Organic Metamorphism in the California Petroleum Basins:

Chapter B—Insights from Extractable Bitumen and Saturated

Hydrocarbons

By Leigh C. Price

U.S. Geological Survey Bulletin 2174–B

U.S. Department of the Interior

U.S. Geological Survey
U.S. Department of the Interior

Bruce Babbitt, Secretary

U.S. Geological Survey

Charles G. Groat, Director

Any use of trade, product, or firm names in this publication

is for descriptive purposes only and

does not imply endorsement by the U.S. Government

Published in the Central Region, Denver, Colorado

Manuscript approved for publication December 15, 1999

Photocomposition by Norma J. Maes
III

Contents

Abstract ................................................................................................................................................ 1

Introduction........................................................................................................................................... 1

Samples and Methods......................................................................................................................... 2

Results.................................................................................................................................................... 2

Los Angeles /Ventura Hydrogen-Poor OM: Extractable Bitumen—Amounts and

Characteristics ........................................................................................................................... 2

Introduction.......................................................................................................... 2

 HC Generation ...................................................................................................... 2

 Loss of Generated HCS .................................................................................................... 6

 Variable OM Hydrogen Richness ................................................................................... 7

 HC-Rich Immature Shales................................................................................................ 7

 Bitumen Compositions...................................................................................................... 12

 Saturated-HC Gas Chromatograms ...................................................................... 12

Southern San Joaquin Valley ................................................................................................... 13

Introduction......................................................................................................................... 13

HC Generation..................................................................................................................... 13

Non-Generation Controls.................................................................................................. 13

Bitumen Composition......................................................................................................... 15

Saturated-HC Gas Chromatograms................................................................................. 15

Hydrogen-Rich OM ..................................................................................................................... 17

HC Generation..................................................................................................................... 17

Bitumen Compositon.......................................................................................................... 19

Saturated-HC Gas Chromatograms ....................................................................... 20

Discussion ............................................................................................................................................. 23

Suppression of Organic Metamorphism in Hydrogen-Rich OM.......................................... 23

Origin of High Concentration of Immaure HCS....................................................................... 24

Bell-Shaped HC-Generation Curves ........................................................................................ 26

Conclusions........................................................................................................................................... 27

Acknowledgments ............................................................................................................................... 28

References ............................................................................................................................................ 28

Figures

1. Plot of the HC and bitumen coefficients versus burial temperature for

 Los Angeles and Ventura Basin shales ......................................................................... 6

2–4. Gas chromatograms of:

2. Saturated HCS from a powdered and whole-rock shale sample ..................... 8

3. Saturated and aromatic HCS from samples of mature core and cuttings 

chips from shales of the Apex-1 well, Los Angeles Basin................................. 10

4. Saturated and aromatic HCS from five immature Los Angeles 

Basin shales .............................................................................................................. 11

 5. Plot of normalized compound-fraction percentages versus burial temperature 

for bitumen from Los Angeles and Ventura Basin shales with hydrogen-poor 

organic matter........................................................................................................... 12

 6. Saturated-HC gas chromatograms from Los Angeles and Ventura Basin 

shales with hydrogen-poor organic matter.......................................................... 14

7. Plot of the HC and bitumen coefficients versus depth for shales from the 

Paloma Field, Southern San Joaquin Valley Basin........................................................ 15

 8. Saturated- and aromatic-HC gas chromatograms from four deep shales from 

the Paloma Field........................................................................................................ 16

 9. Plot of normalized compound-fraction percentages versus burial 

temperature for bitumen from Paloma Field shales............................................ 17
IV

10. Saturated-HC gas chromatograms from Paloma Field shales demonstrating

relative maturity changes versus depth.......................................................................... 18

11. Plot of the HC and bitumen coefficients versus burial temperature for 

shales from the Los Angeles and Ventura Basins and with hydrogen-rich 

organic matter ..................................................................................................................... 19

12. Plot of normalized compound-fraction percentages versus burial temperature 

for bitumen from shales with hydrogen-rich organic matter and from the 

the Los Angeles and Ventura Basins ............................................................................. 21

 13. Saturated-HC gas chromatograms from Los Angeles and Ventura Basin shales 

 with hydrogen-rich organic matter.................................................................................. 22

 14. Plots of normalized compound-fraction percentages and the HC coefficient

versus the ROCK-EVAL hydrogen index for samples buried at 158° to 176.2°C........ 24

 15. Saturated-HC gas chromatograms, over the n-C26 to n-C36 range, of three pair 

(hydrogen-rich versus hydrogen-poor organic matter) of samples, each pair at 

equivalent burial temperatures......................................................................................... 25

 16. Plots of various petroleum-geochemical data versus depth for immature 

offshore California shales.................................................................................................. 26

Tables

1. Soxhlet extraction data for the samples of this study .................................................. 3
1

Abstract

Seventy-five shales from the Los Angeles, Ventura, and 

Southern San Joaquin Valley Basins were extracted and analyzed. Samples were chosen on the basis of ROCK-EVAL analyses of a much larger sample base. The samples ranged in burial 

temperatures from 40° to 220°C, and contained hydrogen-poor 

to hydrogen-rich organic matter (OM), based on OM visual typing and a correlation of elemental kerogen hydrogen to carbon 

ratios with ROCK-EVAL hydrogen indices. 

By extractable bitumen measurements, rocks with hydrogen-poor OM in the Los Angeles Basin began mainstage hydrocarbon (HC) generation by 90°C. The HC concentrations 

maximized by 165°C, and beyond 165°C, HC and bitumen concentrations and ROCK-EVAL hydrogen indices all began 

decreasing to low values reached by 220°C, where HC generation was largely complete. Rocks with hydrogen-poor OM in 

the Southern San Joaquin Valley Basin commenced mainstage 

HC generation at 135°C and HC concentrations maximized by 

180°C. Above 180°C, HC and bitumen concentrations and 

ROCK-EVAL hydrogen indices all decreased to low values 

reached by 214°C, again the process of HC generation being 

largely complete. In both cases, bell-shaped HC-generation 

curves were present versus depth (burial temperature). Mainstage HC generation had not yet begun in Ventura Basin rocks 

with hydrogen-poor OM by 140°C. The apparent lower temperature for initiation of mainstage generation in the Los Angeles 

Basin is attributed to very recent cooling in that basin from 

meteoric-water flow. Thus, HC generation there most probably 

occurred at higher burial temperatures.

In contrast, mainstage HC generation, and all aspects of 

organic metamorphism, were strongly suppressed in rocks with 

hydrogen-rich OM at temperatures as high as 198°C. For example, shales from the Wilmington field (Los Angeles Basin) from 

180° to 198°C retained ROCK-EVAL hydrogen indices of 550-

700 and had saturated-HC coefficients of only 4-15 mg/g 

organic carbon. The rocks with hydrogen-rich OM were subjected to the same burial conditions as the rocks with hydrogenpoor OM. We attribute this suppression of organic metamorphism in this study primarily to much stronger bonds in the 

hydrogen-rich OM compared to the bonds in hydrogen-poor 

OM. Trends in bitumen compositions (qualitative characteristics) versus burial temperature were also very different for rocks 

with hydrogen-poor OM compared to that in rocks with hydrogen-rich OM. This observation demonstrated that the two OM 

types also had significantly different reaction pathways, in addition to different reaction kinetics. Strong exploration implications arise from these observations.

Above 40°C, but before mainstage HC generation, a lowtemperature (pre-mainstage) HC generation occurred in all 

rocks, and all OM types, studied. This low-temperature generation resulted in significant qualitative changes in the bitumen 

and HCS (hydrocarbons) from rocks of all OM types, especially 

in rocks with hydrogen-rich OM, from 40° to 70°C. This, and 

previous studies, document that very high carbon-normalized 

concentrations of indigenous bitumen and HCS occur in late 

Neogene immature rocks of any OM type in all southern California basins. This characteristic is attributed to the low-temperature generation occurring in both sulfur-poor and sulfur-rich 

kerogens, which originally had unusually high concentrations of 

weak (15-40 Kcal/mole) bonds. These observations and considerations have marked relevance to exploration regarding the possible formation of commercial oil deposits at immature ranks in 

these basins. Other significant geochemical observations also 

result from this study.

Introduction

Price and others (1999) listed the reasons for the overall 

study. Samples were chosen for Soxhlet extraction from trends 

observed in, or hypotheses made from, the data of Price and others (1999). These samples provide a unique opportunity to study 

the effects of organic matter (OM) variation on hydrocarbon 

(HC) generation for several reasons: First, hydrogen-rich (types 

I and II) OM and hydrogen-poor (types III and IV) OM were 

intermittently deposited with each other in different areas of the 

southern California petroleum basins. In fact, many examples 

exist (based on ROCK-EVAL analyses, Price and others, 1999) 

where different OM types occur in rocks several meters apart in 

the same wellbore. Second, all OM types have been exposed to 

high burial temperatures (180° to 219°C) in the basins studied, 

which should result in high organic maturities. Thirdly, as discussed in Price and others (1999), the present-day burial temperatures in the synclines of two of the three basins studied are 

believed to be maximal and are some of the most accurate 

Organic Metamorphism in the California Petroleum Basins: 

Chapter B—Insights from Extractable Bitumen and Saturated 

Hydrocarbons

By Leigh C. Price
2 Organic Metamorphism in the California Petroleum Basins

equilibrium temperatures available worldwide. Thus, organic 

maturities can be directly related to maximum burial temperature. As in Price and others (1999), data are plotted here versus 

(equilibrium) burial temperatures and not depth because geothermal gradients vary both between basins and between different sites in the same basin. Lastly, sediment age ranges from 

upper Miocene to Pliocene (roughly 2 to 8 million years) and 

thus the influence of geologic time (if any, Price, 1983) is minimized in these samples.

This is the second paper of a three-part study. The first 

paper (Price and others, 1999) discussed vitrinite reflectance 

(Ro) and ROCK-EVAL analyses, and related those analyses to 

OM type. The third part of the study will examine biomarkers, 

aromatic HCS, the results of aqueous-pyrolysis experiments, 

modeling studies, whole-rock extraction (Price and Clayton, 

1992), δ13C measurements of bitumen and macerated kerogens, 

and kerogen visual analyses.

Plots, versus burial temperature, of milligrams of extractable C15+ bitumen or HCS, both normalized to grams of total 

organic carbon (the bitumen and HC coefficients), wherein all 

samples were put on one plot, had no definable trends. Thus, the 

sample base was broken into three subgroups. Samples from the 

Los Angeles and Ventura Basins were put into two groups: (1) 

samples with ROCK-EVAL hydrogen indices less than 300 (all 

but 4 of 28 samples studied herein had hydrogen indices less 

than 240), in other words, types III or IV OM; and (2) samples 

with hydrogen indices greater than 380, or more hydrogen-rich 

OM (one sample with an HI of 306 (TOC = 5.18) was put in this 

class). The Southern San Joaquin Valley Basin samples made up 

the third class, and 13 of these 16 samples had types III or IV 

OM. Organic-matter type identification was determined by the 

relationship between kerogen elemental hydrogen to carbon 

ratios and the ROCK-EVAL hydrogen-index established in Price 

and others (1999). 

Samples and Methods

All samples were core except for two cuttings chips samples from the Apex-1 wellbore. See Price and others (1999) for 

a description of cleaning methods. All cleaned rocks were 

ground and sieved to 100 mesh and Soxhlet extracted in dichloromethane for 72 hours. The dichloromethane and bitumen 

were reduced in volume by passive evaporation (Price and 

Wenger, 1992), retaining all C8+ compounds. (All solvent evaporation was by passive evaporation.) After transferring the 

extract to a 50 mL volumetric flask, a 5 mL aliquot was taken for 

bitumen determination. The dichloromethane was passively 

evaporated to 1 mL, and 3 aliquots of 5 mL of hexane were 

added, with intervening passive evaporation to 1 mL, to deasphaltene the bitumen. After the last evaporation, the asphaltenes 

were filtered and weighed, and the remaining bitumen passively 

evaporated to 0.5 to 1.0 mL for silica-gel-alumina column chromatography to separate the bitumen into saturated and aromatic 

HCS and resins. Saturated HCS were eluted with 10 mL of hexane, aromatic HCS with 25 mL of benzene, and resins with 7 mL 

of 1:1 benzene-methanol. The saturated and aromatic HCS were 

transferred to 10 mL volumetric flasks and 5 mL of each were 

taken for C8+ gas chromatography, and the other 5 mL were used 

for C13+ weights (obtained by letting the 5 mL aliquot in tared 

vials stand for 12-18 hours after losing their last solvent).

Samples are identified by feet and not meters in this paper 

because sample depths were originally in feet and conversion to 

meters would cause loss of the prime identifier. Extraction data 

are presented in table 1.

Results

Los Angeles/Ventura Hydrogen-Poor OM: Extractable 

Bitumen-Amounts and Characteristics

Introduction

 Although the Los Angeles and Ventura Basins are separate, 

they are geographically close with very similar depositional and 

geologic histories. The rocks and extracted bitumen from the 

two basins were qualitatively indistinguishable from one another 

and the starting OM in the two basins also appears identical. 

Because of these reasons, and the more limited number of samples from the Ventura Basin, samples from both basins were 

plotted together. 

HC Generation

Milligrams of C15+ bitumen (triangles) and C15+ HCS 

(dots), both normalized to total organic carbon (TOC), are plotted versus burial temperature for rocks with types III and IV OM 

from the Los Angeles and Ventura Basins in figure 1. The numbers at each bitumen coefficient sample point are ROCK-EVAL 

hydrogen indices (left number) and TOC contents (right number). Two bell-shaped curves have been fitted to the data, the 

solid line is the HC coefficient and the dashed line is the bitumen 

coefficient. Sixteen of the 27 HC coefficients lie on or near the 

inferred (solid-line) curve for those samples as do 16 of the 27 

bitumen coefficients for their inferred (dashed) curve. Bellshaped HC or bitumen coefficient (generation) curves are not 

always present, where expected, for sample bases that have sufficient maturity ranges (discussed below). However, when 

present, these curves invariably have significant scatter, as in figure 1. In fact, the inferred bell-shaped generation profile of figure 1 is not at all well defined, and it could be argued that a HCgeneration profile is not necessarily even present in figure 1. 

However, the inferred profile of figure 1 is partly based both on 

well-defined generation profiles from the very large ROCKEVAL data base for the Los Angeles Basin in Price and others 

(1999, figs. 1, 3, 8, 9) and the lack of detectable HC generation 

in samples from the Ventura Basin in the data base of Price and 

others (1999). In fact, one purpose of figure 1 is to examine the 

causes resulting in the scatter of data points throughout, and thus 

the lack of definition in, HC-generation profiles (“bell-shaped 

curves”), including those of figure 1.

