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IPA 93-13.02
PROCEEDINGS INDONESIAN PETROLEUM ASSOCIATION Twenty First Annual
Convention, October 1992
GEOCHEMICAL INVERSION - A MODERN APPROACH TO INFERRING
SOURCE-ROCK IDENTITY FROM CHARACTERIST ICS OF ACCUMULATED
OIL AND GAS
K. K. Bissada * L. W. Elrod *
L. M. Darnell * H. M. Szymczyk
J. L. Trostle *
ABSTRACT
In recent years, petroleum geochemists have been re- focussing
their efforts on developing practical means for inferring, from
hydrocarbon chemistry and geologic constraints, the "provenance" of
hydrocarbon accumulations, seeps or stains. This capability,
referred to here as "Geochemical Inversion", can be invaluable to
the explorationist in deriving clues as to the character, age,
identity, maturity and location of an accumulation's source rocks
and in evaluating a petroleum system's hydrocarbon supply
volumetrics: This is particularly true where pertinent source-rock'
information may be absent because exploratory drilling focused
strictly on structural highs and failed to penetrate the deeply
buried, effective basinal source facies. Advances in chemical
analysis technology over the last decade have facilitated the
development of powerful geochemical methods for deconvolution of
complex chemistries of crude oil and natural gas at the molecular
and subatomic levels to extract specific information on the hydro-
carbons' source. Inferences on such factors as organic matter
make-up, depositional environment, lithology, age and maturity of
the source can frequently be drawn. These, together with a sound
analysis of the geologic and architectural constraints on the
system, can supply clues as to the identity and location of the
probable source sequence. This paper describes the principles
underlying geochemical "inversion" and provides examples of its
application in exploration and exploitation settings.
Inversion of geochemical characteristics of migrated hydrocarbon
fluids to specific attributes of the source
* Texaco Inc., E&P Technology Department
is demonstrated. The paper will also illustrate the utilization
of systematic variations in fluid chemistry within a geologic
setting to infer source location, degree of hydrocarbon mixing and
relative migration distance.
INTRODUCTION
As economics of oil and gas become more complex, explorationists
often are required to go beyond conven- tional trap identification
and trap capacity deter- mination. Objective assessments of
hydrocarbon supply and migration patterns are becoming critical
elements in evaluating many exploration and exploitation
opportunities. Addressing hydrocarbon-supply volu- metrics and
migration patterns requires systematic analyses of source
attributes, source distribution, transformation potentials, level
of thermal transfor- mation, source-to-trap transfer, efficiencies,
and correlation of any encountered hydrocarbons (seeps, stains or
accumulations) to one another and to the. source rocks from which
they were generated and expelled. Whereas oil and gas samples are
often readily available for characterization and correlation
analyses, pertinent source rock information is frequently absent
because exploratory drilling typically focuses on structural highs
and seldom samples the deeply buried, effective basinal source
facies (Figure 1). Explorationists are left with three options: (1)
Make arbitrary assumptions on the subsurface attributes of the
system, (2) forecast these attributes utilizing conceptual and
geochemical models constrained by physico-chemical principles, or
(3) utilize the chemical characteristic of any encountered
hydrocarbons to infer the possible character, maturity and identity
of the potential source system. In this paper we will focus on this
third approach which we refer to as "geochemical inversion".
IPA, 2006 - 21st Annual Convention Proceedings, 1992
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The explosive developments in chemical analysis technology,
coupled with enhanced data processing capabilities over the last
decade, have allowed the development of some very powerful
geochemical methods not only for reliable oil-to-oil and oil-to-
source correlation, but also for deconvolution of the complex
chemistry of crude oil and natural gas at the molecular and
subatomic levels to extract information on the hydrocarbons source.
