Biomarker analysis of oils and source rocks using a thermal extraction-GC-MS

Chemical Geology, 93 ( 1991 ) l - I 1 Elsevier Science Publishers B.V., Amsterdam

1

Biomarker analysis of oils and source rocks using a thermal extraction-GC-MS Malvin Bjoroy a, Keith Hall a, Peter Barry Hall a, Paul Leplat b and Rita Loberg a a Geolab Nor A/S, Hornebergveien 5, 7038 Trondheim, Norway b Fina Research, ChausOe de Vilvorde, 98-100, B- 1120 Bruxelles, Belgium (Received February 20, 1990; revised and accepted January 8, 1991 )

ABSTRACT Bjoroy, M., Hall, K., Hall, P.B., Leplat, P. and Loberg, R., 1991. Biomarker analysis of oi|s and source rocks using a thermal extraction-GC-MS. In: J.A. Curiale, R. Alexander and P.W. Brooks (Editors), Organic Geochemistry of Hydrocarbon Basins. Chem. Geol., 93:1-11. GC-MS analysis of thermally extracted hydrocarbons on sediments has been tried in practice only in the last few years. It allows rapid acquisition of data, normally only obtained after elaborate work-up processes have been performed. An oil, an oil-stained sandstone and source rocks (4) have been selected for this study. Both saturated and aromatic hydrocarbon biomarkers were monitored using MID of selected ions. The machine used in this study has been developed at our laboratories. The methodology is the same for both oils and source rocks so that rapid hydrocarbon characterisation and oilsource rock correlations are possible.

1. Introduction GC-MS analysis of biomarkers is normally performed on the saturated and aromatic hydrocarbon fractions of solvent extracts. This is time-consuming, expensive and information on low molecular weight compounds is lost. Thermal extraction-gas chromatography is routinely performed on sediments in a number of different laboratories (Martin, 1977; St. Paul et al., 1980; Bjoroy et al., 1985). A commercially available instrument, the Geofina Hydrocarbon Meter ( G H M ) was introduced in 1988. Analysis of biomarkers by thermal extraction-GC-MS has only been tried in the last few years (e.g. P u t t m a n n et al., 1988). However, there are problems, in particular loss of high molecular weight material, and the low content of biomarkers in many sediments makes good analysis difficult. 0009-2541/91/$03.50

Analysis with the G H M has shown good reproducibility and virtually quantitative removal of all high molecular weight material from only 10 or 20 mg of sediment (e.g. Bjoroy et al., 1985). This study demonstrates the use of a G H M coupled to a Vestec quadrupole MS in biomarker analysis of source rocks, reservoir rocks and oil. Both low and high molecular weight biomarker analysis was performed.

2. Experimental procedure The GHM-MS system (Fig. 1 ) comprises a G H M injector installed onto a modified Varian Model 3400 gas chromatograph system. The G H M injector unit employs a sample probe onto which a sample cup with a capacity of 100 mg of whole rock is placed. The sample probe is driven into the furnace via a precision stepper motor, the probe shaft assembly is sealed at the furnace by high temperature Vi-

© 1991 Elsevier Science Publishers B.V. All rights reserved.

2

M. BJOROY ET AL.

~

He CARRIER

l

GAS

GHM

INJECTOR

SAMPLE CUP HP LASER JET I

4

TEKN I VENT MS DA1 A SYSTEM

SPLIT LINE VALVE

i

t! LN2 COl D TRAP

DIRECT

INLET

VESTEC

201 [C,'GCMS

Fig. 1. Schematicdiagram of the GHM-MSsystem.