Both the inferred HC and bitumen coefficient curves begin 

noticeable increases over 90° to 100°C, rather than the 120°C 

reported by Phillipi (1965). Moreover, the figure 1 data agree 

with the much larger ROCK-EVAL sample base of Price and 
Samples and Methods 3

Table 1. Soxhlet-extraction data for core samples of shales from selected southern California basins. Original sample depths are given in feet. 

in percent of rock weight. PPM is parts per million (dry rock weight) of the respective species. MG/G OC is milligrams (of the respective speciexample, the bitumen coefficient). SATS are saturated HCS, AROS are aromatic HCS, NSO are resins, ASP are asphaltenes, and TOTAL BIT, is ROCK-EVAL Tmax and hydrogen index, respectively. BURIAL TEMP. °C is the burial temperature in °C. All wells in the Wilmington field and the 

drilled and depths in table 1 are true burial depths and not driller depths. Wilmington field wells are cluster wells drilled from piers or islands as nBasin: Apex-1 is the American Petrofina Central Corehole (all Apex-1 samples are core except for two cuttings chips samples, labeled as cuttingas shown. La Mirada 46-1 is the General Petroleum La Mirada 46-1 in the Anaheim Nose area. LL&W-1 is the Standard Oil of California (SOCA1 (slightly northwest of the most northwest extension of the Huntington Beach Field). McGrath-18 is the Continental McGrath-18 (Seal Beach fiePetroleum Santa Fe Springs-243 (Santa Fe Springs field). Del Amo-1 is the SOCAL Del Amo-1 southwest of the Dominguez field and northeast oBryant Estate-1 is the Texaco Bryant Estate-1 (just northeast of the Seal Beach field). Bald. Hills Comm.-1 is the Shell Baldwin Hills CommunityA is the Shell Alamitos 48-A (southeast end of Long Beach field). L.B. Airport-1 is the Texaco Long Beach Airport-1 (just northeast of the central L1 is the SOCAL Houghton Community-1 (northwest plunge of the Santa Fe Springs field). In the Ventura Basin: Taylor 315 is the Shell Taylor 315 Lloyd-185 (both wells are in the Ventura Avenue field). SOCAL Lim.-1 is the SOCAL Limoneira-1 and Sup. Lim.-1 is the Superior Oil Co. LimoneirIn the Southern San Joaquin Valley Basin, Paloma field: Ohio Oil A-1 is as named; Ohio Oil KCLA-8 is as named; KCL-F-71-10 is the Ohio Oil KCLperior Oil Anderson 56-35; and the KCL A 72-4 is the Ohio Oil KCL A 72-4. One sample is not from the Paloma field, the Shell 21-14 which is the Sh12.9 km (8 mi) north of the Paloma field. The Ventura Basin outcrop sample is explained in the text.
4 Organic Metamorphism in the California Petroleum Basins Table 1—continued
Samples and Methods 5

Table 1—continued

VENTURA BASIN
6 Organic Metamorphism in the California Petroleum Basins

76.8/2.93

107/1.36

90.7/1.50

128/1.35V

103/1.91V 215/1.65

198/2.70

277/1.98

232/1.36V

262/1.43

282/2.41/V

200/1.70V

192/1.38HC

217/2.18

87.4/1.74

116/1.93

174/1.20

87/1.20

84.4/2.10 50/1.28

96.7/1.06

95.4/0.87

LBA

AC

AC

219/1.25

ACO

112/0.88V

176/1.56V

144/1.22

MILLIGRAMS PER GRAM OF ORGANIC CARBON

40

50

60

70

80

90

100

110

120

0 25 50 75 100 125 150 175 200 225

130

140

150

160

170

180

190

200

210

220

BURIAL TEMPERTURE IN °C

others (1999), which also showed intense HC generation beginning by 90° to 100°C for hydrogen-poor OM in the Los Angeles 

Basin. Part of the disagreement between the two studies is from 

Phillipi's (1965) incorrect assumption of uniform geothermal 

gradients throughout the Los Angeles Basin. Notwithstanding, 

the data of figure 1 illustrate that HC generation appears well 

underway by 120°C, with bitumen concentrations maximizing at 

about 155°C, and HC concentrations maximizing at about 

165°C. Both curves then exhibit continuous decreases with 

increasing temperature to the highest temperatures examined 

(about 220°C).

Samples at 200°C and greater have low hydrogen indices, 

with the deepest sample at 219°C having a hydrogen index of 

only 50. Samples at 220°C are approaching burnout for hydrogen-poor OM, or a loss of all HC generation potential (Price, 

1989). This is not equivalent to C15+ HC thermal destruction. 

It appears from figure 1 that mainstage-HC generation 

commences in Ventura Basin rocks with hydrogen-poor OM by 

90° to 100°C. However, other considerations suggest that this is 

not the case. First, ROCK-EVAL analysis of a much larger sample base of Ventura Basin rocks (Price and others, 1999, figs. 7, 

10, 11) demonstrates that mainstage-HC generation has not 

begun there by 140°C. Secondly, the high bitumen and HC coefficients for the Ventura Basin 176/1.56 sample at 120°C (fig. 1), 

and probably to some extent the moderate values of the Ventura 

Basin 232/1.36 sample at 114°C (fig. 1), are an unusual characteristic of some immature shales in all the southern California 

petroleum basins: abnormally high carbon-normalized concentrations of immature bitumen and HCS (discussed below). Thus, 

we do not interpret the elevated coefficients in these two samples 

as due to HC generation. Lastly, two deeper Ventura Basin samples (282/2.41 (124°C); and 200/1.70 (139°C); fig. 1) have lower 

coefficients than the trend of the curves, the 200/1.70 sample 

significantly so. These low values are attributed to mainstageHC generation not having begun in these rocks.

Loss of Generated HCS

The bitumen and HC concentration decreases at temperatures above 155° to 165°C, respectively in figure 1, are usually 

attributed to C15+ HC thermal destruction (Tissot and Welte, 

1984). However, data below demonstrate that this cannot be the 

case. We attribute these decreases to both HC expulsion and to 

loss of generated HCS to the drilling mud. These two controls 

may also result in some of the higher temperature (≥140° C) discordant sample points of figure 1.

The data point labeled “HC” at 172°C in figure 1 is core 

from the Houghton Community-1 wellbore. This, and other, 

samples of this study were submitted to both whole-rock extraction (Price and Clayton, 1992) and conventional powdered-rock 

extraction. Whole-rock extraction detects an oil phase fractionated from the whole-rock bitumen, which is poised for expulsion 

in cracks and parting laminae of the rock, when such bitumen is 

present. Unpublished research by L. C. Price, subsequent to the 

Price and Clayton (1992) study, demonstrates that this fractionation of bitumen to an oil-like phase depends largely on both 

organic richness and increasing maturity. Differences exist 

between the whole-rock and powdered-rock extracts for the 

Houghton sample (fig. 2). Note the reduced amounts of isoprenoid HCS (especially pristane and phytane) and the higher 

concentrations of n-paraffins in the whole-rock extract. Elevated 

percentages of saturated HCS (SATS) and reduced percentages 

of asphaltenes (ASP) and resins (NSO) are also present in the 

whole-rock extract compared to the powdered-rock extract (fig. 

2).

Thus, whole-rock extraction demonstrates, as expected, that 

a more oil-like phase, compared to the extract from the powdered rock, has been fractionated from the Houghton-1 bitumen 

and exists in cracks and parting laminae ready for expulsion. 

Considering the sample's burial temperature (172°C), it is also 

probable that some expulsion of oil has already occurred from 

this rock, partially accounting for the abnormally low bitumen 

and HC coefficients of this sample (fig. 1). 

However, these low values could also be from partial loss of 

this fractionated-oil phase to the drilling mud during the rock 

trip up the wellbore in drilling operations. This HC loss is discussed in Price and LeFever (1992) and Price (1994). During 

the rock trip uphole, HC gases cogenerated and present with the 

fractionated oil, expand in volume from the large pressure 

decreases from depth to surface. These gases explode into the 

drilling mud, blowing fractionated oil in the rock's cracks and 

parting laminae into the mud. This can result in the loss of sigFigure 1. Plot of the HC coefficient (mg C15+ saturated plus aromatic 

HCS/g OC; dots, solid line) and the bitumen coefficient (mg bitumen/g OC; 

triangles, dashed line) versus present-day burial temperature in °C for 

shales with hydrogen-poor OM from the Los Angeles and Ventura Basins. Thus, there are two data points for each sample. Ventura Basin 

samples are labeled by "V", all others are Los Angeles Basin. The lefthand number of each sample pair (eg. - 76.8/2.93) is the ROCK-EVAL hydrogen index (76.8); the right-hand number is the TOC (2.93). One unlabeled sample at 98°C (just below "103/1.91V") has values of 207/2.41. LBA 

is Long Beach Airport-1; HC is Houghton Community-1; AC is Apex-1 cuttings chips; and ACO is Apex-1 core.
Samples and Methods 7

nificant amounts of generated HCS to the drilling mud before 

mature source rocks ever arrive at the laboratory for analysis. 

Features of the whole-rock chromatogram of figure 2 suggest that such a loss has occurred in this sample. Note the two 

dashed lines on the whole-rock chromatogram (fig. 2) connecting the C12 to C17 n-paraffins and the C13 to C18 isoprenoid HCS. 

Such regular decreases in concentration with decrease in carbon 

number result from leaching by solution mechanisms or from 

evaporation. Bell-shaped chromatograms, such as that of the 

whole-rock gas chromatogram of figure 2, also result from a gasassisted loss of generated HCS to the drilling mud.

The HC loss to the drilling mud has been found to be larger 

from cuttings chips than from core because of the larger surface 

area of cuttings chips (L. C. Price, unpub. data). This observation is manifested in the data of figure 1. 

Of the 27 samples of figure 1, all are core except two, 

which are picked cuttings chips (shales) from the 6,324.3 m 

(20,750 ft) Apex Central Core Hole-1, the deepest well in the 

Los Angeles Basin. These two cuttings-chip samples are labeled 

AC (Apex-1 chips) at 176° and 198°C (fig. 1). The 5 deepest 

samples of figure 1 are all core from the Apex well, and a sample 

at 183°C (labeled ACO) between the two cuttings-chips samples 

is also an Apex-1 core sample. The 183°C core sample was 

identical to the two contiguous cuttings chip samples (at 

176°and 198° C, fig. 1), regarding OM facies and mineralogy, 

except that it was core. Note that the amount of extractable bitumen and HCS for the two Apex-1 cuttings-chip samples fall far 

off their respective curves, curves largely defined by Apex-1 core 

at depth in figure 1. This observation is attributed to a greater 

loss of generated HCS to the drilling mud from the cuttings 

chips versus core. Moreover, this loss strongly affects qualitative characteristics of the remaining HCS in the two Apex-1 cuttings-chips samples.

Saturated and aromatic HC gas chromatograms of the three 

samples under discussion (176°, 183°, and 198°C) are in figure 

3, the chromatogram from the core being in the middle and those 

from the cuttings chips being on the top and bottom. Note the 

“rounded’’ bell-like shape of the peaks above the hump and the 

expanded humps in the four chromatograms from cuttings chips 

compared to the chromatograms from core. The saturated HCS 

from the core have higher concentrations of higher and lower 

molecular weight material compared to the cuttings chips, which 

have a post-escape “residue’’ concentrated over n-C16 to n-C21. 

As discussed the aromatic-HC gas chromatogram of the core is 

dominated by peaks of alkylated-benzenes, alkylated-naphthalenes, and alkylated-phenanthrenes and resembles a moderately 

mature oil. In contrast, these peaks are less pronounced in the 

aromatic-HC gas chromatograms from cuttings chips. The 

rounded bell-shaped gas chromatograms of figure 3 have been 

observed in other unrelated studies of this author and are 

believed to be characteristic of rocks with significant HC losses 

to drilling mud (Price and Le Fever, 1992). As discussed, the HC 

losses are due to a decrease of confining pressure as core and 

cuttings chips ascend the wellbore during drilling operations. 

Also note in figure 3 that the carbon-normalized saturated- and 

aromatic-HC concentrations of the two cuttings-chip samples 

are significantly lower than that of the core: 32.7 and 45.8 percent less saturated HCS and 31.0 and 41.4 percent less aromatic 

HCS for the 198° and 176°C (18,255-18,451 ft and 16,337-

16,641 ft) samples, respectively, compared to the equivalent values from the core sample. Data from Price and others (1999) 

demonstrate that the OM over this burial interval in the Apex-1 

was all the same. Thus, these differences in amounts of saturated HCS are not due to facies variations.

Variable OM Hydrogen Richness

In figure 1, samples shallower than 94°C generally have 

lower hydrogen indices (76.8-128) compared to deeper samples 

between 95° and 200°C (hydrogen indices = 116-282, with one 

exception at 159°C, “LBA’’, hydrogen index = 87.4). This distribution of hydrogen indices is in part due to an increase in silts 

and sands, and a decrease in kerogen hydrogen richness, with 

decrease in depth (and rock age) in the Los Angeles and Ventura 

Basins (Price and others, 1999), partly because these basins 

“sanded-up’’ in the late Pliocene and Pleistocene. Thus, shallower sediments were deposited in more oxygen-rich settings, 

had more terrestrial OM deposited with them, and their OM was 

more strongly diluted with mineral matter, all compared to 

deeper sediments. The increase in hydrogen indices with 

increase in depth is also partly due to increasing kerogen hydrogenation by water with increasing depth (Price and others, 

1999).

The “LBA” (Long Beach Airport-1) sample at 159°C in figure 1 with a hydrogen index of 87.4 and 1.74 percent TOC has 

discordant (low) HC and bitumen coefficients. A hydrogen 

index of 87.4 is tending towards type IV OM (inertinite). This 

explains the low HC and bitumen coefficients, because per unit 

weight, type IV OM has less capacity for HC generation than 

types III or III/II OM. Thus, another reason for the scatter in 

bell-shaped HC generation curves (fig. 1) can be variable original kerogen hydrogen richness, even within rocks of seemingly 

uniform OM.

HC-Rich Immature Shales

In figure 1, four samples at burial temperatures <120°C 

have unexpectedly high HC and bitumen coefficients (107/1.36 

(53°C), 112/0.88V (57°C), 215/1.65 (94°C), 176/1.56V 

(120°C)). In fact, two of these samples have values characteristic of the deeper zone of mainstage-HC generation. These four 

samples, and probably to a lesser extent several other samples of 

figure 1, typify an observation applicable to fine- (and coarse-) 

grained rocks of the southern California petroleum basins: 

abnormally high bitumen concentrations can exist in these rocks 

at immature ranks. This observation was also made by both 

Katz and Royale (1993) and Katz and Elrod (1983) for offshore 

southern California sediments. As discussed in Price and others 

(1999), ROCK-EVAL analyses of coarse-grained rocks in these 

basins often demonstrated significant staining, an observation 

supported by Soxhlet extractions of several of the stained rocks 

(not discussed here). It appears that many (most?) porous rocks 

in and around southern California oil fields have moderate to 

significant levels of oil staining. Innumerable petroleumgeochemical analyses of coarse-grained rocks from California 

petroleum basins by UNOCAL support this observation (Bruce 

Bromley, UNOCAL, oral commun., 7/94). Such staining in 
8 Organic Metamorphism in the California Petroleum Basins n-10 i-13 i-14 i-15 i-16 n-15 i-18

n-20

n-25

n-29

n-30

n-31

n-32

PR

PHY

n-10

n-11

n-12

i-13

i-14

i-13 

i-15 

i-16 

i-18 

n-14 

n-15 

n-16 

n-17 

n-20 

n-19 

n-18 

n-21 

PHY 

10 20 30 40 50 60 70 n-22 n-23 n-24 n-25 n-26 n-27 n-28 n-29 n-30 n-31 n-32 

RETENTION TIME IN MINUTES

50

40

30

20

10

0

30

20

10

0

SATS

AROS

NSO

ASP

SATS

AROS

NSO

ASP

HOUGHTON COMMUNITY-1

POWDERED ROCK

HOUGHTON COMMUNITY-1

WHOLE ROCK
Samples and Methods 9

these coarse-grained rocks would originate from migrating oil, 

either derived from shales adjacent to the sands or from more 

deeply buried shales.

