EFFECTS OF MATURATION ON HYDROCARBON RECOVERIES

FROM CANADIAN OIL SHALE DEPOSITS

G. Macauley1, L.R. Snowdon2, and W.D.Kalkreuth3

Abstract

Classification and maturation levels have been established for selected Canadian oil shales by geochemicalRock-Eval pyrolysis and by petrological maceral identification, fluorescence and vitrinite reflectancetechniques. These results are compared to hydrocarbon recovery potentials established by Rock-Eval pyrolysisand Fischer Assays and also to hydrocarbon quality defined by specific gravity determinations and by gaschromatography of both thermal and solvent extract fractions. Oil qualities have been compared bypristane/phytane and pristane/nC 1 7 ratios.

The lightest gravity oils (s.g. 0.87) and best yield potential (>9 kg/tonne/%TOC) are those from theMississippian age Albert Formation lamosites of New Brunswick, followed by the Pennsylvanian Pictou Groupstellarite (torbanite) of the Oil-Coal Seam of Nova Scotia, then the Ordovician Collingwood marine sapropelickerogens in Ontario, and the Upper Devonian Kettle Point marine mixed deposits of Ontario. Poorest recoveries(s.g. 0.97, 4 kg/tonne/%TOC) are from the Cretaceous Boyne-Favel formations of the Manitoba Escarpment.

Maximum pyrolytic yield potential occurs at the level of initial moderate maturity. At this position ofoptimum oil generation, recoveries are greater than those from immature zones. Recoveries then decrease

steadily through the moderate and high maturity ranges to ultimate overmaturity. The quality of oil improves asmaturation increases, but with a commensurate decrease in yield potential, best illustrated by Collingwood zonestudies. Increasing maturation over a depth range of 600 m has decreased yields by about 10% for the Albert oilshales but has not affected oil quality at the Albert Mines deposit, the most significant of known Canadiandeposits to date.

INTRODUCTION

During the past five years, the Geological Survey ofCanada has been systematically investigating, in conjunctionwith several provincial government geological agencies, oilshale potential in Canada to define more completely thefuture potential energy reserves of the nation. An initial

project, completed in 1980 (Macauley, 198*0, outlined thegeology of the known deposits and reviewed their relative

economic potentials from limited available analytical data.Since that time, the most significant deposits, locatedprimarily in the southern part of the country or in

economically strategic areas (i.e. near tide water) have beenevaluated by a series of techniques of which Rock-Evalpyrolysis was the prime method. Further assessment has been

by organic petrology (including maceral identification, andboth fluorescence and reflectance studies) and by productcharacterization using gas chromatography of thermal and

solvent extract fractions. Some early results and concepts

were reported in Macauley et al. (1983): more complete dataand interpretations are more recently available in

"Geochemistry and Geological Factors GoverningExploitation of Selected Canadian Oil Shale

Deposits"

(Macauley et al., 1985). Both classification and maturationdata, and their effect on the quantity and quality ofpyrolyzed hydrocarbons, have been excerpted andsummarized from the above paper for presentation herein.

No formal classification is as yet available for oil shale

kerogens; Macauley et al. (1985) proposed a system forCanadian oil shales (Fig. 1) based on a combination of thekerogen type (i.e. I, II, III) as defined in Tissot and Welte

'Consulting Geologists, 8-5400 Dalhousie Drive N.W., Calgary, Alberta T3A 2B42Geochemist, Institute of Sedimentary and Petroleum Geology, 3303 - 33rd Street N.W., Calgary,'Organic Petrologist, Institute of Sedimentary and Petroleum Geology, 3303 - 33rd Street N.W., (

(1978), maceral components defined by both Hutton et al.(1980) and Cook et al. (1981) and also by environment.Maturation levels are much less well defined. The use of coalmaturation indices has been attempted, but has beengenerally unsatisfactory because increased definition is

necessary within the "oil generation window", that stage ofmaturation so important for the development of hydrocarbonsfrom source rocks and also for the retorting processes for oilshales. Figure 2 outlines the maturation terminology appliedto Canadian oil shales by Macauley et al. (1985), andillustrates values for many of the geochemical, petrologicaland equivalent coal indices. The modifying terms low,medium and high, as applied to mature oil shales within theoil maturation window, are not synonymous with the low,medium and high volatile bituminous coal rankings.