ton O-rings. The furnace unit is heated by high temperature cartridge heaters of 300 W capacity, control is by a multi-ramp temperature controller (Newtronic Control model 96 TP5), which allows a variety of heating ramp functions to be employed. The sample is transferred to the column oven via an independently heated transfer line at 300°C. The sample effluent from the furnace may be analysed either in the split or splitless mode depending upon sample yield. The GHM gas chromatograph is coupled via a heated transfer line directly to the mass spectrometer and the line is operated at 300 °C. A capillary column of 0.32 m m i.d. is used, coated with a 0.5/~ film thickness ofOV 1 Methyl Silicone stationary phase. The column is temperature-programmed from 30°C up to 300°C at 4 ° C/minute, with an initial isothermal time of 5 min to allow the thermal desorption to take place and a final isothermal time of 10 min to allow complete elution of high molecular

weight components. In certain cases, liquid nitrogen cold-trapping is used to cryo-focus the lower molecular weight components. The capillary column is fed directly into the ion source to within 5 m m of the ion beam. The mass spectrometer used in the system is a Vestec Model 201 quadrupole mass spectrometer in which a differentially pumped vacuum system is employed. A low-volume, high-sensitivity ion source operating at 70 eV ionisation energy and 200 pA trap current and temperture of 260°C, the electron beam is collimated by two permanent magnets. The ions are detected by a Chaneltron electron multiplier, the output of which is fed to a Technivent mass spectrometry data system employing a Compaq model 286 IBM compatible computer. Output from the data system is via a Hewlett Packard Laserjet printer. Both full scan and selected ion recording may be employed depending upon sample requirements. In the selected ion recording mode a cycle time of 1 s is employed.

BIOMARKER ANALYSISOF OILS AND SOURCE ROCKS USING A THERMAL EXTRACTION-GC-MS

3. Results and discussion

An oil, a reservoir rock and source rocks (listed in Table 1 ) were selected for thermal extraction-GC-MS to demonstrate the potential of the technique for rapid characterisation of hydrocarbons and its use in correlation studies. Comparisons are made with saturate fractions from solvent extracts of the same samples. Figure 2 shows examples of general distributions of n-alkanes in the samples using the m / z 113 fragmentation. This exaggerates the contribution from the isoprenoids, so that pristane/nC~7 ratios for example are higher than would be seen from TIC plots. Note that low molecular weight hydrocarbons, i.e. from C~0 to nCls, are prominent even in the lowermaturity samples. Comparison of the North Sea samples shows a good correlation in the distribution of biomarker compounds in the t/Clg-rtC23 alkane region between Upper Jurassic Viking Gp. shales (both mature and moderately mature samples) and reservoired hydrocarbons in Middle Jurassic Brent Gp. TABLEI Basic data on the samples investigated Sample

Maturity (% Ro)

North Sea reservoir rock

Stratigraphy

Middle Jurassic Brent Gp. sandstone

North Sea, shale with type III kerogen

0.5

Lower Jurassic Dunlin Gp. shale

North Sea, shale with type II kerogen

0.5

Upper Jurassic Viking Gp. shale

North Sea, shale with type II kerogen

0.8

Upper Jurassic Viking Gp. shale

Green River Basin oil Green River shale with type I kerogen

Uinta Basin, USA

~ 0.5

Uinta Basin, USA

3

sandstones (peaks are marked with asterisk in chromatograms in Fig. 2 ). Basic information as to the input and maturity of these samples can be obtained from the distribution of hopanes and steranes (Seifert et al., 1980). This has been performed in this study using m/z 191 and 217 fragmentations, respectively. Figures 3 and 4 show hopane and sterane distributions for the same samples as in Fig. 2. Assignments of individual peaks are given in Tables 2 and 3. Values of typical parameters obtainable from the m/z 191 and 217 fragmentograms are shown in Table 4 for these samples and for comparison, results obtained from the saturate fractions of the solvent extracts of the same samples (Fig. 5 shows examples of the latter for oils). There is a good agreement for many of these parameters. The greatest disparity appears to be in less mature samples where other compounds may co-elute with, and hence interfere with, the results, or where parameters are chosen which cover a wide range of boiling points; for example, the ratio of the C24 tricyclic terpane (peak Q) to C3o aft hopane (peak E), which is higher in the thermal extract than the saturate fraction. In this case it may be that there is some retention of the C30 hopane by the mineral matrix in the case of the thermal extract. The hopane distributions seen in Fig. 3 show that differences in maturity are most marked between immature and the marginally mature North Sea source rocks, while there is little difference between marginally mature and oil window mature samples. The most significant differences are the presence of the tiff hopane series (i.e. 17fl(H) 21fl(H) series), abundant fla hopanes and low %C32 22S (i.e. 2 2 S ( 2 2 S + 2 2 R ) × 100, J1/J~ +J2) (see Table 4) in the immature sample. Whereas tiff hopanes are virtually absent, fla hopanes are less prominent and %C32 22S is approaching an equilibrium value of 60% (Mackenzie et al., 1980). Another ratio wich decreases rapidly before entering the main phase of oil generation, is the relative amount of C29 + C30 fla ho-