The origin of occasional high bitumen and HC concentrations in immature fine-grained rocks with all OM types in the 

California basins is more problematical. Many causes are possible; however, we envision only three likely explanations: (1) 

abnormally large amounts of either HCS or HC precursors in 

kerogen with weak bonds, originally deposited with the shales; 

(2) migrating oil, from deeper more mature rocks, moving into 

shallower fine-grained rocks; and (3) HC cap-rock leakage from 

oil-fields with gas-assisted vertical migration through microfracture networks over the fields. Each explanation has flaws. Conversely, qualitative evidence within the saturated and aromatic 

HCS of the “stained’’ samples suggests each mechanism operable, while concurrently demonstrating that no mechanism operates universally. In figure 4, saturated- and aromatic-HC gas 

chromatograms are shown for five immature shales, four of 

which are “stained’’, as delineated by abnormally high saturatedHC coefficients determined by Soxhlet extraction. The top saturated-HC chromatogram (fig. 4, Reyes-1) is representative of 

immature “unstained’’ samples for all OM types: (1) low concentrations of C14- and C22+ n-paraffins; (2) high pristane/n-C17 and 

phytane/n-C18 (and other i-C/n-C) ratios; (3) most of the saturated HCS composed of n-C14 to n-C20 molecular weight material; and (4) prominent biomarker peaks, compared to adjacent nparaffins. Blowups of the biomarker region are in the upper right 

of each saturated-HC chromatogram.

 The Reyes-147 and Taylor-315 (second and fourth) chromatograms (fig. 4) both have elevated concentrations of saturated 

and aromatic HCS, and thus by quantitative considerations 

would appear to be “stained’’. However, the saturated-, and aromatic-HC gas chromatograms of both these samples are typical 

of immature “unstained’’ samples of all OM types, and thus also 

serve as representative examples of chromatograms from immature samples. For example, within the aromatic HCS for these 

two samples: (1) there is a pronounced C15+ hump; and (2) there 

are large, but not dominate, peaks of methyl-, dimethyl-, and trimethyl- naphthalenes, and methyl- and dimethyl- phenanthrenes. 

Note in contrast that the C15+ hump in the Reyes-1 aromatic HCS 

(first right-hand chromatogram) is suppressed by uncharacteristically high concentrations of alkylated benzenes. High concentrations of HCS and bitumen with immature characteristics in 

immature rocks, such as the Reyes-147 and Taylor-315 examples, account for most examples of “stained’’ samples of finegrained rocks in this study. As discussed below, these cases are 

attributed to generation occurring over low temperatures (40° to 

90°C), from HC and bitumen precursors in kerogen with very 

weak bonds.

The WC533 shale (bottom chromatograms, fig. 4) has low 

saturated- and aromatic- HC concentrations, and by quantitative 

considerations would be considered unstained. However, the 

saturated HCS from this sample have very mature characteristics 

for their burial temperature (73.5°C): (1) elevated n-C/i-C 

ratios, (2) elevated concentrations of C14- and C19+ material, and 

(3) high n-paraffin peaks compared to adjacent biomarkers. 

Within the aromatic HCS: (1) there is a reduced hump, (2) significant C15- material, and (3) much of the sample is composed 

of alkylated benzenes and naphthalenes. The relatively elevated 

amounts of C15- HCS in this sample preclude either surface 

staining of the core by oil during drilling or co-deposition of the 

HCS with the shale, because loss or evaporation of the C15- HCS 

would occur in both cases. Instead, these low carbon-normalized concentrations of mature HCS appear to have been 

“implanted’’ in the shale after burial. A gas-assisted vertical 

migration of oil (gas solution) from a more deeply buried reservoir could account for the low concentrations of mature HCS in 

the WC533 sample. Microseepage of thermogenic HC-gas 

occurs at all surface localities in petroleum-bearing basins, 

including sites laterally removed from production (Price, 1986, 

1993a). Moreover, Leith and others (1993) demonstrated a gasassisted vertical migration of oil into microfractured shales for 

as much as 400 m above the Snorre field in the North Sea and 

discussed other such cases documented by workers in other 

areas. Similar vertical HC movement through caprocks above 

oil fields would be expected, and is documented, in the structurally intense southern California basins, and thus also helps to 

explain the scatter in the figure 1 data, including the scatter in 

the bell-shaped HC generation curve.

The WD107 shale sample has high concentrations of biodegraded saturated (and aromatic) HCS (third chromatograms, fig. 

4). Biodegradation requires an open-fluid system for both nutrient and oxygen influx to the microbes and for waste-product 

removal. This is not possible in a shale. Perhaps the WD-107 

HCS were co-deposited with the shale, from macroseeping oil 

being degraded at the depositional interface. However, the WD107 biodegraded HCS could have also have originated from a 

gas-assisted vertical migration, from a deeper biodegraded oil 

reservoir, through microfractured caprocks.

Curiale and others (1985) also reported biodegraded HCS 

extracted from two samples of Antelope shale from the Miocene 

Monterey Formation in the Midway-Sunset oilfield, San Joaquin 

Valley Basin. They tentatively concluded that the biodegradation occurred either in the water column before deposition or at 

the sediment-water interface after deposition. They did not 

believe that these biodegraded HCS were emplaced by oil staining because these samples had some of lowest extractable 

organic-matter contents of their entire sample set, and they (logically) concluded that oil-staining should result in high bitumen 

coefficients. However, the bitumen coefficients of their two 

samples were, in point of fact, moderately high (117.9 and 141.5 

mg/g OC), especially for their shallow burial depths (675.4 and 

932.0 m, respectively). Moreover, the WC533 sample (last chromatograms, fig. 4) must be oil-stained, yet it has very low saturated- and aromatic-HC coefficients (8 and 3 mg/g OC, 

respectively). Thus, staining does not necessarily appear to 

result in high HC concentrations. Because the highly structured 

Midway-Sunset field would be prone to vertical HC leakage 

Figure 2 (previous). Saturated-HC gas chromatograms from solvent extractions of whole and powdered rock of the Houghton Community-1, 

12,875-12,890 ft sample. The n-paraffins are designated by n- and their respective carbon numbers, isoprenoid HCS by i- and their respective carbon numbers, PR is pristane and PHY is phytane. Dashed lines connect 

the tops of the n-paraffin and isoprenoid HC peaks. Use the whole-rock 

chromatogram as an index for the powdered-rock chromatogram. Histograms show the normalized percentages of C13+ saturated (SATS) and aromatic (AROS) HCS, resins (NSO) , and asphaltenes (ASP) for both 

extracts.
10 Organic Metamorphism in the California Petroleum Basins n-10i-16 n-15i-18 PR PHY n-20 n-25 n-30

ALBEN

NAP

MNAP

DMNAP

TMNAP

PHEN

MPHEN

DMPHEN

n-10

n-11

n-12 i-13

i-14 n-13

n-14 i-15

i-16 n-15

i-18 n-17

n-16

n-18

n-19

n-20

n-21

n-22

n-23

n-24

n-25

n-26

n-27

n-28

n-29

n-30

n-31

n-32

n-33

n-34

n-35

PR

PHY

ALBEN

NAP

MNAP

DMNAP

TMNAP

PHEN

MPHEN

DMPHEN

i-16 n-15

i-18

PR

PHY

n-20

n-25

n-30

ALBEN

NAP

MNAP

DMNAP

TMNAP

PHEN

MPHEN

DMPHEN

RETENTION TIME IN MINUTES RETENTION TIME IN MINUTES

APEX-1

16,337-16,641ft

176.2 °C

BIT=122mg/g

SATS=58.8mg/g

CUTTING CHIPS

APEX-1

16,337-16,641ft

AROS=29.0mg/g

APEX-1

16,974ft

183.2 °C

BIT=168mg/g

SATS=76.1mg/g

CORE

APEX-1

16,974 ft

AROS=42.2mg/g

APEX-1

18,255-18,451 ft

198.3 °C

BIT=122mg/g

SATS=48.9mg/g

CUTTING CHIPS

APEX-1

18,255-18,451 ft

AROS=24.6mg/g

10 20 30 40 50 60 70 80 10 20 30 40 50 60 70 80

Figure 3. Saturated and aromatic HC gas chromatograms for two cuttings-chip samples (16,337-16,641 ft and 18,255-18,451 ft) and one core sample 

(16,974 ft) from the Apex-1 wellbore. In the saturated-HC chromatograms, n-paraffins are designated by n- and their respective carbon number, isoprenoid HCS by i- and their respective carbon number, PR is pristane, and PHY is phytane. Use the 16,974 ft chromatogram as an index for unlabeled 

peaks in the other saturated-HC chromatograms. Sample depth is in feet, burial temperature is in °C, bitumen coefficients, or the milligrams of bitumen per gram of organic carbon (BIT = "x" mg/g), and saturated-HC coefficients (SATS = "y" mg/g) are given for each saturated-HC chromatogram. In 

the aromatic HC chromatograms: ALBEN are alkylated benzenes; NAP is naphthalene; MNAP, DMNAP, and TMNAP are the methyl-, dimethyl-, and 

trimethyl-naphthalenes; PHEN is phenanthrene, and MPHEN and DMPHEN are the methyl- and dimethyl-phenanthrenes. Aromatic HC coefficients 

(AROS = "x" mg/g) and sample depths (in feet) are given for each aromatic HC chromatogram.
Samples and Methods 11

n-10

i-13

i-14

i-15

i-16 n-15

i-18

PR

PHY

n-20

n-25

n-26

n-27

n-28

n-29

n-30

n-31

n-32

n-33

n-34

n-35

ALBEN

NAP

MNAP

DMNAP

TMNAP

PHEN

MPHEN

DMPHEN

n-15

i-18

PR

PHY

n-20

n-25

n-30

n-26

n-27

n-28

n-29

n-30

n-31

n-32

n-33

n-34

n-35

ALBEN

NAP

MNAP

DMNAP

TMNAP

PHEN

DMPHEN

MPHEN

n-11

n-12

n-13

i-15n-14 i-16

n-15

n-16

i-18

PR

PHY i-21

n-19 n-20

n-21

n-22

n-23

n-24

n-25

n-26

n-26

n-27

n-28

n-29

n-30

n-32

n-31

ALBEN

NAP DMNAP

TMNAP

MNAP

PHEN

MPHEN

DMPHEN

n-10

n-12

i-14

n-13

i-15n-14

i-16 n-15

n-16

i-18

PR

PHY

n-20

n-25

n-30

n-26

n-27

n-28

n-29

n-30

n-31

n-32

n-33

n-34

n-35

ALBEN

NAP

MNAP

PHEN

DMNAP

TMNAP

MPHEN

DMPHEN

n-10

n-11

n-12

n-13

i-13

i-14

i-15 n-14

n-15 i-16

i-18

n-16

n-17 PR

PHY

n-18

n-19

n-20

n-21

n-22

n-23

n-24

n-25

n-26

n-27

n-28

n-29

n-30

n-31

n-32

n-33

n-26

n-27

n-28

n-29

n-30

n-31

n-32

n-33

n-34

n-35

ALBEN

NAP

MNAP

DMNAP TMNAP PHEN

MPHEN

DMPHEN

n-18

n-17

REYES-1

2830-2833ft

53.1 °C

HI=107

SATS:

 229ppm

 17mg/g

REYES-1

2830-2833ft

AROS:

 149ppm

 9mg/g

REYES-147

3725-4218ft

65.2 °C

HI=197

SATS:

 805ppm

 56.3mg/g REYES-147

3725-4218ft

AROS:

 372ppm

 26.0mg/g

WD-107

3017ft

72.4 °C

HI=162

SATS:

 3122ppm

 120mg/g

WD-107

3017ft

AROS:

 3346ppm

 129mg/g

TAYLOR-315

11,850-11,855ft

119.9 °C

HI=176

SATS:

 1146ppm

 73mg/g

TAYLOR-315

11,850-11,855ft

AROS:

 461ppm

 30mg/g

WC-533 3083 ft

 73.5 °C HI=176

SATS:

 245ppm

 8mg/g

WC-533

3083ft

SATS:

 107ppm

 3mg/g

RETENTION TIME IN MINUTES RETENTION TIME IN MINUTES

10 20 30 40 50 60 70 80 10 20 30 40 50 60 70 80
12 Organic Metamorphism in the California Petroleum Basins

0 10 20 30 40 50 60 70 80 90 100

40

50

60

70

80

90

100

110

120

130

140

150

160

170

180

190

200

210

220

BURIAL TEMPERATURE IN °C

NORMALIZED PERCENTAGE

9/76.8

53/112/V

16/90.7

22/207

16/103 17/128/V

40.1/277

56/217

24/200/V

72/87.4

66.4/192

118/219

100/95.4

69/84.4

71/50 95.3/96.7

80.4/87

73.5/174

87.8/116

124/144

103/176/V

35.2/282/V

53.2/232/V

35.2/198

55.2/215

57.7/262

26/107

SATS

AROS NSO

ASP

through its fractured anticlinal crest, the two biodegraded samples Curiale and others (1985) reported on could be due to oil 

staining.

Examples of immature fine-grained rocks with unusually 

high HC concentrations are common in the southern California 

basins. These HCS have multiple origins and help to obfuscate 

interpretation of quantitative and qualitative characteristics arising from HC generation, such as the data of figure 1.

 Bitumen Compositions

Normalized bitumen percentages are plotted in figure 5 for 

the samples of figure 1 along with TOC-normalized extractable 

HCS (left-hand number) and the ROCK-EVAL hydrogen index 

(right-hand number). Over no temperature range in figure 5, is 

there a correlation between maxima or minima in the compound 

classes with either the HC coefficient or the hydrogen index. To 

wit, a relatively high percentage of saturated HCS does not consistently correlate with relatively high (or low) hydrogen indices 

or HC coefficients. However, there is a trend, with scatter, of a 

progressive increase in the percentage of saturated HCS of the 

total bitumen versus a continuous decrease in the resins, with 

increasing burial temperature. In contrast, aromatic HCS, and 

to a lesser extent, asphaltenes, remain relatively constant versus 

temperature. The 90° to 180°C range covers most of the mainstage HC generation zone (fig. 1). Over these temperatures in 

figure 5, all compound classes remain somewhat constant, with 

one exception near 140°C (“56/217’’). Thus, it appears that in 

the case of hydrogen-poor OM, the HCS and resins plus 

asphaltenes are being cogenerated with each other, unlike the 

case with hydrogen-rich OM, wherein resins and asphaltenes 

are generated first and later thermally decompose to HCS 

(Lewan, 1991; Price and Wenger, 1992). In other words, reaction pathways may be different between these different OM 

types.

Saturated-HC Gas Chromatograms

Qualitative changes in the saturated HCS from HC generation in hydrogen-poor OM are evident in figures 4 and 6. 

The Reyes-1, Reyes-147, and Taylor-315 saturated-HC chromatograms of figure 4 (first, second, and fourth chromatograms, left side), and the La Mirada 46-1 chromatogram of 

figure 6 (upper left chromatogram), represent examples from 

immature samples. These chromatograms (1) are principally 

concentrated over the 16 to 22 carbon number range; (2) have 

a pronounced naphthenic hump; (3) have low, but variable, 

concentrations of C15- and C23+ n-paraffins; (4) have moderate 

to prominent biomarker peaks; and (5) have moderate isoprenoid HC to n-paraffin (i-C to n-C) ratios. The first and second characteristics are distinguishing. In contrast, early stages 

of HC generation (refer to Sup. Lim .-1 13,080 ft and La 

Mirada 46-1 11,988 ft; second and third left chromatograms 

respectively; fig. 6) are generally characterized by (1) moderate to significant increases in the relative concentrations of C15- 

and C21+ compounds; moderation of the naphthenic hump; (3) 

pronounced biomarker peaks with relatively small adjacent nparaffins; and (4) higher i-C to n-C ratios, relative to more 

immature samples. The increased relative concentrations of 

C15- compounds demonstrates that the hydrogen-poor OM of 

these basins generates these compounds, an important point of 

discussion below.

Samples in the middle of mainstage HC generation and 

beyond, as expected, demonstrate increased maturity. For example, the Baldwin Hills-1 12,406 ft chromatogram (upper right 

chromatogram, fig. 6) has a smoother C17+ n-paraffin profile, 

greatly reduced biomarker peaks, and lower i-C/n-C ratios, all 

relative to more immature samples. However, saturated HCS 

from rocks with hydrogen-poor OM at this, and higher, ranks 

invariably have low or reduced concentrations of C14- HCS and 

Figure 4 (previous). Saturated and aromatic HC gas chromatograms 

from five immature shales. In the saturated HCS, n-paraffins are designated by n- and their respective carbon numbers, isoprenoid HCS by iand their respective carbon numbers, PR is pristane, and PHY is phytane. 