Oil Shale Type

Continental Marine

Torbanite Lamosite MixedAmorphous

(sapropelic)

DominantKerogenType 1 1 II 11

SecondaryKerogen Type III 1,111

Maceral Telalginite(Alginite Al

Lamalginite(Alginite Hi

Amorphous Amorphous

(sapropelic)

Nun-ulgulcomponents

vitrinite

inertinitesporinite

sporinite indeterminate humusvitrinilc

sporinite

Environment bog lacustrine marine marine

Figure 1. Classification of oil shales based on geochemicaltype, maceral composition and environment (fromMacauley et al., 1985).

Alberta T2L 2A7l n.w., ^

Figure 2. Maturation indices (Rock-Eval) for oil shales and source rocks compared with the oil generation window and coal rank(from Macauley et al., 1 985).

Oil Shale Deposits la.

The locations and geological ages of the principal oil 9.

shale deposits in Canada are illustrated in Figure 3: of those

selected for comprehensive investigation, the OrdovicianCollingwood beds (no. 1), Devonian Kettle Point strata(no. 2), the economically most attractive Mississippian oilshales of New Brunswick (no. 3), the torbanites of the Pictouarea, Nova Scotia (no. 6), and the Cretaceous deposits of theManitoba Escarpment (no. 8) will provide most of the data forthe interpretations of this paper. Ordovician oil shales on

Southampton Island (no. 9), at the north end of Hudson Bay, Devonianhave been more recently evaluated (Macauley, 1986) and willbe described with the geochemically similar Collingwood beds

of southern Ontario. The four basic classifications (Fig. 1) 2.pertinent to Canadian oil shales are included within these

deposits.

Billings shale, stratigraphically equivalent to the nearbyCollingwood beds to the west; overmature but includedto provide control for maturity interpretations.

Southampton Island; Boas oil shales depositionallysimilar to those at Collingwood but possibly not astratigraphic equivalent; an end-phase limestone oilshale of a carbonate sequence but followed bycarbonate rather than shale; upper boundary may beerosional; Type I marine sapropelic (amorphous).

The Kettle Point Formation comprises up to 75 m ofblack oil shale intercalated with grey to green nonorganic shale; overlies carbonate with deposition in anapparent shallow open marine environment; Type IImarine mixed(?).

Ordovician

i. Collingwood oil shale outcropping parallel to the base

of the Niagara Escarpment; thin, widespread, brownish-

black to black limestone deposited as the final phase of

a carbonate sequence on a shallow, restricted marine

platform; overlain by a shale interval; Type I marinesapropelic (amorphous).

Carboniferous

3. Albert oil shales of the Mississippian Frederick BrookMember of the Albert Formation; best known of theCanadian oil shales and economically has the mostpotential; continental lacustrine dolomite and dolomite

6.

marlstones depositionally up to 100 m thick butexpanded to as much as 300 m at the Albert Minesdeposit by structural deformation; Type I continentallamosite.

Torbanite, locally called stellarite, associated with coalin the Oil-Coal Seam; areally restricted and thin withina shale sequence; a continental bog type deposit; Type Icontinental torbanite.

Cretaceous

8. Areally extensive shallow marine shale depositscharacterized by abundant white calcareous specks(coccolith debris) within the Boyne and Favelformations; two zones up to 60 m total; best developedalong the Manitoba Escarpment in Manitoba and easternSaskatchewan; local areas of fair yields; excellentthickness and large areal extent indicate vast potentialin-place reserves; Type II marine mixed.

to these data unless otherwise referenced. Included inTable I are: Tmax, the temperature recorded at the maximumhydrocarbon evolution rate defining the S2 peak; HI and OI,the Hydrogen and Oxygen indices, defining the ratios of S2hydrocarbons and of CO2 to the organic carbon content ofthe rock; the yield ratio of total recovered hydrocarbons tothe organic carbon content; PI, the Production Index, theratio of volatile hydrocarbons (SI peak) to the totalrecovered hydrocarbons (S1+S2); S.G., the specific gravity ofthe shale oil; Amax(nm), the optimum fluorescence intensity;Q, the Red/Green Quotient; and Ro(%), vitrinite reflectancevalues.