4

M. BJOROY

ET AL

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Fig. 2. m / z 113 fragmentograms of analysed samples: A. moderately mature Viking Group shale with type II kerogen (0.5% Ro); B. immature Dunlin Group shale with type III kerogen (0.4% Ro); C. moderately mature Green River shale with type I kerogen (0.5% Ro); D. mature Viking Group shale with type II kerogen (0.8% R,,); E. North Sea reservoir rock from Brent Group; F. Uinta Basin oil.

B I O M A R K E R ANALYSIS O F OILS .AND S O U R C E ROCKS U S I N G A T H E R M A L E X T R A C T I O N - G C - M S

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Fig. 3. Terpanes represented by m / z 191 fragmentograms of analysed samples (see Table 2 for peak identification). Sample identification as in Fig. 2.

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BI()MARKER

ANALYSIS

OF OILS AND SOURCE

ROCKS

USING

A THERMAL

I O0

EXTRACTION-GC-MS

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Fig. 5. mlz 191 and 217 fragmentograms of saturated fractions of oils: A. rn/z 191 fragmentograms,North Sea oil; B. mlz 191 fragrnentograms, Uinta Basin oil; C. m/z 217 fragmentograms, North Sea oil; D. rn/z 217 fragmentograms, Uinta Basin oil. panes (or moretanes) versus C29 + C30 a f t hopanes. This ratio, which is greater than one in immature sediments, has reached values close to that of North Sea oils when marginally mature (i.e. ~ 0.19 compared with 0.14 for oil). In contrast, the sterane distribution patterns ( m / z 2 17 fragmentograms, Fig. 4) show distinct differences in the maturity of the three North Sea source rock samples. For the immature sample from the Lower Jurassic, the

flo~a as well as the o~aa 20R compounds are present, but not the aao~ 20S C29 sterane. In the marginally mature Upper Jurassic sample, the % C 2 9 20S (i.e. c ~ a o ~ 20S/c~ao~ ( 2 0 R + 2 0 S ) × 100) value is 33% (somewhat lower, i.e. 24% from saturated hydrocarbons fraction of solvent fraction) and is at about equilibrium in the oil-stained sandstone and oil window mature Upper Jurassic, i.e. 50-60% (Mackenzie et al., 1980). In the mature Upper

8

M. BJOROY ET AL. I0~

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Fig. 6. m / z 125 f r a g m e n t o g r a m s : ( A ) G r e e n R i v e r shale; a n d ( B ) U i n t a Basin oil, s a t u r a t e d fraction. TABLE 2 Assignment of peaks in m / z 191 fragmentograms A. B. Z. C. D. E. F. G. H. I. J. K. L. M. P. Q. R. S. T. N. O. Y. X.

18a-trisnorneohopane (Ts) 170~-trisnorhopane ( T ~ ) Bisnorhopane c~//-norhopane flc~-norhopane o~fl-hopane /~-hopane 22S-c~fl h o m o h o p a n e 22R-~/~ h o m o h o p a n e /k~-homomoretane 22S-0~fl b i s h o m o h o p a n e 22R-c~fl b i s h o m o h o p a n e 22S-cxfl t r i s h o m o h o p a n e 22R-c~fl t r i s h o m o h o p a n e 22S-cd~ t e t r a k i s h o m o h o p a n e 22R-c~fl t e t r a k i s h o m o h o p a n e 22S-AB p e n t a k i s h o m o h o p a n e 22R-aft p e n t a k i s h o m o h o p a n e Tricyclic terpane Tricyclic terpane Tricyclic terpane (17R,17S) Tricyclic terpane Tricyclic terpane (17R,17S) Tricyclic terpane Tricyclic terpane 25,28,30-trisnorhopane/moretane U n k n o w n triterpane