Use the WC-533 3,083 ft saturated HC chromatogram as an index for unlabeled peaks in the other chromatograms. Sample depth (in feet), burial 

temperature (in °C), the ROCK-EVAL hydrogen index (HI), and saturatedHC concentrations in ppm (by rock weight) and as normalized to TOC 

(mg/g) are given for each saturated HC chromatogram. An expanded 

chromatogram of the biomarker region (n-C26 to n-C36) is also provided 

wherein the n-paraffins are labeled by their respective carbon numbers. 

In the aromatic-HC chromatograms, ALBEN are alkylated benzenes; 

NAP is naphthalene; MNAP, DMNAP, and TMNAP are the methyl-,

dimethyl-, and trimethyl-naphthalenes; PHEN is phenanthrene; and 

MPHEN and DMPHEN are the methyl-, dimethyl-phenanthrenes. Aromatic-HC concentrations are also given in ppm (by rock weight) and as 

normalized to TOC (mg/g).

Figure 5. Normalized percentages, versus burial temperature, of saturated (SATS) and aromatic (AROS) HCS, resins (NSO), and asphaltenes 

(ASP) in bitumen from rocks with hydrogen-poor OM from the Los Angeles-Ventura Basins. The left-hand number of each sample is the HC coefficient (mg saturated plus aromatic HCS/g TOC) and the ROCK-EVAL 

hydrogen index is the right-hand number. Ventura Basin samples are 

marked by "V". 
Samples and Methods 13

smoothly decreasing n-paraffin profiles with decreasing carbon 

numbers (dashed lines in the Baldwin Hills-1 and Apex-1 16,974 

ft and 20,219 ft (three right-hand chromatograms, fig. 6). As discussed below, this feature is not from either analytical procedures or HC loss during core storage. Instead we attribute the 

feature to a preferential loss of C14- saturated HCS either to 

expulsion or to the drilling mud.

The maturity of the Apex-1 16,974 ft chromatogram is 

advanced relative to the Baldwin Hills-1 chromatogram, as is 

that of the Apex-1 20,219 ft chromatogram relative to the Apex1 16,974 ft chromatogram (three right-hand chromatograms, fig. 

6): smoother n-paraffin profiles; greatly reduced biomarker 

peaks; lower i-C/n-C ratios, and so forth. However, the Apex-1 

16,974 ft sample also has reduced concentrations of both C14- 

peaks (dashed line) and C19+ n-paraffins relative to the Apex-1 

20,219 ft sample, features also attributed to a significant loss of 

these compounds either to expulsion or to the drilling mud. The 

C15+ portion of the 20,219 ft chromatogram has the mature 

characteristics expected for its 213.9° C burial temperature. 

However, this sample has also lost significant amounts of C15- 

HCS (dashed line).

Southern San Joaquin Valley

Introduction

Selected shales from the Paloma field in the central syncline of the Southern San Joaquin Valley were chosen for 

Soxhlet extraction to confirm the ROCK-EVAL analyses for this 

area (Price and others, 1999), and for comparison with the 

extractable OM from rocks with hydrogen-poor OM from the 

Los Angeles-Ventura Basins. The extensively cored 21,306 ft 

(6,493.8m) Ohio Oil KCL “A’’ 72-4 wellbore (Paloma Field) 

has a well defined HC generation profile (Price and others, 1999, 

figs. 12, 13). One sample (257/1.67, 101°C, fig. 7) is from the 

Canal field about 12.9 km (8 mi) north of the Paloma field and 

was used to fill in a temperature gap in the Paloma field samples. 

HC Generation

In figure 7, the solid line and dots are the HC coefficient 

(mg HCS/g OC), and the long-dashed line and triangles are the 

bitumen coefficient (mg bitumen/g OC) for shales from the Paloma field. Hydrogen indices (left number) and TOC contents 

(right number) are given for each sample. Between burial temperatures of 70° to 90°C, most of the shales had low TOC contents with very hydrogen-depleted OM (Price and others, 1999, 

fig. 12). This prevented determination of pre-generation C15+ 

bitumen and HC baseline concentrations in figure 7. Thus, the 

short-dashed lines in the 70° to 120°C portion of both curves are 

interpretations accommodating the extraction data from the low 

TOC rocks of this interval. Based on the ROCK-EVAL data for 

this area (Price and others, 1999; their figs. 12, 13), the solid and 

long-dashed lines are believed to best represent trends which 

would be in rocks with TOC contents of 1-3 percent (if such 

rocks were present): gradually increasing HC and bitumen concentrations from low-level HC generation occurring before 

mainstage HC generation. A shallow (70-120°C) zone of 

intense HC generation, as portrayed by the short-dashed lines, is 

not a preferred explanation. Rather, we attribute the elevated HC 

and bitumen coefficients over this interval to the low TOC values 

of two of the samples (0.19 and 0.32 percent) and to elevated 

amounts of indigenous (pre-generation) HCS and bitumen in the 

2.57/1.67 sample, which, as noted, is from the Canal field, north 

of the Paloma field.

Mainstage HC generation is interpreted to begin at 135°C 

in figure 7 (in the middle of the Antelope shale of the Miocene 

Monterey Formation) and to maximize by 180°C. These are 

lower temperatures for these events than those of the much 

larger ROCK-EVAL data base for this area (150° and 203°C, 

respectively, figs. 12 and 13 in Price and others, 1999). By comparison, Kruge (1983), from both analyses of Monterey rocks at 

the Lost Hills oilfield and time-temperature modeling, concluded that intense HC generation would only begin at 140°C in 

the Southern San Joaquin Valley Basin, an estimate in agreement 

with the analyses of this study. The temperatures at Paloma for 

beginning mainstage HC generation (135°C) and maximum of 

generation (180°C) are significantly higher than for the same 

two events in the Los Angeles Basin rocks with hydrogen-poor 

OM (90° to 95° C and 150° to 160°C, respectively, fig. 1). This 

divergence is attributed to the hypothesis of Price and others 

(1999) that the Los Angeles Basin has cooled significantly in the 

recent geologic past. Thus, HC generation there actually took 

place at higher burial temperatures than present-day values.

Non-Generation Controls

Parameters besides HC generation have significant control 

over quantitative and qualitative aspects of the bitumen from 

shales of the Paloma field. For example, the apparent shallow 

trends in the bitumen and HC coefficients (short-dashed lines, 

fig. 7) are inferred as due to very low TOC values in two samples 

and to abnormally high contents of immature indigenous bitumen in one sample. As another example in figure 7, one sample 

(590/2.26 at 150°C) has values far greater than the trends of the 

curves and two samples (94/2.97, 180°C; and 39.6/2.02, 214°C) 

have values far less than the curves. The 590/2.26 sample has a 

bitumen coefficient of 376, which plots off scale. As discussed 

below, the saturated- (and aromatic-) HC gas chromatograms of 

this sample (Anderson 56-35, 13,905 ft) have immature characteristics. Thus the high HC concentrations in this rock are not 

from oil staining. Instead, the very large bitumen (376) and HC 

coefficients (228) of this sample are another example of the high 

contents of indigenous bitumen possible at pre-HC-generation 

ranks in rocks in the California petroleum basins. Moreover, the 

hydrogen index decreased from 590 to 223 when this sample 

was Soxhlet extracted, demonstrating that the rock contains type 

III, and not type II, OM.

Comparison of the two samples with low HC and bitumen 

coefficients (94/2.97, 180°C; and 39.6/2.02, 213°C) in figure 7 

with samples at equivalent temperatures and on the curves (227/

1.66, 180°C; and 95.6/1.14, 214°C; respectively), yields insights 

into the reasons for these low values. Saturated- and aromaticHC gas chromatograms are given in figure 8 for the four samples 

under discussion. The saturated-HC chromatograms for the 
14 Organic Metamorphism in the California Petroleum Basins n-10i-13i-14 i-16 i-18n-15 PR PHY n-20 n-25n-27 n-28 n-29 n-30 i-15 n-31

n-10

i-13

i-14

i-15

i-16 n-15

PR

i-18

PHY

n-20

n-25

n-30

n-31

n-32

n-33

n-34

n-35

n-10

i-13

i-14

i-15

i-16 n-15

i-18

PR

PHY

n-20

n-27

n-25

n-28

n-29

n-30

n-31

n-32

n-33

n-34

n-35

n-10

i-13

i-14

i-15

i-16 n-15

i-18

PR

PHY

n-20

n-25

n-30

n-31

n-32

n-33

n-34

n-35

n-10

n-11

n-12 i-13

i-14 n-13

i-15 n-14

i-16n-15

n-16

i-18

PR

PHY

n-18

n-19

n-20

n-21

n-22

n-23

n-24

n-25

n-26

n-27

n-28

n-29

n-30

n-31 n-32

n-33

n-34

n-10

n-11

n-12 i-13

i-14

i-15

n-13

n-14

i-16

n-15

n-16 i-18

n-17 PR

PHY

n-18

n-19

n-20

n-21

n-22

n-23

n-24

n-25

n-26

n-27

n-28

n-29

n-30

n-31

n-32

n-33

n-34

n-35

LA MIRADA 46-1

7732-7735 ft

92.9 °C

HI=103

BIT=34mg/g

SATS=10mg/g

BALDWIN HILLS-1

12,406 ft

151 °C

HI=144

BIT=212mg/g

SATS=81mg/g

SUP. LIM-1

13,080 ft

124.2 °C

HI=232

BIT=87.9mg/g

SATS=34.9mg/g

APEX-1

16,974 ft

183.2 °C

HI=219

BIT=167mg/g

SATS=76mg/g

LA MIRADA 46-1

11,988 ft

137.2 °C

HI=217

BIT=141mg/g

SATS=25mg/g

APEX-1

20,219 ft

213.9 °C

HI=84.4

BIT=101mg/g

SATS=40mg/g

RETENTION TIME IN MINUTES RETENTION TIME IN MINUTES

10 20 30 40 50 60 70 80 10 20 30 40 50 60 70 80

KLC “A” 72-4 samples at 179.6° (17,160 ft, “94/2.97”) and 

180.6°C (17,269-17,272 ft) samples are similar (two top left 

chromatograms, fig. 8). Those of the aromatic HCS are less 

similar (top two right chromatograms, fig. 8), partly because 

higher methyl-naphthalene concentrations suppress the 179.6°C 

(17,160 ft) sample’s aromatic hump. The lower methyl-naphthalene concentration in the 180.6°C sample is from a moderately greater loss of lighter HCS in this sample compared to the 

179.6°C sample. This loss is also manifested by the greater 

slope of the dashed line in the C15- portion of the saturated HCchromatogram of the 180.6°C sample compared to the 179.6°C 

sample (upper two left chromatograms, fig. 8). Otherwise, 

these two saturated-HC chromatograms are almost identical.

ROCK-EVAL analysis of these samples after Soxhlet 

extraction revealed approximately equivalent hydrogen indices 

(82 for the 179.6°C sample, and 127 for the 180.6°C sample). 

Figure 6. Saturated-HC gas chromatograms from Los Angeles-Ventura Basin samples, demonstrating qualitative (maturity) changes from HC generation in hydrogen-poor OM. See figure captions 2-4 for explanation of labeling on chromatograms.
Samples and Methods 15

MILLIGRAMS PER GRAM OF ORGANIC CARBON

BURIAL TEMPERATURE IN °C

DEPTH IN KILOMETERS

30 60

60

70

80

90

100

110

120

130

140

150

170

180

190

200

210

220

90 120 150 180 210 270

2.0

3.0

4.0

5.0

6.0

0 240

399/2.10

47.4/0.19

257.4/1.67

90.3/0.32

212/1.90

164/2.16

452/4.03

222/4.64

146/1.36

94/2.97

39.6/2.02 35.3/2.21

157.3/1.33

95.6/1.14

590/2.26

376

112/1.22

227/1.66

160

The originally higher hydrogen index (227) of the 180.6°C sample was from resins and asphaltenes, in the abundant bitumen of 

this sample (228 mg/g OC), contributing to the S2 peak (Clementz, 1979). Thus, these two shales were originally of equivalent 

organic richness and the much higher bitumen and HC contents 

in the 180.6°C sample can not be from more hydrogen-rich OM. 

Nor can loss of generated HCS to the drilling mud explain the 

difference, because the 180.6°C sample, with higher bitumen 

and HC concentrations, has actually had the greater loss to the 

drilling mud, as demonstrated by the dashed slanted lines (top 

two left chromatgrams, fig. 8). Thus more efficient HC expulsion from the 179.6°C sample is the only apparent remaining 

explanation for the lower HC concentrations in that sample.

The chromatograms from the 214.2°C (20,922-20,925 ft) 

and 214.3°C (20,930 ft) samples are strikingly different from 

each other (bottom four chromatograms, fig. 8). The 214.3°C 

saturated and aromatic HCS have the mature characteristics 

expected for this sample's burial temperature. However, the 

214.2°C saturated HCS have very immature characteristics: (1) 

high pristane/n-C17, phytane/n-C18, and other i-C/n-C ratios; (2) 

a pronounced naphthenic hump; and (3) being largely composed 

of C16-C23 material. The 214.2°C aromatic-HC chromatogram 

also appears quite immature compared to that of the 214.3°C 

sample. Neither the qualitative nor quantitative differences of 

these two samples are related to original richness of their OM, 

because ROCK-EVAL analysis of the two Soxhlet-extracted 

shales revealed that they had equivalent hydrogen indices, 30.6 

for the 214.2°C sample and 23.5 for the 214.3°C sample. The 

higher original hydrogen index of the 214.2°C sample (95.6 

unextracted versus 30.6 extracted) is again due to resins and 

asphaltenes contributing to the S2 peak (Clementz, 1979). Thus, 

the OM in the two samples is equivalent.

The 214.2°C core had obvious visual fractures and slickenslides. It is possible that this rock, when buried, was along an 

oil-migration path and that significant amounts of nonindigenous 

oil were stored in the cracks of this rock. This would account for 

the high saturated-HC and bitumen coefficients of the 214.2°C 

sample relative to the 214.3°C sample (81 and 122 versus 21 and 

27, respectively). Moreover, the cracks and fractures of the 

214.2°C sample would have allowed loss of much of this nonindigenous oil to the drilling mud, resulting in the leached and 

highly immature appearance of that sample’s saturated- and aromatic-HC chromatograms. Whatever the cause, the qualitative 

aspects of the 214.2°C sample's saturated and aromatic HCS are 

most unusual and unexpected.

As an aside, the KCL “A’’ 72-4 20,930 ft saturated- (and 

aromatic-) HC gas chromatograms, were the only chromatograms in this study from rocks with hydrogen-poor OM, at 

150°C or higher, which did not have a significant loss of C15- 

compounds (fig. 8). Different factors unrelated, or only indirectly related, to HC generation and (or) maturity appear to 

result in both significant scatter in the bell-shaped generation 

curves of hydrogen-poor OM (figs. 1, 7) and in profound qualitative differences in saturated- and aromatic-HC gas chromatograms (figs. 2, 3, 4, 6, 8, 10). These factors include variable 

efficiency of HC expulsion, loss of HCS to the drilling fluid during drilling operations, subsurface migrating HCS, possibly variable original organic richess even within one OM type, and no 

doubt yet-unrecognized controls.