In principle, geochemical inversion utilizes the same types of
analytical procedures used in conventional petroleum-to-source
correlations (Figure 2). The derived information may include
specific characteristics of the source rocks such as organic matter
make-up, lithology, and maturity. These con- clusions can then lead
to specific inferences about the depositional environment, age ,
identity and location of the hydrocarbon source sequence. The
chemical signatures of the hydrocarbon fluids can also provide
clues as to migration distances and fluid mixing.
This paper is by no means a comprehensive treatise on
geochemical inversion. It is intended only as an intro- ductory
review of the potentials and limitations of the current technology
in terms of its exploration and exploitation applications. It is
hoped that the subject will draw attention to the utility of the
tools in address- ing such problems as delineation of gathering
areas for reserve-volumetrics analysis, predicting hydrocarbon
quality and producibility for risk assessment, and defining
migration paths and pay-zone inter-relation- ships for exploitation
planning.
FUNDAMENTALS OF GEOCHEMICAL INVERSION
The basis for geochemical inversion lies in the processes that
originally form the oil and gas. Petroleum originates in organic
material that is deposited in aquatic environments. The organic
matter accumulating in the potential source sediments possesses
distinctive chemical characteristics inherited from the specific
combination of organisms within the original ecosystem. These
characteristics, in turn, are transferred to the generated
products. Figure 3 is a schematic sketch of the processes that
affect a complex organic molecule typifying the chemistry of the
bio-mass as it is deposited and transformed into oil and gas
through processes of digenesis, catagenesis, expulsion and
migration. The starting molecule typically would be unsaturated
with respect to organic hydrogen. It would have some oxygen, some
sulfur and perhaps some nitrogen atoms. Molecules with this sort of
structure are not stable in the geologic system. As the molecule
gets buried deeper, it undergoes many changes. Mainly, oxygen and
other hetero-atoms are removed and the structure becomes saturated
with respect to hydrogen, eventualiy becoming a hvdrocarbon. Once
the hydrocarbon
forms, it is geologically stable, particularly if it ends up
being incorporated into an oil accumulation. The product
hydrocarbon retains the majority of the structure that was in the
original complex organic molecule. Thus, by examining the
encountered hydro- carbons, it is possible to glean what type of
organic matter originally contributed to the petroleum.
This is substantially true also at the subatomic level. The
stable isotopes of carbon and hydrogen are not appreciably altered
during the burial and thermal evolution of sedimentary organic
matter from bio- polymer through geopolymer (kerogen) , and even-
tually to oil and gas (Schoell, 1984). The inherent isotopic
fractionation that sets the original isotopic composition of the
parent organic matter is a normal consequence of the physical
chemistry of these isotopes. For example, a normal carbon atom with
mass number 12 has 6 protons and 6 neutrons in the nucleus, whereas
a carbon with mass number 13 has one additional neutron in the
nucleus. This means that chemically the two atoms are identical and
thus will undergo the same chemical reactions in exactly the same
way. 13C, being larger, however, generally reacts more slowly.
Thus, when it bonds with other carbons, it forms bonds that are
very slightly stronger than bonds between 12C. This difference
promotes segregation between organic molecules with different
relative abundances of the two isotopes. Whenever carbon gets into
the biological system through the carbon cycle, the algae, bacteria
or higher plants processing this carbon have a tendency to
isotopically segregate it and set the 13C to 12C ratio in the given
ecosystem. This fractionation occurs because of the way the two
isotopes interact with the enzymatic processes. Thus, the I3C to
12C ratio will vary with the type of carbon available to the
organisms during photo- synthesis, the type of organic species
contributing to the oils, and with the chemical environmental
stress that the organisms were subjected to, regardless of age.
Different oils, then, should have distinct carbon isotope
signatures.
There are numerous factors that influence what accumulates into
the primary source material and what happens to the organic matter
upon deposition, trans- formation into hydrocarbons, and migration
of the products through the carrier system. Variation in these
factors and conditions influence not only the character of the
hydrocarbon blend that is generated and entrapped, but also the
isotopic composition of the carbon that makes up the hydrocarbons.
