance of the Albert oil shales, measured on vitrinite, is mostly suppressed compared to the nearby Mapleton organic-lean shale in New Brunswick. There is also a correlation between HI and %Ro, ran in the oil shale samples studied; the higher is the HI, the lower is the %Ro.

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