Bitumen Composition

Normalized bitumen percentages are plotted in figure 9 for 

the Paloma field samples along with the HC coefficient (lefthand number) and hydrogen index (right-hand number) for each 

sample. Beyond 135°C (beginning of intense HC generation), 

the percentage of saturated HCS progressively increases, 

whereas that of the resins (NSO) continuously decreases, especially above 180°C. This is analogous to the trends observed in 

the Los Angeles Basin (fig. 5). Also, as in figure 5, the percentages of aromatic HCS and asphaltenes, with scatter, remain 

roughly constant. Thus, as with the hydrogen-poor OM in the 

Los Angeles Basin, in the hydrogen-poor OM at Paloma, the 

HCS, resins, and asphaltenes are cogenerated with each other, 

and the resins appear to preferentially thermally decompose 

above 180°C. The minimum in the saturated-HC percentage 

(13.5 percent) in the “33/452’’ sample at 137°C cannot be attributed to this sample having hydrogen-rich OM (hydrogen index = 

452), because the next shallowest sample (“31/164’’) also has a 

low percentage of saturated HCS (17.5 percent), yet it contains 

type III/IV OM (hydrogen index = 164).

Saturated-HC Gas Chromatograms

Satrated-HC gas chromatograms from immature rocks at 

Paloma, somewhat resemble those of the Los Angeles-Ventura 

Basins, with large naphthenic envelopes and a limited carbon 

Figure 7. Plot of the HC coefficient (dots, solid line) and bitumen coefficient (triangles, long-dashed line) versus burial temperature in ° C and 

depth in kilometers for shales from the Paloma Field, Southern San 

Joaquin Valley Basin. Thus, there are two data points for each sample. 

Left-hand number for each sample is the ROCK-EVAL hydrogen index, 

right-hand number is the TOC. See figure 1 caption for further explanation. The “590/2.26” sample (at about 140°C) has an offscale bitumen coefficient of 376.
16 Organic Metamorphism in the California Petroleum Basins

10 20 30 40 50 60 70 80 10 20 30 40 50 60 70

RETENTION TIME IN MINUTES RETENTION TIME IN MINUTES

80

n-9

n-10

n-11 n-11

n-10

ALBEN

PR

PHY

NAP

MNAP

DMNAP

TMNAP

PHEN

MPHEN

DMPHEN

ALBEN

ALBEN

ALBEN

NAP

MNAP

DMNAP

TMNAP

PHEN

MPHEN

DMPHEN

NAP

MNAP

DMNAP TMNAP PHEN

MPHEN

DMPHEN

NAP

MNAP

DMNAP

TMNAP

PHEN

MPHEN

DMPHEN

n-12

n-13

n-14 n-13

n-15 n-15 n-15

n-16

n-17

n-36

n-35

n-34

n-33

i-13

i-14

i-16

n-32

n-31

n-30 n-30

n-35 n-35

n-29

n-28

n-27

n-26

n-25 n-25

n-30 n-30

n-25 n-25 n-24

n-23

n-22

n-21

n-20 n-20 n-20 n-20

PR PR PR

PHY PHY PHY

i-18 i-18 i-18

n-15

i-16

i-15

i-16 i-16

i-15 i-15

i-14 i-14 i-14

i-13

n-19

n-18

i-13 i-13

KCL "A" 72-4

17,160 ft

179.6 °C

HI=94

BIT=88mg/g

SATS=39mg/g

KCL "A" 72-4

17,160 ft

AROS=18mg/g

KCL "A" 72-4

17,269-17,272 ft

180.6 °C

HI=227

BIT=228mg/g

SATS=140mg/g

KCL "A" 72-4

17,269-17,272 ft

AROS=31mg/g

KCL "A" 72-4

20,922-20,925 ft

214.2 °C

HI=95.6

BIT=122mg/g

SATS=81mg/g

KCL "A" 72-4

20,930 ft

214.3 °C

HI=39.6

BIT=27mg/g

SATS=21mg/g

KCL "A" 72-4

20,930-20,925 ft

AROS=5mg/g

KCL "A" 72-4

20,930 ft

AROS=5mg/g

Figure 8. Saturated and aromatic HC gas chromatograms for four deep core samples from the Paloma KCL"A" 72-4 wellbore. See figure 3 caption 

for explanation of labels on the chromatograms. Dashed lines on two chromatograms connect the top of the n-paraffin peaks.
Samples and Methods 17

10/399

59/47.4

48/257

33/452

61/212

96/146

57/94

33/90.3

27/212

228/590

171/227

146/112

21/39.6

111/95.6 81.6/35.3

125/157

31/164

0 10 20 30 40 50 60 70 80 90 100

60

70

80

90

100

110

120

130

140

150

160

170

180

190

200

210

220

SATS

ASP

NSO

AROS

NORMALIZED PERCENTAGE

BURIAL TEMPERATURE IN °C

number range (C15 to C24) over which most saturated HCS occur 

(Ohio A-1, 6,750 ft sample; second chromatogram from top, left 

side; fig. 10). However, differences can also exist between 

immature samples from the two basins as seen in the Ohio A-1 

4,574-4,583 ft sample (top left chromatogram, fig. 10), to wit: 

higher concentrations of n-paraffins at Paloma, a wider carbonnumber range over which most saturated HCS occur, and strong 

odd n-paraffin preferences over n-C23 to n-C33. We attribute 

these differences to slightly different starting OM (a stronger 

influence of terrestrial OM at Paloma) and possibly to different 

depositional conditions in the rocks deposited shallower than 

8,600 ft (2,620 m) at Paloma (Pliocene San Joaquin Formation 

and younger rocks) compared to Los Angeles and Ventura basin 

rocks. The saturated HCS from rocks deeper than 8,600 ft 

(2,620 m) at Paloma (Pliocene Etchegoin Formation and older 

rocks) were similar to, or indistinguishable from, those of Los 

Angeles and Ventura Basin rocks at similar maturities. For 

example, compare the KCL “A” 21-14 8,608 ft sample (101°C, 

third chromatogram on left, fig. 10) with the La Mirada 46-1 

7,732-7,735 ft sample (top left chromatogram, fig. 6). 

ROCK-EVAL data (Price and others, 1999) suggest that 

low-level HC generation occurs at Paloma before mainstage HC 

generation, as interpreted by the inferred gradually increasing 

HC and bitumen coefficients between 30° to 130°C in figure 7. 

This inference is supported by changing qualitative characteristics of the saturated HCS in figure 10 from 100° to 140°C, 

which corresponds to a rank of pre-mainstage HC generation 

(fig. 7). For example, in the KCL “A” 21-14 8,608 ft sample 

(third chromatogram on left, fig. 10) and the KCL-F-71-10 

12,028 ft sample (top right chromatogram, fig. 10): (1) the size 

of the naphthenic envelope is suppressed from generation of 

acyclic HCS and n-paraffins, (2) the biomarker peaks become 

prevalent, and (3) the pristane/n-C17 and phytane/n-C18 ratios 

increase significantly, all compared to shallower samples. These 

qualitative differences could be attributed to an OM-type shift 

with depth at Paloma. However, visual-kerogen analyses 

(unpub. data, L. C. Price) demonstrate a uniform OM type in 

these rocks. Moreover, as discussed above, these same peculiar 

qualitative changes were also observed in saturated HCS from 

Los Angeles and Ventura Basin rocks at these same maturity levels (pre-mainstage HC generation). This observation suggests 

that basically the same starting OM is present in equivalent-age 

rocks from the three basins, at least for the hydrogen-poor OM. 

This hypothesis is supported by carbon-isotopic analyses of the 

saturated and aromatic HCS from mid Miocene rocks with 

hydrogen-poor OM from the three basins (L. C. Price, unpub. 

data). To wit, saturated HCS have a narrow range of δ13C values 

(-25.0 to -23.5) as do aromatic HCS (-24.7 to -23.0), with no 

apparent differences between samples from the three basins

With the commencement and progression of mainstage-HC 

generation at Paloma, as judged by the Anderson 56-35 13,905 

ft, and KCL “A’’ 72-4 15,293-15,302 ft samples (second and 

third chromatograms on right respectively, fig. 10): (1) biomarker peaks decrease and adjacent n-paraffins become increasingly 

dominant; (2) increasing amounts of C14- and C22+ material are 

generated; (3) i-C/n-C ratios decrease as does the naphthenic 

hump; and (4) n-paraffin profiles become more regular. With 

further burial, these maturity changes continue (17,160 ft and 

17,269-17,272 ft samples (two top left chromatograms, fig. 8); 

and 18,286-18,297 ft sample (bottom right chromatogram, fig. 

10). The deepest samples have the mature characteristics 

expected at these 214°C burial temperatures (the 20,930 ft sample (bottom left chromatogram, fig. 8).

The qualitative changes in the Paloma saturated HCS during mainstage-HC generation are indistinguishable from those 

from the hydrogen-poor OM of the Los Angeles-Ventura Basins 

over the same ranks. That the saturated HCS from the different 

areas cannot be discriminated from one another, at any rank 

above 95°C, suggests the same starting OM or similar depositional conditions, or both, for these areas. Lastly, it is noteworthy that the saturated HCS become oil-like only at about 180°C 

and above for the hydrogen-poor OM of both areas.

Hydrogen-Rich OM

HC Generation

Figure 11 is a plot of the HC (dots and solid line) and bitumen (triangles and dashed line) coefficients versus burial temperature for rocks with hydrogen-rich OM, mainly from the Los 

Angeles Basin. All samples had ROCK-EVAL hydrogen indices of at least 350, many with higher values, several with values 

characteristic of type I OM. Hydrogen indices (left-hand number) and TOC contents (right-hand number) are given for each 

sample.

Two features are immediately apparent in figure 11. First, 

two shallower samples at 72.5° and 90.5°C (243E/2.35E and 

363E/1.58E, respectively) have very high HC (215 and 249) and 

bitumen (323 and 372) coefficients. The previously discussed 

243E/2.35E sample (fig. 4, third chromatogram on left, WDFigure 9. Normalized percentages, versus burial temperature, of saturated (SATS) and aromatic (AROS) HCS, resins (NSO), and asphaltenes 

(ASP) in bitumen from rocks from different wells in the Paloma Field, 

Southern San Joaquin Valley Basin. Samples at 162.5°C and higher are 

from the KCL"A" 72-4 wellbore. The HC coefficient (mg saturated plus aromatic HCS/g TOC, left-hand number) and ROCK-EVAL hydrogen index 

(right-hand number) are given for each sample. 
18 Organic Metamorphism in the California Petroleum Basins n-10 i-13 i-14 i-15 i-16 n-15 i-18 PR PHY n-20n-25 n-30 n-31 n-32 n-33 n-34 n-35

OHIO A-1

4574-4583 ft

64.1 °C

HI=399

BIT=23mg/g

SATS=7mg/g

° KCL F 71-10

12.028 ft

132.5 °C

HI=164

BIT=66mg/g

SATS=10mg/g

n-10

i-13

i-14

i-15

i-16 n-15

i-18

PHY

PR

n-20

n-25

n-27

n-28

n-29

n-30

n-31

n-32

n-33

n-34

n-35

i-13

i-14

i-15

i-16 n-15

i-18

PR

PHY

n-20

n-25

n-30

OHIO A-1

6750 ft

84.0 °C

HI=47.4

BIT=111mg/g

SATS=40mg/g

(T.O.C.=0.19)

n-10

i-13

i-14

i-15

i-16 n-15

i-18

PR

PHY

n-20

n-25

n-30

n-31

n-32

n-33

n-34

n-35

ANDERSON 56-35

13,905 ft

149.7 °C

HI=590

BIT=376mg/g

SATS=140mg/g

n-10

n-11

n-12

n-13

n-14

i-13

i-14

i-15

i-16

i-18

n-15

n-17

n-18

n-19

n-20

n-21

n-22

n-23

n-24

PR

PHY

n-25

n-26

n-27

n-28

n-29

n-30

n-31

n-32

n-33

n-34

n-35

KCL A 21-14

8608 ft

101.0 °C

HI=257

BIT=97mg/g

SATS=25mg/g

KCL "A" 72-4

15,293–15,302 ft

162.5 °C

HI=146

BIT=147mg/g

SATS=61mg/g

n-10

i-13

i-14

i-15

i-16

n-15

i-18

PR

PHY

n-20

n-25

n-30

n-35

KCL N 58-32

10,824-10,830 ft

121.5 °C

HI=212

BIT=52mg/g

SATS=15mg/g

n-10

n-11

n-12 i-13

i-14

i-15

i-16

n-15

n-16

i-18

n-17

PHY

PR

n-19

n-20

n-21n-22

n-23

n-24

n-25

n-26

n-27

n-28

n-29

n-30

n-31

n-32

n-33

n-34

n-35

n-14

n-13

n-18

KCL "A" 72-4

18,286–18,297 ft

190.0 °C

HI=112

BIT=185mg/g

SATS=114mg/g

n-10

n-11

n-12

n-13

n-14

n-15

n-16

n-17

n-18

n-19

n-20

n-21

n-22

n-23

n-24

n-25

n-26

n-27

n-28

n-29

n-30

n-31

n-32

n-33

n-34

n-35

i-13

i-14

i-15

i-16

i-18

PR

PHY

n-36

10 20 30 40 50 60 70 80 10 20 30 40 50 60 70 80

RETENTION TIME IN MINUTES RETENTION TIME IN MINUTES
Samples and Methods 19

BURIAL TEMPERATURE IN °C

MILLIGRAMS PER GRAM OF ORGANIC CARBON

0

430/29.5/V

399/2.10/SSJV

391/3.20

291/5.18

500/8.93

388/4.53

416/2.29

560/5.98 652/

4.30/V

390/3.31/V

452/4.03

SSJV

834/4.59

535/6.12

406/3.04

517/3.01V

467/4.54

510/1.27 388/3.63

404/3.54 500/3.66

630/5.40

556/5.40

551/5.27

372/2.60

243E/2.35E

547/1.76

363E/1.58E

382/3.99

50

50

60

70

80

90

100

110

120

130

140

150

160

170

180

190

200

100 150 200 250 300 350

441/

3.12V

700/2.13

107, 3,017 ft) was hypothesized to be a biodegraded oil which 

migrated into the shale from a deeper reservoir with biodegraded oil, via caprock leakage. This fact and the lower hydrogen index (243) of the extracted, versus the unextracted (372), 

sample (table 1) would suggest that this rock contains type III, 

and not type II/III, OM. Saturated- and aromatic-HC gas chromatograms of the other sample (363E/1.58E) are immature. 

Thus, the high HC concentrations of this sample are due neither 

to “oil staining’’ nor to mainstage HC generation. The 363E/

1.58E sample is yet another example of high concentrations of 

immature bitumen and HCS which are occasionally present in 

immature shales from the California basins. Based on ROCKEVAL analyses (Price and others, 1999), other immature rocks 

with hydrogen-rich OM from these basins at burial temperatures 

below 120°C also have abnormally high bitumen contents. Gas 

chromatography suggests that the slightly elevated HC coefficients, and significantly elevated bitumen coefficients, of the 

388/3.63 and 404/3.54 samples (fig. 11, both about 162°C) 

appear to be due to low-level HC generation. Gas chromatography could not be performed on the 551/5.27 sample (about 

132°C, fig. 11) and thus the cause of the slightly elevated HC, 

and moderately elevated bitumen, coefficients of that sample is 

unknown. 

The second obvious feature of figure 11 is that it lacks even 

an ill-defined bell-shaped curve at 120°C and above, temperatures where HC generation is expected from the data of Philippi 

(1965), Price and others (1999), and figures 1 and 7. One might 

argue for a vague bell-shaped curve for the bitumen coefficient 

(dashed line) from 105° to 161.5°C with a sharp drop thereafter. 

However, the high hydrogen indices (500-700) of the rocks 

between 164° to 197°C argue against mainstage-HC generation 

occurring here. Moreover, the HC coefficient (solid line) with 

scatter, remains essentially invariant from 105° to 197°C, and 

the three deepest samples of figure 11 have some of the lowest 

values of the entire sample base.