The data of Table I must be recognized as incomplete.Gas chromatography results are those from analyses of thesaturate fractions of solvent extracts, and are incompletewithin the total series of deposits studied. Similarly,investigations by organic petrology are still in progress;however, there are now sufficient data to provide apreliminary comparative insight into both the quantity and

quality of hydrocarbon products obtained from the differentclasses and maturities of kerogen encountered.

ANALYTICAL DATADISCUSSION

A standard program used for the Rock-Eval pyrolysishas been described in Macauley et al. (1985). The Rock-Evalpyrolysis apparatus at the ISPG, Calgary, does not respondlinearly for the S2 peak: the compensating techniques toovercome this factor have been described in detail inSnowdon (1984) and briefly in Macauley et al. (1985). Organiccarbon determinations, essential to the interpretation ofRock-Eval data, were obtained using a Leco WRI2 carbonanalyzer after crushing to an approximate 150 micronparticle size and treatment in both cold and hot hydrochloricacid (Snowdon, 1984). Some of the latest carbon determinations were made with a more recently acquired carbonanalyzer component of the Rock-Eval equipment.

Where available, Fischer Assay analyses have invariablybeen acquired through commercial laboratories utilizing thestandard practice defined by the United States Bureau ofMines.

Two techniques of organic petrology were utilized todetermine oil shale maturations. A microscope photometer(Leitz MPV II) was used to measure vitrinite reflectances atrandom orientations (%Rm), but these data were found to beineffective for interpretations of maturation because ofreduced reflectances resulting from bitumen impregnation ofthe vitrinite particles (Hutton et al., 1980; Kalkreuth andMacauley, 1984; Kalkreuth and Macauley, in press). Thesame microscope photometer was used to measure changes inspectral intensities of alginitic material during ultravioletirradiation, in particular the wavelength of the highestrecorded intensity (Amax [nm]) and the Red/Green Quotient(Q = intensity at 650 nm/intensity at 500 nm). Theseprocedures have been described in greater detail in Kalkreuthand Macauley (1984).

Table I summarizes the most significant data from allsources on the basis firstly of classification and secondly ofmaturation within each type of deposit. The comparativeassessments to be outlined for the various deposits will refer

The most complete data sequence is that for theOrdovician Type I sapropelic (amorphous) deposits where thecomplete spectrum from immature to overmature have beenencountered through five separate areas. Althoughconsiderable data are available for the most economicallypotential and most studied deposit, that of the Type Ilamosite Mississippian Albert oil shales, only a smallmaturation range is covered. Other deposits have beenmeasured only at single levels of thermal maturation to date.

Type I Lamosite:Brunswick

Mississippian Albert oil shales, New

A small but significant deposit at Albert Mines, NewBrunswick, containing an estimated 42.8 million cubic metres(269 million barrels) of in situ reserves to a depth of 600 mover an area of 1.6 km square (one square mile), providesmost of the data for this oil shale unit (Fig. 3, no. 3). Themajor kerogen component has been well defined aslamalginite (Kalkreuth and Macauley, 1984).

The most significant maturation variation can bemapped at a single corehole location (Macauley and Ball,1982; Kalkreuth and Macauley, 1984) where beds range fromlow near surface to moderate at a depth of 600 m. Theincreased maturation is evident by a downward decrease inyield of about 10% relative to TOC content, by an increasingpetroliferous odor on breaking, by an increase in theProduction Index and by pronounced changes in fluorescencevalues. No change was recorded in the average specific

gravities (Macauley and Ball, 1982) nor was there anysignificant change in the characteristics of the solventextract saturate fraction as defined by pristane and phytanecomponents (Altebaeumer, 1985). The uppermost beds are alaminated papery dolomitic marlstone with minor claycontent in contrast to the lower beds which are dolostones.Some mineral matrix effect may be present by which the

Figure 3. Principal oil shale deposits of Canada: those comprehensively analyzed by geochemical investigations are numbered(from Macauley et al., 1985).

yield is less from the deeper beds, but other data certainlyprove some degree of decreasing yield because of anincreased maturation level.