C27H44 C27H46 C28H48 C29H5o C5oH29 C3oHsz C3oHn C3~ H54 C31H54 C31H54 C32H56 C32H56 C33H58 C33H58 C34H6o C34H6o C35H62 C35H62 C23H42 C24H44 C25H66 C24H42 C26H48 C21H38 C22H40 C27H46

(l) ( I I, R = H ) ( IV ) ( II, R =- C2H5 ) (II1, R = C2H5 ( I1, R = i - C3H 7 ) ( 111, R = i - C3H7 ) ( II, R = i - C4H9 ) ( 1I, R = i - C4H9) (II1, R = i - C 4 H g ) (II, R = i - C s H ~ ) (II, R = i - CsH~, ) ( II, R = i - C6H 13 ) (II, R = i - C6H13 ) (I1, R = i - CTHt5 ) (II, R = i - C7HI5 ) (1I, R = i - CsHI7 ) (II, R = i - C8HI7 ) (V, R = i - C4H9) (V, R = i - C s H t ~) (V, R - = i - C 6 H I ~ ) ( VI ) (V, R = i - C T H t s ) (V, R = C 2 H s ) (W, R = C 3 H 7 ) (VII)

C3oH52

c~ and fl refer to hydrogen atoms at C- 17 and C-21, respectively, unless indicated otherwise. Note that tiff hopanes are marked in fragmentograms with carbon number, for example C27flfl. C29 marks position of 25-norhopane.

Jurassic and the oil-stained sandstone there is little difference between the thermal extract

and solvent extract data. Similar observation may be made based on

BIOMARKER ANALYSIS OF OILS AND SOURCE ROCKS USING A THERMAL

100

EXTRACTION-GC-MS

9

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90

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33

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31

33

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37

39

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Fig. 7. T r i a r o m a t i c s t e r a n e s r e p r e s e n t e d by m / z 231 fragmentograms: (A) N o r t h Sea r e s e r v o i r rock: a n d ( B ) U i n t a Basin oil. For peak i d e n t i f i c a t i o n : al, C2o; bl, C21; q , C26 20S; dl, C26 2 0 R + C 2 7 20S; el, C28 20S; .[i. C2v 20R; gt, C2~ 20R. TABLE 3 .Assignment o f peaks in m/z 217 fragmentograms a. b. c. d. c. f. g. h. i. j. k. I. m. n. o. p. q. r. s. t. u. v.

20S-flc~-diacholestane 20R-flc~-diacholestane 20S-~fl-diacholestane 20R-~cfl-diacholestane 20S-fl~x-24-methyl-diacholestane 20R-flo~-24-methyl-diacholestane 20S-ecfl-24-methyl-diacholestane + 20S-c~c~-cholestane 20S-flo~-24-ethyl-diacholestane + 20R-ocflfl-cholestane 20S-c~flfl-cholestane + 20R-c~fl-24-methyl-diacholestane 20R-~xc~c~-cholestane 20R-flc~-24-ethyl-diacholestane 20S-c~fl-24-ethyl-diacholestane 20S-cxo~o~-24-methyl-cholestane 20R-c~ccfl-24-methyl-cholestane + 20R-~fl-24-ethyl-diacholestane 20S-~flfl-24-methyl-cholestane 20R-c~c~-24-methyl-cholestane 20S-c~c~c~-24-ethyl-cholestane 20R-o~flfl-24-ethyl-cholestane 20S-c~flfl-24-ethyl-cholestane 20R-~c~-24-ethyl-cholestane 5~-sterane 5c~-sterane

C27H48 C27H48 C17H48 C27H48 C2,H5o C28H5o C28H5o C27H48

C291-152 C27H48 C27H48 C28H5o C27H48 C29H52 C29H52 C28H5o C28H5o C29H52 C28H5o C28H5o C29H52 C29H52 C29H52 C29H52 C21H36 C22H38