These factors are summarized in Figure 4. Top among these factors
are:
I. Type of organic material in the prevailing eco- system.
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Was it dominantly algal? Was it dominantly bacterial? Was
higher-plant input significant? (Post-Silurian) Were they flowering
plants (angiosperms)? (Post- Jurassic). In fact, the specific
species of the biomass may have profound effects on the character
of the resulting oil.
2. Type of depositional environment. Was it marine or
lacustrine? Was it deep-water (>500 m) or shallow water (>200
m) '? Was it oxidizing or reducing? Was the biological oxygen
demand high? Was it hypersaline? Was it alkaline?
3. Source-rock matrix lithology. Was it dominantly clastics? Was
it dominantly carbonates?
4. Migration factors. Was migration long-range or short? Was the
carrier system highly retentive? Was entrainment of carrier
constituents significant?
In fact, migration through a highly carbonaceous carrier system
could contribute substantially to the product's fingerprint.
But this is not all. Once the oil has been generated and
emplaced into the reservoir, its character can be further modified
by a number of subsurface alteration processes (Figure 5) :
5 . Alteration factors. Was the oil water-washed in the
reservoir'! Was it biodegraded? To what extent? If it is a light
crude/condensate, is it a primary condensate, a product of phase
segregation, or thermal degradation?
These complexities cause every oil accumulation to look a little
bit different, having had different organic input, a different
depositional environment or a different generation history. The
effects leave their mark on the ultimate composition of the product
which, in turn, allows inversion of the geochemical characteristics
of the accumulated hydrocarbons to specific attributes of the
generative system and its history.
Effective geochemical Inversion requires that the geochemist
consider the contribution of all the pertinent
factors to the final composition of the hydrocarbons. The
inversion process can be performed in two ways:
1. Interpretation of attributes in the hydrocarbon composition
that are directly related to the source character and identity.
2. Interpretation of the systematic variations in fluid
chemistry within the regional geologic framework and drawing
inferences on sourcing direction, degree of hydrocarbon mixing,
relative contribution of multiple sources, and relative migration
distances. This approach capitalizes on migration-sensitive and
alteration-sensitive parameters to draw the inferences.
DIRECT INFERENCING OF SOURCE CHARACTER OR IDENTITY
ORGANIC INPUT AND SOURCE ENVIRONMENT
A large variety of organisms have been available for
incorporation into sediments and subsequent transfor- mation into
hydrocarbons. During this transformation, many of the specific
organic compounds that constituted the organisms often retain much
of their original structure, distribution and stereochemistry in
the accumulated hydrocarbon fluid. Concurrently, the environment of
deposition of the source rock can have a profound effect on the
characteristics of the resultant hydrocarbons, partly because the
environmental stresses alter the conditions under which the
affiliated organisms grow and partly because the prevailing
physicmhemical conditions modify the organic material during and
immediately after deposition. Thus, the parameters for inferring
depositionai environments are often intimately linked to those for
inferring organic input. Careful interpretation of the distribution
of the various components in the hydrocarbon fluid provides clues
about the organisms that contributed to the original source organic
material and/or about the environments under which the source rocks
have been deposited.
At the simplest level, the distribution of the normal paraffins
in an undegraded oil can indicate the type of organic material that
contributed to the source. Although algae and bacteria probably
represent the common basis for all crudes (Lijmbach, 1975), contri-
bution of specific compounds to the source matter m u l d impart
specific characteristics on the overall crude-oil character. Thus,
oils that contain high proportions of waxy paraffins (long-chain
n-paraffins with > 22 carbon atoms) may be interpreted to have
been genqated from sources that contain anomalously high
proportions of higher plant material (waxy leaf
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168
cuticle) in the kerogen mix (Figure 6-a). This, in turn,
indicates proximity of the original depositional system to a source
of terrestrial plant detritus; i.e., a near- shore facies. Figure
6-b shows an example from the Moray Firth area of the North Sea
where the southeast- erly increase in contribution of higher plant
kerogen to Kimmeridgian source rocks is indeed paralleled by a
southeasterly increase in content of CIS+ waxy n-paraffins in the
crudes (Bissada, 1983).