Data for marginal beds are less distinct, but are derivedfrom a limited number of samples at several locations both

east and west of the Albert Mines deposit. None of these

deposits is economically so attractive as that at Albert Mines

and data are much less definitive. The specific gravity is the

most pronounced variable: the Production Index is slightly

less than for the low maturity beds and the Hydrogen Index

has the highest indicated average value.

Oxygen is everywhere almost entirely lacking. This

may result if onlyminimal maturation is required to remove

the oxygen from lamosites, or may result from bacterial

reduction of the organic matter as evidenced by degradation

of the few spores encountered (Utting, pers. comm.) or mayindicate that these deposits contained virtually no indigenous

oxygen.

Tmax is also an enigmatic value for these deposits.Most of the original Rock-Eval investigations were carriedout on Type II deposits in France (Espitalie et al., 1977-Tissot and Welte, 1978). Since that time, furtherinvestigations have indicated that, for Type I deposits,initiation of maturation under laboratory conditions does notcommence until a temperature of 450C has been reached?,SKPltfhf,etal'4. lm)- As "Nation has increased atAlbert Mines, Tmax has not varied significantly, and hasremained m the range 443-445C, somewhat below theindicated onset value for initial maturation. There has beensome conjecture that, once maturation has started and muchof the kerogen converted to bitumen, the hydrocarbonproduct will then continue to mature at a lower temperature.If the bitumen has been generated by natural processes, onlythe lower temperatures of the increased maturation level willbe reflected in the laboratory pyrolyses.

Shale oil from the Albert beds is dominantly long chainaliphatic in character, with minimal aromatic component.

TABLE I

Generalized geochemical and organic petrological data

for the four basic oil shale types recognized in Canada

MaturityTmax

H, 0,YWdRrtto PI S.G.

Pristane/phytane

Pristane Amax/nC 1 7 (nm)

Ro%

Type I continental lamosite - Albert oil shale, New Brunswick

Marginal 444 900 7 9.40 .08 0.913Low 445 846 6 9.36 .10 0.884 0.6Moderate 442 836 6 7.90 .20 0.884 0.6

0.30.5

560>700

1.11 .501.48

Type I continental torbanite - stellarite of Oil-Coal Seam, Nova Scotia

Low(?) 450 648 11 7.10 .02 0.86 3.31(coal) .97

1.16 612 1.25 .41632 1.27

Type II marine sapropelic (amorphous) - Boas oil shale, Southampton Island

Immature 426 565 65 5.84 .04 - 0.73 1.81 460 0.29

Type II marine sapropelic (amorphous) - Collingwood oil shale, southwestern Ontario

Low 436 563 22 6.41 .06 0.9210.942

1.26 1.34

Moderate 439 470 19 5.04 .06 0.909 1.24 1.02High 444 195 15 2.51 .23 0.910 1.54 0.50Over 466 26 10 0.57 .57

Immature

Type II marine mixed - Kettle Point oil shale, southwestern Ontario

429 376 13 3.87 .04 0.936 1.70 1.69

Type II marine mixed - Boyne and Favel formations, Manitoba Escarpment

417 235 62 3.5 .03 0.965416 348 51 5.0 .03 0.965

Type I Torbanite: Stellarite of the Pictou Group, Nova Scotia

Stellarite is a local terminology for a torbanite bed,associated with immediately overlying coal in the Oil-CoalSeam in which both coal are stellarite are equallyrepresented in an average thickness approximating 3 m.Although the classification is well defined by the dominanceof telalginite, a Botryococcus-type algae (Macauley et al,1985; Kalkreuth and Macauley, in press), the maturation levelof the oil shale within the oil generation window is not

distinct, even though the maturation of the related coal canbe well defined from vitrinite reflectance data.

From the organic petrological investigations, thedominant kerogen component is telalginite, but somevitrinitic material is encountered and telalginite is alsopresent in the overlying coal bed. At 450C, Tmax may be onthe border of initial maturation (Espitalie et al., 1984), whichis apparently confirmed by the low (.02) Production Index.Both the Hydrogen Index and the yield ratio are below that of

the New Brunswick lamosite, but are above thoseencountered in the marine oil shales.