In figure 1, which shows rocks from the same areas as figure 11 but with hydrogen-poor OM, intense HC generation 

begins by 100°C, maximizes by 165°C and is largely complete 

by 210°C. At Paloma (fig. 7), intense HC generation commences in rocks with hydrogen-poor OM by 135°C, maximizes 

by 180°C, and is also largely complete by 210°C. In contrast, in 

figure 11, the persistent high hydrogen indices in samples at 

150° to 198°C, and the lack of defined increases in either the 

bitumen or especially the HC coefficients, both dictate the conclusion that mainstage-HC generation has not even begun by 

198°C in these rocks. As discussed in Price (1988), an equivalent situation exists with the 21,500 ft (6,552.9 m) Shell Taylor 

653 wellbore, Ventura Avenue Field, Ventura Basin. This well, 

with a 210°C bottom-hole temperature, encountered the 

Miocene Santa Margarita Formation at about 16,000 ft (4,987 

m), at a burial temperature of 155°C. All measured maturity 

indices were suppressed in these 2 to 5 percent TOC rocks with 

hydrogen-rich OM from 155° to 210°C and the threshold of 

intense HC generation was not recognized in these rocks to total 

depth (John Castaño, Shell Oil, oral commun., 11/5/1985). 

Unpublished analyses carried out in 1999 on the rocks of this 

well with hydrogen-rich OM by the author demonstrate that 

mainstage C15+ HC generation actually commences in this well 

at 196.7°C and 6,218 m. This paradox of high-temperature generation with hydrogen-rich OM is unexpected by existing paradigm. Moreover, because intense HC generation has not yet 

begun by 200°C in figure 11, the declines from the maxima of 

the bell-shaped curves of figure 1 beyond 150°C, and of figure 7 

beyond 180°C, cannot be from HC destruction. 

Bitumen Composition

The normalized compositional percentage of the bitumen 

from the samples of figure 11 are given in figure 12, where profoundly different trends are present compared to the two equivalent plots for hydrogen-poor OM (figs. 5 and 9). The shallowest 

sample in figure 12 is a 29.6 percent TOC shale with type II-S 

OM from the Monterey Formation, Ventura Basin. This 

unweathered quarry sample from Naples Beach, Ventura Co., 

Calif., (supplied by M. D. Lewan, U.S. Geological Survey, 

sample ML-91-16) has never been hotter than 40°-50°C (Caroline Isaacs, U.S. Geological Survey, oral commun., 6/94). The 

low content of saturated HCS (4.0 percent) in the shallowest 

sample is because of the sample’s extreme immaturity, and 

agrees with the normalized percentages of saturated HCS (1.03 

to 6.03 percent) that Katz and Elrod (1983) reported in bitumens 

Figure 10 (previous). Saturated-HC gas chromatograms from Paloma 

Field (Southern San Joaquin Valley Basin) samples demonstrating qualitative (maturity) changes from HC generation. See figure captions 2-4 for 

explanation of labeling on chromatograms.

Figure 11. Plot of the HC coefficient (dots, solid line) and bitumen coefficient (triangles, dashed line) versus burial temperature in °C for shales 

with hydrogen-rich OM (hydrogen index >350) from the California petroleum basins. Left-hand number at each sample point is the ROCK-EVAL 

hydrogen index, right-hand number is TOC; “E” after these numbers refers to Soxhlet-extracted samples. SSJV is a Southern San Joaquin Valley Basin sample. All other samples are from the Los Angeles Basin.
20 Organic Metamorphism in the California Petroleum Basins

extracted from 23 Middle Miocene to Lower Pliocene immature 

rocks (1,236 to 3,306 ft, 377.2 to 1,007.5 m burial depths) with 

type II OM from offshore California (fig. 16, discussed below). 

Thus, the 2.70/430 V sample is representative of immature 

hydrogen-rich OM in the California petroleum basins. Between 

50° and 68°C, in figure 12, the saturated-HC percentage sharply 

increases to 44 percent at 68°C, the second highest percentage 

of the sample set. Considering both the data of Katz and Elrod 

(1983) and of this study, this increase can only be due to early 

HC generation between 40° and 70°C from cracking of weak 

bonds (perhaps acids, alcohols) to saturated HCS. 

These profound qualitative changes in bitumen composition from 40 o to 70°C are paralleled by equally profound qualitative changes in saturated-HC gas chromatograms. This is 

evidenced by comparing chromatograms from the most immature samples of this paper with those (not shown here) from the 

very immature offshore California shales of both Katz and 

Elrod (1983, fig. 5) and Claypool and others (1979, fig. 1). The 

Claypool and others (1979) and Katz and Elrod (1983) chromatograms completely lack n-paraffins, with the only peaks 

being acylic saturated HCS, or biomarkers, or simply naphthenic humps. B. Katz (Texaco, written commun., 11/13/1995) 

notes recent data suggesting that in some of the Cooperative 

Monterey Organic Geochemical Study (CMOGS) Naples Beach 

samples, more than 80 percent of the saturated HCS may be 

made up by the biomarker bisnorhopane (also evident in the 

data of Katz and Elrod, 1983). However, saturated-HC chromatograms of this study from even the most immature rocks 

with hydrogen-rich OM (see the WD-401, 2,411 ft sample, 

burial temperature 62.1°C, top left chromatogram, fig. 13) had a 

complement of n-paraffins and a much more "mature" appearance. Isaacs and others (1993) report that by inorganic thermometers, the maximum burial temperatures reached by the 

Naples Beach section were 40° to 50°C, whereas the Lions 

Head section was exposed to 85° to 100°C. Bitumen from 

Lions Head samples of the CMOGS study, although still immature, is significantly more mature in appearance than that from 

Naples Beach samples. For example, Lions Head bitumen has 

significantly higher n-paraffin concentrations than bitumen from 

the Naples Beach sample suite (Barry Katz, Texaco, written 

commun., 11/13/95). Thus, data from other investigators support the observations of this study regarding profound qualitative changes in the bitumen from rocks with hydrogen-rich OM 

over burial temperatures of 40° to 70°C. These strong qualitative differences in chromatograms between such low-temperature samples can only be caused by low temperature (40°-

70°C) generation processes which also cause the strong qualitative changes in the bitumen over these temperatures (fig. 12). 

However, this is a temperature interval which usually does not 

receive attention in petroleum-geochemical studies, often 

because of a lack of samples. 

From 68°C to the deepest samples of figure 12, with scatter, the percentage of saturated HCS decreases. In fact, the second hottest sample (181.4°C) has the second-lowest saturatedHC content (6.7 percent). Beyond 90°C, the percentages of aromatic HCS and resins remain roughly constant. In contrast, 

beyond a minimum at 68°-75°C, the percentage of asphaltenes 

increases with scatter. The compositional changes over the 

entire temperature range in figure 12 suggest that, contrary to 

the quantitative data (fig. 11), some type of low-level HC generation is occurring with increasing burial. Moreover, the much 

different bitumen compositional trends versus burial temperature in figure 12, compared to bitumen compositional trends for 

hydrogen-poor OM (figs. 5, 9), dictate that the reaction path of 

the hydrogen-rich OM is markedly different than that of hydrogen-poor OM.

Lewan (1991) observed the reaction pathway: kerogen --> 

asphaltenes + resins--> HCS in hydrous-pyrolysis experiments 

on the shale of the Upper-Devonian to Lower-Mississippian 

Woodford Formation (type II OM). He also noted that this reaction pathway has long been observed in oil-shale retorting and 

also has been previously suggested for natural HC generation. 

Furthermore, Lewan has observed this reaction pathway for 

other rocks with hydrogen-rich OM (M. D. Lewan, U.S. Geological Survey, oral commun., 4/94). This reaction pathway also 

occurred in rocks with hydrogen-rich OM in the experiments of 

Wenger and Price (1991), and thus appears applicable to all 

hydrogen-rich OM. Therefore, that the percentage of saturated 

HCS is still decreasing at 198°C (fig. 12), supports the conclusion drawn from the figure 11 data that mainstage HC generation has not yet begun in these rocks with hydrogen-rich OM at 

temperatures as high as 198°C. 

Saturated-HC Gas Chromatograms

Eight representative saturated-HC gas chromatograms 

from the samples of figures 11 and 12 are shown in figure 13. 

Saturated-HC chromatograms from immature rocks with hydrogen-rich OM (WD-401, 2411 ft, top left chromatogram, fig. 13) 

have the same characteristics as those with type III OM (Reyes147 and Reyes-1 samples, top left two chromatograms, fig. 4), 

namely: (1) most of the saturated HCS concentrated over C14 to 

C21; (2) a pronounced naphthenic envelope over limited carbon 

ranges (C13 to C20); (3) a lack of significant concentrations of 

C22+ n-paraffins with an almost complete absence of C27+ 

(waxy) n-paraffins; (4) a noticeable lack, or reduced concentrations, of C13- HCS (the WD-401, 2,411 ft sample, top left chromatograms fig. 13, is an exception); and (5) moderate i-C/n-C 

ratios. 

Although several exceptions existed, primarily between 

burial temperatures of roughly 95° to 145°C, saturated-HC 

chromatograms from rocks with hydrogen-rich OM (fig. 13) 

had the same qualitative changes as in chromatograms from 

rocks over the same temperature interval with hydrogen-poor 

OM from the Los Angeles-Ventura (fig. 6) and Southern San 

Joaquin Valley (fig. 10) Basins. These changes included (1) relative increases in C20 to C26 n-paraffins and C15- compounds; 

(2) a moderation of the naphthenic envelope from generation of 

C15 to C20 n-paraffins and acyclic saturated HCS; (3) increases 

in i-C/n-C ratios especially pristane/n-C17 and phytane/n-C18; 

and (4) a dramatic increase in biomarker peak heights. For 

example, compare Seal Beach, 6,045-7,901 ft (103.4 ° C, second left chromatogram from top, fig. 13) with both La Mirada 

46-1, 7,732-7,735 ft (92.9°C, top left chromatogram, fig. 6) and 

with Shell KCL “A” 21-14, 8,608 ft (101.0°C, third left chromatogram from top, fig. 10). Also compare WD-102, 6,071 ft 

(124.3°C, third left chromatogram from top, fig. 13) with Sup. 
Samples and Methods 21

BURIAL TEMPERATURE IN °C

SATS

AROS

NSO

ASP

NORMALIZED PERCENTAGE

0 10 20 30 40 50 60 70 80 90 100

50

60

70

80

90

100

110

120

130

140

150

160

170

180

190

200

2.70/430/V

20/382

249/372

10/399/SSJV

11/391

19.7/291

16/500

215/547

63.3/416

35/390

28.9/388

37/560

27/652V

87.4/551

33/406

55.4/441V

65/834

54.1/535

33/452

 SSJV

84/388

76.7/404

47/517/V

48.8/467

43/510

30.4/500

19/630

22/556

35/700

Lim.-1 13,080 ft (124.2°C, second left chromatogram from top, 

fig. 6) and Ohio KCL-F-71-10, 12,028 ft (132.5°C, top right 

chromatogram, fig. 10). All these chromatograms have the 

same characteristics in spite of significant OM-type and geographic variations. This observation suggests that the same 

starting OM was present both in these different basins and in 

different depositional settings of these basins. 

The hypothesis that all (or most of) the southern California 

basin Miocene kerogens had the same, or nearly the same, starting OM, in spite of widely different ending OM types, is supported by carbon-isotopic analyses of the saturated and 

aromatic HCS extracted from these rocks. Whether the OM is 

hydrogen-rich, or hydrogen-poor, both the saturated and aromatic HCS have a narrow range of δ13C values (-25.0 to -23.5 

and -24.7 to -23.0, respectively). Moreover, kerogens from different locations in these basins also have a narrow range of 

δ13C values (-21.00 to -22.80), with no differences between 

hydrogen-rich and hydrogen-poor OM.

Curiale and others (1985) noted a similarity in biomarker 

distributions among Miocene Monterey oils and rock extracts 

from the Los Angeles, Ventura, Santa Maria, and San Joaquin 

Valley Basins. This similarity was surprising to them, given the 

different basins, field locations, and the diverse lithology of the 

Monterey rocks. Those authors also concluded that a similar 

starting OM was present in these different locations. Caroline 

Isaacs, on the basis of data generated by the Cooperative 

Monterey Organic Geochemical Study (CMOGS), concluded 

that all the OM in Monterey rocks was the same, despite widely 

variable depositional settings for the different CMOGS samples 

(C. Isaacs, then U.S. Geological Survey, written commun., 12/1/

95).

If indeed, all (or most of) the Miocene kerogens in southern 

California basin shales started from the same OM, irrespective 

of the final hydrogen richness of the kerogens, then depositional 

conditions must have played the major role in determining final 

organic facies in these basins.

In figure 13, the biomarker peaks in the Lloyd-185, 14,990-

15,074 ft (146.4°C)(bottom left chromatogram) sample are moderated compared to the two shallower chromatograms (second 

and third chromatograms on left, fig. 13), an observation applying to most other shallower samples with burial temperatures 

between 80° to 140°C and with hydrogen-rich OM. This trend 

was also observed in saturated HCS from hydrogen-poor OM 

over the same burial temperatures. For example, compare the 

Lloyd-185 (146.4°C) chromatogram (bottom left chromatogram, 

fig. 13) with the Anderson 56-35, 13,905 ft (149.7°C) chromatogram (second chromatogram from top right, fig. 10). Again, the 

two are remarkably similar, suggesting the same starting OM 

both in the different basins and in different depositional settings 

in the basins.

Between 145° and 197.7°C to (the highest-temperature 

sample studied), saturated-HC chromatograms from rocks with 

hydrogen-rich OM had significant qualitative differences compared to chromatograms from lower-temperature rocks with 

hydrogen-rich OM (fig. 13). This observation demonstrated that 

continuing low-level HC generation was occurring in these 

deeper rocks. A most notable characteristic was increased C14-

and C22+ material relative to C15 to C21 range compounds. Consequently, the higher-temperature chromatograms (four right 

chromatograms, fig. 13) always had more uniform n-paraffin 

distributions relative to lower-temperature samples (four left 

chromatograms, fig. 13). However, the highest-temperature 

samples with hydrogen-rich OM still had irregular n-paraffin 

profiles compared to those from high-temperature samples with 

hydrogen-poor OM. Thus, compare the n-paraffin profiles of the 

WC-403 9,412 ft and 10,387 ft samples (bottom two right-hand 

chromatograms, fig. 13, hydrogen-rich OM) with those of the 

18,286-18,297 ft (bottom right chromatogram, fig. 10), 20,219 ft 

(bottom right chromatogram, fig. 6), and 20, 930 ft (bottom left 

chromatogram, fig. 8) samples, all with hydrogen-poor OM. 