( I, R = H ) (I, R = H ) (II, R = H ) ( If, R = H ) ( 1, R = CH 3 ) ( I, R = CH 3 ) (II, R = CH 3 ) ( 1II, R = H ) ( II, R = C2H5 ) ( IV, R = H ) (IV, R = H) ( 11, R = CH3 ) ( II1, R = H ) ( I, R = C2H5 ) ( II, R = C2Hs ) ( I II, R = CH 3 ) ( IV, R = CH 3 ) (II, R = C2 H5 ) (IV, R = CH 3) (III, R = CH 3 ) ( III, R = C2H5 ) (IV, R = C2H 5 ) (IV, R = C2H5 ) ( III, R = C2H 5 ) (VI, R = C2Hs ) ( II, R = C3H7 )

ce and fl refer to hydrogen atoms at C-5, C-14 and C-I 7 in regular steranes and al C-13 and C-17 in d iasteranes.

another commonly employed sterane parameter, i.e. the percentage of aflfl 2 0 R + 2 0 S C29 steranes (i.e. aflfl 20 (R + S ) C29/o~o~ol + o:flfl

(20R + S ) × 100 ) (see Table 4 ) ( Mackenzie et al., 1980). The most likely source rock for the oil in the

10

M. BJOROY ET AL.

TABLE 4 Biomarker ratios Sample

Pris/Phyt

Tm/T s

SAT

SAT

TE

TE

Mor/Hop

(°/o) 22SC32

(%) 20SC29

(%) C29

C2o/C2~ TriA

SAT

SAT

SAT

SAT

TE

ARO

TE

TE

TE

TE

Upper Jurassic Kimmeridge moderate mature kerogen type II

1.29

1.68

1.76

2.73 0.18

0.19

53

50

24

33

39

39

0.33

0.62

1.12

1.54

1.90

1.77 0.11

0.11

67

58

63

61

63

62

0.44

0.92

0.80

1.09

> 10

> 10

> 10

> 10

NM

NM

NM

NM

NM

NM

32

26

NM

NM

NM

NM

Upper Jurassic Kimmeridge mature kerogen type II

Lower .Jurassic immature kerogen type 111 2.9

~3.5

> 10

> 10

Tertiary Green River immature kerogen type I 0.92

0.77

8.5

4.5

0.66

0.89

Reservoired oil from Brent Gp.

1.9

1.8

1.0

0.9

0.14

0.14

60

60

54

55

63

63

0.41

0.38

Oil from Green River source

1.3

1.2

1.2

1.2

0.14

0.13

56

56

56

57

60

60

0.47

NM

Brent Gp. using the m / z 217 fragmentograms is the Upper Jurassic Viking Gp. The Lower Jurassic shale is quite clearly deficient in C27 and C28 steranes. However, there are also differences between the oil and the mature Upper Jurassic source. The oil is characterized by a lower Tm/Ts (peak B / A ) and prominent peaks due to 28,30 bisnorhopane (peak Z) and 25norhopane (C29 demethylated hopane) which are not seen in the mature shale. Note also the more prominent C27 and C29 20R 13fl(H) 17o~(H) diasteranes in the shale than the oil from the sandstone. It is suspected that a different organic facies of the Upper Jurassic Viking Gp. shales sourced the oil than the source rock example shown here. The hopanes and steranes of the Green River shale and oil are clearly quite different to the North Sea samples. Differences include abundant C28-C30 tricyclic terpanes (marked by

diamond symbols in Fig. 3) plus gammacerane and the distinct distribution pattern of steranes with abundant a a a 20R C28 and C2~ steranes relative to C27 compounds. Investigation of other fragmentations permits even better differentiation. For example, in the Green River shale carotanes are known to be abundant (Anders and Robinson, 1971 ), and using the m / z 125 fragmentation, these compounds can be detected in both oil and immature source rock as shown in Fig. 6. Aromatic hydrocarbon distributions can also be evaluated on the same samples. Triaromatic steranes (but not monoaromatic steranes) can be assessed using m / z 231 fragmentation. Figure 7 shows the m / z 231 fragmentograms of the oil samples shown in Fig. 2 and demonstrates the differences in relative amount ofC26-k-C27to C28 compounds in the two oils, e.g. ratio of peak d~ to g, ).