Occasional recognizable vitrinite would suggest ahigher Oxygen Index than has been encountered. Amax andred/green quotient values are intermediary between the lowto moderate levels of the Albert oil shales, and may indicateequivalent low to moderate maturation. However,completely different values may be applicable to thetelalginite kerogen. The two sets of values for the stellaritepertain to slightly different color as some of the discretetelalginite forms are duller than the average. Only onesolvent extract was analyzed by gas chromatography at theISPG with results that would indicate a considerable humiccomponent. This may reflect a sampling difficulty as otherdata do not reflect such a high humic content for thestellarite bed.

Vitrinite reflectance values are here of somesignificance as the Oil-Coal Seam occurs within a coal-

bearing sequence containing numerous other coal beds.Reflectances approximate 0.90% in the coal of the Oil-CoalSeam, but are closer to 0.40% in the stellarite, most probablythe result of bitumen impregnation (Kalkreuth and Macauley,in press), almost identical to the lowered vitrinitemeasurements that could be made for the lamosite deposits

reqSreslL^ Macauley, 1984). Bitumen impregnationin the ran

^gree of maturation. This deposit is probablylack It argC L0* t0 mode-ate thermal maturation, but thev.k oi generated hydrocarbon in the SI peak is anomalous.

exc^?hetorbanites (cannel coals with vitrinite

N

Type II marine mixed: Devonian Kettle Point Formation ofsouthwestern Ontario - Boyne and Favel formations of theManitoba Escarpment

Rock-Eval analyses are the basic data available for theType II mixed deposits, which have been analyzed only at animmature level of maturation. Tmax averages are below thegeneralized lower oil generation window value of 435C andProduction Indices are also low at 0.04 and 0.03.

The mixed nature of these deposits is characterized bythe lower Hydrogen Indices in contrast to those of the Type Ideposits, by the much higher specific gravities of therecovered oil products, and by both the Pristane/Phytane andPristane/nC 1 7 ratios which are indicative of a Type III humiccomponent. The Oxygen Indices of the Boyne and Favel bedsaverage over 50, similar to the high average at 65 for theimmature Type II sapropelic Boas oil shale. At 13, theaverage oxygen index of the Devonian Kettle Point beds islower than anticipated. There is a variation in HydrogenIndices and yield ratios reported for the Boyne and Favelunits: these appear to reflect variations in the relativeconcentrations of sapropelic and humic kerogens in thedeposit. Hydrogen indices in excess of 600 with related yieldratios up to 6.5 kg/tonne/%TOC are locally encountered,especially in the Favel beds, and have been interpreted torepresent beds dominated by sapropelic kerogen.

Oils are here the most aromatic commensurate with theheavier specific gravities of these hydrocarbons.

Organic petrology lacks definition in the sphere ofmatrix kerogen, the fine amorphous organic detritus which isso difficult to define in maceral terminology and which doesnot lend itself readily to fluorescence investigations. Thelowering of vitrinite reflectance values by bitumenimpregnation, generally by 50% in oil shale beds, makes thistechnique virtually valueless except where the oil shaleoccurs within a series of sediments containing coal bedsbarren of sapropelic kerogen, or, more usefully, in caseswhere the oil shales are immature or overmature wherebybitumen has not been generated or has been destroyed by thematuration process.

Gas chromatography provides excellent productcharacterization where the maturation is such that sufficientsoluble hydrocarbons have been generated to provideappropriate chromatograms. Where the SI component isabsent or small, especially in mixed deposits, results may notbe entirely indicative of the average kerogens present.

Many Rock-Eval pyrolyses can be carried out quicklyand inexpensively if sufficient analyses are required to justifyacquisition of the apparatus in contrast to commercialanalyses. Selected samples can then be subjected to theother analytical procedures which are generally more time-

consuming and also more expensive, but which can providemuch additional data from only a limited number of samples,and by which the classifications and maturations can be morecompletely defined.