In rocks with hydrogen-rich OM, between 145° and 

197.7°C, within the saturated HCS, certain maturity indices 

could reverse themselves, with no index constantly increasing 

and remaining elevated. For example, selected i-C/n-C ratios, 

could have significantly more mature values than other indices in 

the same chromatogram, or the relative heights of biomarker 

peaks compared to adjacent n-paraffins could reverse themselves 

between samples. Also note that even though they are at equivalent burial temperatures, the Alamitos 48-A 158°C chromatogram (top right chromatogram, fig. 13) appears more mature 

Figure 12. Normalized percentages, versus burial temperature of 

saturated (SATS) and aromatic (AROS) HCS, resins (NSO), and asphaltenes (ASP) in bitumen from rocks with hydrogen-rich OM (hydrogen index >350) from the California (principally Los AngelesVentura) petroleum basins. The HC coefficient (mg saturated plus aromatic HCS/g OC, left-hand number) and the ROCK-EVAL hydrogen 

index (right-hand number) are given for each sample. See figure 11 

caption for explanation of letters next to samples.
22 Organic Metamorphism in the California Petroleum Basins n-10 i-13i-14 i-15 i-16 n-15 i-18PR PHY n-20 n-25 n-30

WD-401

2411 ft

62.1 °C

HI=382

BIT=38mg/g

SATS=12mg/g

ALAMITOS 48-A

12,655-12,664 ft

158 °C

HI=510

BIT=119mg/g

SATS=11mg/g

n-10

i-13

i-15

i-14

i-16 n-15

i-18

PHY

PR

n-20

n-25

n-30

n-31

n-32

n-33

SEAL BEACH

6045-7901 ft

95.0-117.7 °C(103.4 °C)

HI=388

BIT=49.8mg/g

SATS=16.4mg/g

n-10

i-13

i-14

i-15

i-16 n-15

i-18

PRPHY

n-20

n-25

n-28

n-29

n-30

n-31

LLW-1

10,250-10,254 ft

161.29 °C

HI=388

BIT=189mg/g

SATS=40mg/g

n-10

i-13

i-14

i-15

i-16

n-15

i-18 PR

PHY

n-20

n-25

n-27

n-28

n-29 n-30

n-31 n-32

n-33

WD-102

6071 ft

124.3 °C

HI=834

BIT=135mg/g

SATS=40mg/g

n-10

i-13

i-14

i-15

i-16 n-15

i-18

PR

PHY

n-20

n-25

n-26

n-27

n-28

n-29

WC-403

9412 ft

181.8 °C

HI=556

BIT=58mg/g

SATS=4mg/g

n-10

n-11

i-13

i-14

i-15

i-16 n-15

i-18

PR

PHY

n-20

n-25

n-27

n-28

n-29

n-30

n-31

n-32

n-33

LLOYD-185

14,990-15,074 ft

146.6 °C

HI=441

BIT=84.7mg/g

SATS=34.1mg/g

n-10

n-11

n-12 i-13

i-14 n-13

i-15 n-14

i-16 n-15

n-16

i-18 n-17

n-18

PR

PHY n-19

n-20

n-21

n-22

n-23

n-24

n-25

n-26

n-27

n-28

n-29

n-30

n-31

n-32

n-33

n-34

WC-403

10,387 ft

197.7 °C

HI=700

BIT=85mg/g

SATS=15mg/g

n-10

n-11

n-12

n-13

i-13

i-14

i-18

PR

PHY

n-15

n-16

n-17

n-18

n-19

n-20

n-21

n-22

n-23

n-24

n-25

n-26

n-27

n-28

n-29

n-30

n-31

n-32

n-33

n-34

n-14 i-15

i-16

10 20 30 40 50 60 70 80 10 20 30 40 50 60 70 80

RETENTION IN TIME MINUTES RETENTION IN TIME MINUTES
Discussion 23

than the LLW-1 161.2°C chromatogram (second chromatogram 

from top right, fig. 13) which has significantly higher i-C/n-C 

ratios and more prominent biomarker peaks. On the other hand, 

note the prominent i-C14 peak in the Alamitos 48-A 158oC chromatogram. Thus, no saturated HC-chromatogram from a rock 

with hydrogen-rich OM had an overall mature appearance, no 

matter what the burial temperature.

All saturated-HC chromatograms from rocks with hydrogen-rich OM at and above 150°C had three characteristics (fig. 

13): (1) elevated concentrations of C14- material compared to all 

but one example (20,930 ft sample, bottom left chromatogram, 

fig. 8) from rocks with hydrogen-poor OM at equivalent temperatures; (2) irregular (ragged) n-paraffin profiles; and (3) overall 

immature appearances, although some maturity indices in the 

chromatogram could have “mature’’ values.

The changes in qualitative characteristics of the saturatedHC-chromatograms from rocks with hydrogen-rich OM versus 

increasing burial temperature (fig. 13), like the bitumen compositions of figure 12, demonstrate that some form of HC generation is occurring in these rocks. However, the high hydrogen 

indices (as much as 700), the low saturated-HC coefficients (4 to 

15 mg/g OC), and the low normalized percentages of saturated 

HCS in the bitumen of these rocks, all demonstrate that mainstage HC generation has not commenced in these rocks, contrary to the situation in rocks with hydrogen-poor OM at 

equivalent temperatures. This observation may explain why 

rocks with hydrogen-rich OM at temperatures of 150°C and 

greater have C14- saturated HCS. That is because these rocks 

have not entered mainstage-HC generation and thus have not yet 

generated significant amounts of HC gas. Therefore, there is little gas to cause a loss of what C14- HCS have been generated, 

either to expulsion or to the drilling mud during drilling operations. 

The presence of C14- saturated HCS almost exclusively in 

the rocks of this study at or above 150°C, but only with hydrogen-rich OM, is an important observation. Moreover, the abundant C14- material in the KCL “A’’ - 72-4, 20,930 ft 

chromatogram (bottom left, fig. 8) demonstrates that the general 

lack of C14- material in high-temperature rocks with hydrogenpoor OM cannot be due to a lack of generative capability for 

these compounds from hydrogen-poor OM. Lastly, saturatedHC gas chromatograms from rocks at high temperatures, and 

with hydrogen-rich OM, retain an overall immature appearance 

simply because these rocks have not yet entered mainstage-HC 

generation.

Discussion

Suppression of Organic Metamorphism in Hydrogen-Rich 

OM

Figure 14 is another example of the significant suppression 

of organic metamorphism always observed in rocks with hydrogen-rich OM at elevated temperatures in the southern California 

basins. In figure 14, data are plotted from samples with burial 

temperatures between 158.0° to 176.2°C, thus HC generation 

should be underway. These samples also have a wide hydrogen-index range. The best indication of HC generation is direct 

measurement of generated HCS, e.g., the HC coefficient. This 

parameter, and the percentage composition of the extracted 

bitumen, for seven different samples are plotted in figure 14, all 

versus hydrogen index. As the hydrogen index increases, the 

HC coefficient strongly decreases, from values of around 100 

mg/g OC for samples with hydrogen indices of 100-150, to 19 

mg/g OC for a hydrogen index of 630. Concurrently, elevated 

percentages (60 percent and above) of total HCS in the 

extracted bitumen in low-hydrogen-index rocks strongly 

decrease with increasing hydrogen index (fig. 14). 

Comparison of individual sample pairs with widely different hydrogen indices, but at similar elevated burial temperatures 

(>150°C), invariably demonstrates that the high-hydrogenindex sample is significantly less mature in appearance. For 

example, compare the hydrogen-rich OM WC-403, 9412 ft 

sample (181.8°C, second right-hand chromatogram from bottom, fig. 13) with hydrogen-poor OM samples at equivalent 

temperatures: Apex-1, 16,974 ft (183.2 ° C, middle right chromatogram, fig. 6); KCL “A’’ 72-4, 17,160 ft and 17,269-17,272 

ft (179.6°C and 180.6°C respectively, top two left chromatograms, fig. 8). Also, compare the hydrogen-rich OM WC-403, 

10,387 ft sample (197.7°C, bottom right chromatogram, fig. 13) 

with hydrogen-poor OM samples at slightly lower or higher 

temperatures: KCL “A’’ 72-4, 18,286-18,297 ft sample 

(190.0°C, bottom right chromatogram, fig. 10), KCL “A’’ 72-4 

20,930 ft sample (214.3°C, bottom left chromatogram, fig. 8) or 

the Apex-1, 20,219 ft sample (213.9°C, bottom right chromatogram, fig. 6). Lastly, compare the hydrogen-rich OM LLW-1 

(161.2°C, second chromatogram from right top, fig. 13) and 

Alamitos 48-A (158.0°C, top right chromatogram, fig. 13) samples, with the hydrogen-poor OM KCL “A’’ 72-4, 15,293-

15,302 ft sample (162.5°C, third chromatogram from right top, 

fig. 10). In these cases, and others not shown, the hydrogen-rich 

OM sample was always significantly less mature in appearance 

than the hydrogen-poor OM sample as judged by: (1) more 

irregular n-paraffin profiles, (2) more prominent biomarker 

peaks, (3) large, irregular, or bimodal naphthenic envelopes, and 

(4) higher i-C/n-C ratios.

In this study, the C25+ portion of saturated-HC gas chromatograms was the most consistent and best index to monitor 

maturity changes versus temperature. It is well known that with 

increasing HC generation, the n-paraffin peaks over this carbonnumber range become significantly larger than adjacent biomarker peaks. In all cases examined, for sample pairs at equivalent 

temperatures, the chromatogram from more hydrogen-rich OM 

was always less mature (higher biomarker peaks relative to 

adjacent n-paraffins) than that from hydrogen-poor OM at temperatures of 150°C and higher. Three examples are given in figure 15. The hydrogen-poor OM Baldwin Hills sample at 

151.0°C clearly has a more mature appearance than the 467 

hydrogen index Bryant Estate sample also at 151.0°C (two top 

chromatograms, fig. 15). This observation is also true for the 

other two sample pairs. Moreover, the 16,974 ft Apex-1 sample 

(bottom left, fig. 15), with hydrogen-poor OM is in the middle 

Figure 13. (previous page) Saturated-HC gas chromatograms from 

rocks with hydrogen-rich OM of the Los Angeles-Ventura Basins demonstrating qualitative (maturity) changes versus burial temperature. See 

figure captions 2-4 for explanation of labeling on chromatograms.
24 Organic Metamorphism in the California Petroleum Basins

NORMALIZED PERCENTAGE

0 20 40 60 80 100 10 30 50 70 90 110

HC COEFFICIENT

 mg/g OC

HYDROGEN INDEX

650

550

450

350

250

150

AROS

NSO

ASP

SATS

167.4

164.0

158.0

161.2

172.2

162.5

176.2

of mainstage HC generation, and has a high saturated-HC coefficient (76.1 mg/g). By contrast, the hydrogen-rich member of 

this sample pair (WC-403, 9,412 ft, 181.8°C, bottom right, fig. 

15) has not yet begun mainstage generation and consequently 

has a low saturated HC coefficient (4 mg/g), in spite of its high 

burial temperature.

Significant differences between the reaction kinetics of 

other examples of hydrogen-rich OM and more thermally labile 

hydrogen-poor OM has been previously discussed (Price, 1988, 

1991). Numerous examples of these differences have also been 

presented both in Price and others (1999) and this paper. These 

differences are also apparent in the data of Wenger and Price 

(1991). This divergence in reactivity manifests itself by Ro suppression in hydrogen-rich OM (Price and Barker, 1985). However, in this study, all aspects of organic metamorphism, 

including mainstage HC generation, are suppressed in hydrogenrich OM, compared to hydrogen-poor OM, due to, among other 

controls, the stronger bonds in hydrogen-rich OM. This significant suppression of HC generation has strong exploration implications.

Origin of High Concentrations of Immature HCS

As discussed above, the Reyes-147 and Taylor-315 samples (second and fourth chromatograms on left, fig. 4) have 

unexpectedly high HC concentrations for their burial temperatures, yet the saturated and aromatic HC chromatograms for 

these samples are quite immature in appearance. Because this is 

characteristic of most immature samples of this study with 

abnormally high HC concentrations, such samples cannot have a 

significant component of oil from staining. 

Other investigators have also found abnormally high concentrations of extractable HCS and bitumen in immature shales 

in California. For example, Claypool and others (1979), in their 

study of Pliocene and Miocene shales from the outer continental 

shelf OCS-CAL 78-164-1 wellbore reported very high HC coefficients (81 to 187 mg/g OC) and very high bitumen coefficients 

(159 to 346 mg/g OC) in some of their immature samples. 

Because these bitumens and HCS had very immature appearances, they could not have originated from staining by oil. Claypool and others (1979) concluded that the OM in the shales they 

studied could generate large amounts of HCS at very immature 

ranks. However, other immature shales in their sample set had, 

for their maturity, normal HC (11 to 34 mg/g OC) and bitumen 

(29.7 to 80 mg/g OC) coefficients, seemingly contradicting this 

hypothesis. Taylor (1976, p. 25) also noted that shales from offshore southern California could have abnormally high carbonnormalized extractable bitumen and HCS. Telnaes and others 

(in press) also observed high contents of extractable bitumen 

(bitumen coefficients of 100-460 mg/g OC) in very immature 

shales of the lower Pliocene Sisquoc and upper Miocene 

Monterey Formations in the OCS-315-1 (offshore Santa Maria 

Basin) wellbore. Kruge (1983) noted very high contents of 

extractable bitumen in some immature Monterey shales that he 

studied from the Lost Hills oil field, San Joaquin Valley Basin. 

He attributed these high concentrations to migrated HCS, 

although he noted some could also be indigenous. Curiale and 

others (1985) examined Monterey shales (and oils) from the 

Santa Maria Valley, San Joaquin Valley, Ventura, and Los Angeles Basins. They found high bitumen coefficients (118 to 437 

mg/g OC) in immature shales at shallow to moderately shallow 

burial depths (675 to 2,179 m). Deeper samples also had elevated bitumen coefficients, but immature biomarker distributions 

in these samples suggested that mainstage-HC generation, if 

commenced at all, was not advanced.

Much of this previous work which was just discussed 

involved Monterey shales, and thus most of the above investigators concluded that the occurrence of abnormally high bitumen 

concentrations at immature ranks is peculiar to Monterey Formation rocks. However, high bitumen concentrations at immature ranks were also found in rocks other than the Monterey 

Formation in some of these studies. Moreover, Monterey rocks, 

and the OM therein, have highly variable lithologies, and thus 

were deposited under highly variable conditions in the different 

basins examined in the above studies. Thus, abnormally high 

bitumen concentrations cannot be ascribed as a feature unique to 

Monterey deposition. Lastly, this study found abnormally high 

concentrations of immature bitumen and HCS in all age rocks 

examined and in all basins studied. This phenomenon is characteristic of all rocks and all OM types of late Neogene deposition 

in the California basins. Abnormally high bitumen concentrations have also been observed in immature sediments from the 

Sea of Japan and the Bohai Basin (Barry Katz, Texaco, written 

commun., 11/13/95). However, it is unclear from whence these 

elevated concentrations of immature HCS originate. For example, were they incorporated into the shales at deposition or were 

they generated from kerogen moities with low activation energies?

Data from Katz and Elrod (1983) add insight to this question. They analyzed 23 shallow (377.2 to 1,007.5 m) midFigure 14. Plots of normalized bitumen composition and the HC coefficient (mg of saturated plus aromatic HCS/g TOC) versus the ROCK-EVAL 

hydrogen index for samples of this study at burial temperatures of 158.0°

to 176.2°C. In the normalized-percentage (bitumen composition) plot, 

SATS are saturated HCS, AROS are aromatic HCS, NSO are resins, and 

ASP are asphaltenes. Burial temperatures (in °C) are given for each data 

point in the HC coefficient plot.
Discussion 25

BALDWIN HILLS

12,933 ft

151.0 °C

HI=144

BIT=212mg/g

SATS=81mg/g

BRYANT ESTATE

11,433 ft

151.0 °C

HI=467

BIT=98mg/g

SATS=23mg/g

KCL "A" 72-4

15,293-15,302 ft

162.5 °C

HI=146

BIT=147mg/g

SATS=61mg/g

LL&W-1

10,250-10,254 ft

161.2 °C

HI=388

BIT=189mg/g

SATS=40mg/g

APEX-1

16,974 ft

183.3 °C

HI=219

BIT=168mg/g

SATS=76mg/g

WC-403

 9412 ft

181.8 °C

HI=556

BIT=58mg/g

SATS=4 mg/g

n-26

n-27

n-28

n-29

n-30

n-31

n-32

n-33

n-34

n-35

n-36

n-26

n-27

n-28

n-29

n-30

n-31

n-32

n-33

n-34

n-35

n-36

n-26

n-27

n-28

n-29

n-30

n-31

n-32

n-33

n-34

n-35

n-36

n-26

n-27

n-28

n-29

n-30

n-31

n-32

n-33

n-34

n-35

n-36

n-26

n-27

n-28

n-29

n-30

n-31

n-32

n-33

n-34

n-35

n-36

n-26

n-27

n-28

n-29

n-30

n-31

n-32

n-33

n-34

n-35

n-36

60 65 70 75 80 60 65 70 75 80

RETENTION TIME IN MINUTES RETENTION TIME IN MINUTES

Miocene to lower-Pliocene organic-rich shales from the Deep 

Sea Drilling Project (DSDP) Site 467, offshore southern California. Some of their data are in figure 16. The TOC contents for 

these shales ranged from 1.71 to 9.69 percent (averaging around 

3 percent, fig. 16). Kerogen elemental hydrogen to carbon (H/C) 

ratios for 19 of the 23 shales so analyzed ranged from 1.26 to 

1.40, values characteristic of type II OM. The HC coefficients 

calculated from the Katz and Elrod (1983) data are low, ranging 

from 3.25 to 15.2 mg/g OC, and total HCS compose less than 

15 percent of the extractable OM in all samples, with saturatedHC percentages ranging from 1.03 to 4.68 percent for all but 

one sample (fig. 16). Resins, and especially asphaltenes, comprise most of the extractable OM. Most bitumen coefficients 

are moderately high to high (fig. 16, 72.5 to 152.8 mg/g OC). 