BIOMARKER ANALYSIS OF OILS A N D SOURCE ROCKS USING A T H E R M A L E X T R A C T I O N - G C - M S

4. Conclusions

Biomarker analysis can be undertaken both on oils, source rocks and reservoir rocks using 10-20 mg of sediment. The complete analysis is performed in approximately one hour, giving a full range of fragmentograms such as those which are normally used for GC-MS analysis of solvent extracts. The method is found to give excellent results on immature to mature samples, while samples of high maturity give poor data due to low amounts of high molecular weight biomarkers in these samples. Reservoir rocks have also given excellent data. There is no evidence of major loss of high molecular weight compounds compared with GC-MS analysis of saturated fractions in solvent extracts, and there are no major changes in the biomarker ratios employed. The testing of this type of analysis has only been undertaken on a few samples, so that mineral matrix effects, i.e. absorption effects from different types of minerals have not, as yet, been fully evaluated. There are slight differences in the triterpane and sterane patterns obtained by thermal extraction GC-MS and GC-MS of saturate and aromatic fractions of solvent extracts. Values of c o m m o n isoprenoid alkanes, hopane and sterane ratios using both GC-MS and GHM-MS on saturated and aromatic fractions for various samples presented in Table 4 show that the greatest differences are in the relative amounts of low to high molecular weight terpane to C30 + hopanes and low to high molecular weight steranes. For example, ratios such as C24 tricyclic terpane to C3o c~fl hopane (i.e. Q / E in m / z 191 fragmentogram) or C2o/C28 triaromatic steranes (e.g. aL/gl in m / z 231 fragmentogram) is larger in the thermal extracts than the saturate fraction. Similar variations have been observed in pyrolysis studies (e.g. Jones et al., 1988, and references therein).

11

However, during pyrolysis, kerogen is degraded and hopane ratios are altered. In this study, it is unlikely that degradation occurs and differences can probably be attributed to mineral matrix effects, or even partly to work-up processes during preparation of saturate and aromatic hydrocarbon fractions. References Anders, D.E. and Robinson, W.E., 1971. Cycloalkane constituents of the bitumen from Green River shale. Geochim. Cosmochim. Acta, 35:661-678. Bjoroy, M., Solli, H., Hall, K. and Leplat, P., 1985. Analysis of source rocks, reservoir rocks and cap rocks by combined thermal extraction and pyrolysis-gas chromatography. In: B.M. Thomas et al. (Editors), Petroleum Geochemistry in Exploration of the Norwegian Shelf. Proc. NPF (Nor. Pet. Soc.) Conf. on Organic Geochemistry in Exploration of the Norwegian Shelf, Stavanger, Oct. 22-24, 1984. Graham and Trotman, London, pp. 327-337. Jones, D.M., Douglas, A.G. and Connan, J., 1988. Hydrous pyrolysis of asphaltenes and polar fractions of biodegraded oils. In: L. Matavelli and L. Novelli (Editors), Advances in Organic Geochemistry 1987. Org. Geochem., 13 (4-6): 981-993. Mackenzie, A.S., Patience, R.L., Maxwell, J.R., Vandenbroucke, M. and Durand, B., 1980. Molecular parameters of maturation in the Toarcian shales, Paris Basin, France, 1. Changes in the Configurations ofAcyclic lsoprenoid Alkanes, Steranes and Triterpanes. Geochim. Cosmochim. Acta, 44: 1709-1721. Martin, S.J. 1977. Thermally evolved hydrocarbons from the bitumen and kerogen constituents of whole rock. In: R. Campos and J. Gofii (Editors), Advances in Organic Chemistry 1975. Enadimsa, Madrid, 677 pp. Puttmann, W., Eckhardt, C.B. and Schaefer, R.G., 1988. Analysis of hydrocarbons in coal and rock samples by on-line combination of thermodesorption, gas chromatography and mass spectrometry. Chromatographia, 25 (4): 279-287. Saint-Paul, C., Monin, J.C. and Durand, B. 1980. M6thode de caractdrisation rapide des hydrocarbures de Cj /~ C35 contenus dans les roches s6dimentaires et dans les huiles. Rev. Inst. Fr. Pdt., 35 (6): 1065-1078. Seifert, W.K., Moldowan, J.M. and Jones, R.W., 1980. Application of biological marker chemistry to petroleum exploration. Proc. 10th World Pet. Congr., Bucharest, Sept. 1979. Pap. SP8, pp. 425-440.