SUMMARY OF PROCEDURES

SUMMARY OF RESULTS

Several techniques are available on which to baseinterpretations for both the classification and maturation ofoil shale beds, but none is 100% perfect in itself. Eachprocedure invariably leaves specific questions unanswered. Acontrolled combination of Rock-Eval pyrolysis forclassification, maturation and yield potential, opticalpetrology for maceral identification, fluorescence analysesfor small maturation differences and gas chromatographyfor hydrocarbon characterization can adequately identifymost variations of Type and maturation changes within anysingle geologic oil shale unit.

Mixed deposits, especially the marine Type II mixed andType I torbanites containing abundant humic matter, in part

grading to cannel coals, are the most difficult to interpret.The effects of co-maturation of both algal and humickerogens on product quantity and quality will requireconsiderable further study before any significantpredictability can be achieved.

Rock-Eval pyrolysis is weakest where mixed depositsare encountered because of a partial inability to differentiateType IIII mixes from Type II and Type IIIII mixes. Becauseof the now recognized differing Tmax values at whichmaturation commences and the lack of data defining theeffects of the kerogen types one on the other, Tmax is notthe specific guide initially hoped. Figure 2 will requireconsiderable revision relative to Tmax, and consequently tothe related coal rank maturation levels.

Generalized petroleum quantity and quality can berelated to the classification and maturation of Canadian oilshale deposits as follows:

Type I lamosites, typified by the Mississippian AlbertFormation oil shales of New Brunswick, yield the greatest oilquantities, in excess of 9 kg/tonne/%TOC from beds of lowthermal maturation. The oil quality increases from a specificgravity of 0.91 at low maturity to approximately 0.88 atmoderate maturity. These specific gravities are lower thanwould be generated by natural thermal maturation withincreasing depth of burial over a much greater time span, butare among the best quantities and qualities of shale oilpresently known.

Type I torbanites, known from the Nova Scotiastellarite bed, can generate oil at a rate in excess of7 kg/tonne/%TOC with specific gravities as low as 0.87 frombeds of possible low to moderate thermal maturity. Withinthese deposits, Type III kerogen is often a secondarycomponent, sometimes grading to the principal maceralcontent. Consequently, the oil product characteristics mayvary appreciably.

Type II marine sapropelic (amorphous) kerogens yield inexcess of 6 kg/tonne/%TOC, less than those of the Type Ideposits, but still appreciable. Specific gravities of therecovered oil products range from 0.94 from immaturekerogen to 0.91 from kerogens of moderate to high thermalmaturation. The best oil quality here approximates thepoorest oils from the immature lamosites.

4 Wo/*P"est yields, generally in the range 3 to* Kg/tonne/%TOC, and the highest specific gravities up to

ThV are. recovered from the TyPe marine mixed kerogens.ne yield and the quality may improve somewhat where thenumic component decreases relative to the sapropeliccontent. The Type II mixed Devonian Kettle Point bedspyroiyze to produce a slightly better quality oil at 0.94specific gravity, similar to that from immature Type IIsapropelic oil shales.

One aspect has been omitted from these investigations.Large quantities of natural gas can be a significant secondaryPrii ? f great imPrtance to any retorting process. Thiswill be of particular importance for the Type II mixedkerogens and to those Type I torbanites with a significantvitrinite content. Devonian gas shales of the eastern UnitedStates are stratigraphically equivalent to the Kettle Point oilshales of southern Ontario. Within these types of deposits,the relative quantities of oil and gas produced may varysignificantly with variations of the kerogen components.Generated gas could create hydroretorting effects andappreciably alter the co-produced oil product.

For the more uniform Type I lamosites and Type IIsapropelic kerogens, the determination of classification andthermal maturation are not difficult, but many furtherinvestigations will be required to understand fully those oilshales containing admixed humic kerogens.

Acknowledgments

to thank A.R. Cameron and

ISPG, Calgary for reading theAlso at the

The writers wishN.C. Ollerenshaw, of the .. f v.-.&jmanuscript and for their helpful suggestions. nu at mc

ISPG, P. Greener and L. MacLachlan prepared the manuscriptin the form required for publication. This paper is published

by permission of the Geological Survey of Canada.

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