However, these are misleading values because most of the bitumens are asphaltenes (55.14 to 86.91 percent). Moreover, in 

Figure 15. Saturated-HC gas chromatograms of three sample pairs (hydrogen-rich versus hydrogen-poor OM) at equivalent burial temperatures 

over the C26 to C36 interval. The n-paraffins are labeled by their respective carbon number. See figure captions 2-4 for explanation of labeling on 

chromatograms.
26 Organic Metamorphism in the California Petroleum Basins

DEPTH IN METERS 

TOC H/C mg BIT/g OC

BITUMEN

NORMALIZED 

PERCENT

mg HCS 

gOC

0

2

4

6

8

10

1.25

1.301.35

1.40

3

7

1115

30

60

90

120

150

0

10

20

30

40

50

100

1000

800

700

600

500

400

900

SATS

AROS

NSO

ASP

these samples, bitumen coefficients increase with increasing 

percentages of asphaltenes. In point of fact, these samples have 

low to normal carbon-normalized contents of total HCS and, in 

some cases, resins.

Because no accurate burial temperatures are available for 

DSDP Site 467, such temperatures will have to be estimated. 

Based on well-established geothermal gradients for other southern California offshore areas, a gradient of 25° to 30°C per km 

would be reasonable, as would a temperature of about 11°C at 

the sediment-seawater interface. Thus, the shallowest Katz and 

Elrod (1983) samples would have been exposed to temperatures 

of 20.4° to 22.3°C, with the deepest samples at 36.2 to 41.2°C. 

The OM in these samples appears to be representative of hydrogen-rich OM in the rocks of the coastal onshore California 

Basins (Barry Katz, Texaco, oral commun., 7/95). However, 

none of these samples has the high carbon-normalized concentrations of immature HCS found in some onshore rocks. Thus, 

we may speculate that the high HC concentrations of some 

onshore rocks were not incorporated at deposition, but rather 

arose from cracking of weak kerogen bonds (perhaps alcohols 

or acids) above 41°C but before mainstage-HC generation. The 

pronounced compositional changes in bitumen from rocks with 

type II OM between 40° and 64°C (figs. 12, 16), and the profound qualitative changes in saturated-HC gas chromatograms 

from 40° to 70°C (discussed above), both demonstrate that 

some type of low-temperature HC generation is occurring, 

before mainstage-HC generation begins. 

This hypothesized low-temperature HC generation, which 

must be from very weak kerogen bonds, always results in qualitative changes in the extractable bitumen. However, whether 

or not this low-temperature HC generation results in significant 

quantitative changes in bitumen and HC concentrations 

depends on the percentage of kerogen originally made up by the 

hypothesized weak bonds. Thus, we speculate that immature 

rocks with high concentrations of immature HCS and bitumen, 

originally had an abnormally high percentage of weak bonds in 

their kerogen. Such early HC generation, if it exists, and the 

possibility that such early generated HCS could form commercial oil deposits, have exploration implications as significant as 

the highly suppressed mainstage-HC generation observed in 

hydrogen-rich OM (discussed above).

Bell-Shaped HC-Generation Curves

Bell-shaped HC-generation curves (figs. 1, 7) are invariably observed for coals and shales with hydrogen-poor OM, 

where maturity ranges are large enough, e.g., Ro = 0.4 to 1.5-2.0 

percent (Price, 1989). However, such curves are uncommon in 

source rocks with both hydrogen-rich OM and TOC contents 

>5-7 percent. For example, Price and others (1984) observed 

no measurable increase in bitumen concentrations in the shales 

of the Upper Devonian to Lower Mississippian Bakken Formation, even though that rock went completely through mainstageHC generation (conservatively, starting average TOC contents 

and hydrogen indices respectively are 15-17 percent and 550-

650, versus ending average values of 7-9 percent and 50-150). 

Price and others (1984) attributed this lack of a HC-concentration buildup in the Bakken shales to efficient source-rock 

expulsion. Larter (1988, p. 193) commented on this general 

lack of a HC-concentration buildup in source rocks with hydrogen-rich OM; “In the author’s view, the development of a visible generative window in source rock sections is an infrequent 

occurrence.’’ Larter (1988) also attributed this lack of a HCconcentration buildup to efficient expulsion.

However, Tissot and others (1971) reported significant HC 

and bitumen concentration increases with depth from HC generation in the early Toarcian shales (hydrogen-rich OM) of the 

Paris Basin, also reflected in ROCK-EVAL data on the same 

samples (Espitalié and others, 1985; their figure 20). Substantial variation thus exists in HC-concentration increases during 

HC generation for different rocks. Reasons for this variance 

can be hypothesized.

Firstly, at immature ranks, rocks with hydrogen-poor OM 

usually have lower TOC contents and lower contents of indigenous (pre-generation) bitumen than rocks with more hydrogenrich OM. Also, many rocks with hydrogen-rich OM at moderately low ranks, and beyond, have low (or no) matrix porosity 

(for example, the Bakken shales, Price and LeFever, 1992). 

However, lower TOC rocks with type III OM can have elevated 

porosities (10-20 percent) even when deeply buried (see Price, 

1976, figs. 12, 13). Thus, the presence, or absence, of bellshaped HC-concentration curves in fine-grained rocks can be 

attributed partly to storage capacity. Organic-rich rocks with 

low (or no) porosities and elevated concentrations of indigenous HCS cannot easily store newly generated HCS. Thus, 

these HCS are expelled either to adjacent organic-poor rocks or 

to a secondary-migration path. Another significant loss is oil 

stored in cracks and parting laminae in source rocks (Price and 

Clayton, 1992) to the drilling mud (Price and Le Fever, 1992).

Conversely, higher-porosity, lower-TOC rocks with hydrogen-poor OM have lower original contents of indigenous HCS 

Figure 16. Plots of total organic carbon (TOC), kerogen elemental hydrogen to carbon ratios (H/C); the saturated plus aromatic HC coefficient 

(mg HCS/g OC); the bitumen coefficient (mg BIT/g OC); and normalized bitumen percentages, all for the data of Katz and Elrod (1983). In the normalized-bitumen plot, SATS are saturated HCS, AROS are aromatic HCS, 

NSO are resins, and ASP are asphaltenes. There is a scale break between 50 and 100 percent in the asphaltene field.
Conclusions 27

and significantly greater storage capacity for newly generated 

HCS, allowing bell-shaped HC concentration curves to build up 

during HC generation. (The reasons for some of the quantitative variation in the bell-shaped portion of these curves has been 

discussed above.) The decline from the maximum of bellshaped curves is classically attributed to C15+ HC thermal 

destruction (Albrecht and others, 1976). However, this explanation is contradicted by both the data from high-temperature samples with type II OM of this study and by the data of Price 

(1993b). Instead, we attribute such declines to movement of 

generated HCS from these organically mature rocks, resulting 

from the rock matrix having finally become satiated with C15+ 

HCS from increasing HC generation and decreasing porosity, 

both from increasing burial. The organic-rich Paris Basin Toarcian shales appear to be an exception to the above hypotheses, 

but this is not the case. The Toarcian shales, even during mainstage HC generation, unlike most other high TOC fine-grained 

rocks with hydrogen-rich OM, retain elevated porosities, up to 

10 percent (B. Krooss, Institute of Petroleum and Organic 

Geochemistry, Jülich, Germany; and J. Burrus, Institut Francais 

du Pétrole, Paris, France; oral communs., 10/94). J. Burrus 

attributed the HC-concentration buildups during HC generation 

in the Toarcian shales to the elevated porosities of that rock compared to the low porosities, and lack of HC concentration buildups, in the Bakken shales (J. Burrus, oral commun., 10/94), a 

point of agreement here. 

The absence of bitumen and HC-concentration buildups in 

the hydrogen-rich OM of this study is not, however, from the 

conditions outlined in the above discussion for rocks with hydrogen-rich OM. Rather, their absence is because intense HC generation has not commenced in these rocks at any of the burial 

temperatures examined. 

Conclusions

1. Bell-shaped HC-generation curves are present in rocks 

with hydrogen-poor OM in the Los Angeles and Southern San Joaquin Valley Basins. In the Los Angeles 

Basin, HC generation commences at 90°C and maximizes by 165°C. Above 165°C, HC and bitumen concentrations and hydrogen indices all strongly decrease to 

low values by 220°C, where HC generation is largely 

complete. In the San Joaquin Valley Basin, HC generation commences at 135°C and maximizes by 180°C. 

Above 180°C, HC and bitumen concentrations and 

hydrogen indices all strongly decrease to low values by 

214°C. In the Ventura Basin, intense HC generation has 

not begun in rocks with hydrogen-poor OM by 140°C. 

The significant differences in burial temperatures at commencement of HC generation for the same OM type 

between the different areas is attributed to recent cooling 

in the Los Angeles Basin. HC generation in the Los 

Angeles Basin is thus assumed to have taken place at 

higher burial temperatures in the geologic past.

2. Scatter in the bell-shaped portion of the HC-generation 

curves observed in this study for hydrogen-poor OM are 

attributed to variable original hydrogen indices, a nonuniform loss of generated HCS to either the drilling mud 

or to source-rock expulsion, and to some shales having 

very high relative amounts of extractable bitumen and 

HCS, long before HC generation begins.

 3. In bitumen from rocks with hydrogen-poor OM, the percentage of saturated HCS progressively increases with 

increasing burial. Moreover, resins and asphaltenes 

appear to be cogenerated with the HCS. Above 140° to 

150o C, resins appear to preferentially thermally decompose.

4. Although saturated HCS from hydrogen-poor OM 

become increasingly mature with burial, they become 

oil-like only at temperatures above 180°C in the Los 

Angeles and Southern San Joaquin Valley Basins. Above 

140° to 150°C, saturated HCS from hydrogen-poor OM 

usually have their qualitative (and quantitative) characteristics altered by expulsion and (or) HC loss to the 

drilling mud, especially loss of C15- HCS. A lack of such 

alterations and no loss of C15- HCS in rocks with hydrogen-rich OM to temperatures of at least 198°C is attributed to low concentrations of HC gas in these rocks from 

the lack of commencement of mainstage-HC generation.

5. In the southern California basins, coarse-grained rocks in 

or around existing oil fields, where such rocks are not 

commercial oil reservoirs themselves, often have very 

high bitumen concentrations, from oil-staining.

6. Data from this and other studies document that profound 

qualitative changes occur in the bitumen and HCS over 

40° to 70°C in rocks with hydrogen-rich OM in the 

southern California basins, presumably from low-temperature HC generation processes.

7. In rocks with hydrogen-poor OM in the California 

basins, above 40°C and before mainstage generation, 

low-temperature HC generation also appears to occur, 

resulting in significant qualitative, but often no measurable quantitative, changes in the bitumen and HCS. This 

low-temperature HC generation in rocks with all OM 

types in these basins may result from weak (15-40 kcal/

mole) kerogen bonds.

 8. Fine-grained, immature (pre-mainstage HC generation), 

late Neogene rocks in the southern California petroleum 

basins of all OM types, including sulfur-poor OM, occasionally have abnormally high concentrations of indigenous immature HCS and bitumen. Different lines of 

evidence suggest that this material may result from low 

temperature (40° to 120°C) generation from kerogens 

which originally have abnormally high contents of weak 

bonds (15-40 cal/mole). Such a low-temperature generation could have strong exploration implications.

 9. Profound suppression of mainstage-HC generation, and 

all aspects of organic metamorphism, is present in rocks 

with hydrogen-rich OM in the southern California 

basins, compared to rocks with hydrogen-poor OM buried under the same conditions. For example, mainstage-HC generation is largely complete, and extracted 

bitumen is mature in appearance, in rocks with hydrogen-poor OM by 200°C. Conversely, mainstage HC 

generation has not even begun in rocks with hydrogen-
28 Organic Metamorphism in the California Petroleum Basins

rich OM by 198°C at the Wilmington field and has 

begun only at 197°C at the Ventura Avenue Field. 

Moreover, extracted bitumens from such rocks still have 

an immature appearance at these high temperatures. 

This suppression of organic metamorphism in source 

rocks with hydrogen-rich OM has profound exploration 

implications.

 10. Trends in bitumen composition versus burial temperature 

suggest that hydrogen-rich OM follows different reaction 

pathways, in addition to having different reaction kinetics, than hydrogen-poor OM. In the hydrogen-poor OM 

of this study, saturated and aromatic HCS, resins, and 

asphaltenes are all cogenerated; and at temperatures 

above 150°C, saturated HCS increasingly make up a 

greater percentage of the bitumen, while resins preferentially thermally decompose. By contrast, hydrogen-rich 

OM first generates resins and asphaltenes, which later 

thermally decompose to HCS.

11. From 60° to 145°C, saturated-HC gas chromatograms 

from all OM types demonstrate the same peculiar qualitative changes, versus temperature, in rocks from different sites in the three basins of this study. Moreover, these 

same changes are evident in other studies of southern 

California shales. These peculiar similarities suggest 

that the same, or similar, starting OM exists in many of 

the late Neogene rocks throughout southern California. 

Differences in hydrogen-richness, and reaction pathways 

and kinetics between the different OM types must then 

be due to different depositional conditions at different 

sites affecting the same starting OM.

12. The presence or absence of bell-shaped HC-generation 

curves in fine-grained rocks with adequate maturity 

ranges are hypothesized as due to organic richness and 

rock-storage capacity (porosity). With exceptions, 

organic-rich shales with hydrogen-rich OM typically 

have low porosities and high original bitumen concentrations by rock weight. Thus, such rocks cannot build up 

HC and bitumen concentrations significantly elevated 

over their original values. However, less organic-rich 

rocks with hydrogen-poor OM typically have higher 

porosities and lower original bitumen and HC concentrations (by rock weight), and thus invariably build up bitumen and HC concentrations from HC generation. 

13. The decline in the concentration maxima at 150° and 

180°C for the two bell-shaped HC generation curves for 

hydrogen-poor OM in this study cannot be due to HC 

cracking. This is because HC generation in hydrogenrich OM only occurs at temperatures of 197°C or higher 

in the same basins. Instead, we attribute the declines in 

the bell-shaped HC-generation curves to source-rock 

expulsion and loss of generated HCS to the drilling mud 

during drilling operations.

Acknowledgments 

The reviews of Caroline Isaacs, Barry Katz, and Joe Curiale significantly improved the paper. Their insights into these 

basins based on years of experience in working the basins is 

greatly appreciated. Thane McCulloh originally compiled a 

significant part of the sample base on which this study was 

based.

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