Waxy crudes may alternately signify generation from organic
matter containing abundant remains of certain lacustrine algae that
are enriched in long-chain n- alkanes and alkenes. Of the numerous
geochemically significant algae listed in Table I, those that could
contribute waxy n-paraffin precursors are identified in the right
hand column (Gelpi et al., 1970). Large accumulations of high-wax
crudes are known to have been sourced from many synrift lacustrine
systems around the world (e.g., Williams et al., 1985). Figure 7
illustrates the distinction between chromatograms of oils from
non-marine vs. marine algal source rocks. Generally, chromatograms
of non-marine- sourced oils show:
1. Enrichment of n-paraffins in the range n-C2, to
2. Pronounced odd:even predominance in the n-
3 . Convex curve (relative to baseline) following the
n-C,,.
paraffin distributions in this range.
n-paraffin distribution.
In contrast, chromatograms of marine-sourced oils show:
1. Depletion in n-paraffins above n-C,,. 2. Less pronounced
odd:even predominance. 3. A concave curve following the n-paraffin
distri-
bution.
These observations are similar to those cited by Sofer, 1984 and
Peters et al., 1986.
The ratio of pristane (Pr) to phytane (Ph) in a crude oil has
frequently been used as an indicator of either relative importance
of higher-plant input vs bacterial inputs (Brooks et al., 1969; ten
Haven et al., 1987), or redox conditions within the depositional
system (Powell and McKirdy, 1973; Didyk et al., 1978). The
underlying concepts are:
1. High Pr/Ph ratios (> 1) signify either: sub-oxic to oxic
conditions, or high input of allochthonous higher-plant
material.
2 . Low Pr/Ph ratios (
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within silled basins where the prevailing source of carbon in
the photic zone is atmospheric C 0 2 (with negligible influence
from the deep organic C 0 2 by virtue of its diffusion and dilution
through a long and well-mixed water column).
Stable carbon isotope compositions (13CI'zC) are usually
expressed in the k-notation as parts per thousand deviation from
the '3C/'2C ratio of a standard carbon compound (carbonate-carbon
in the Pee Dee Belemnite) to signify the relative abundance of the
rare, heavy isotope. Because carbon in petroleum is relatively more
enriched in the lighter isotope than carbon of the Pee Dee
standard, the 6 13C values are reported as negative numbers.
Increasingly negative S I3C values indicate increasing enrichment
in the lighter isotope.
Isotopic compositions of oils ascribed to the Miocene Monterey
formation invert to kerogen isotopic composition of -20 to -22 %o,
suggesting deep-water facies for the source rocks. In fact, the
Monterey Fm. is believed to have been deposited in silled,
deep-water (>1,000 m) basins with a common overlying water body
open to the Pacific Ocean (Ingle, 1981). In contrast, 6 I3C values
for oils ascribed to the Devonian/ Mississippian New Albany Shale
of the Illinois basin invert to kerogen 6 I3C values of -28 to -30
%o. The New Albany is believed to have been deposited in a shallow
(< 200 m), restricted epicontinental sea with a well developed
anaerobic water column (Rich, 1951). One can therefore generalize
that isotopically heavy oils (6 13C values of -18 to - 24 %o) ,
whether marine or lacustrine in origin, can be attributed to
deep-water facies, and isotopically light oils (6 I3C values of -26
to -32 %.I, whether marine or lacustrine, can be attributed to
shallow-water facies.
Figure 1 1 compares the compound-specific n-paraffin isotopic
compositions and n-paraffin distributions of two oils of
contrasting source facies. Because the n- paraffin distribution
curve for the Persian Gulf oil is concave, the oil is inferred to
be from a marine algal source. Furthermore, because the n-paraffins
are isotopically light (6 values of -28 to -31 % o ) , the source
is inferred to be a shallow-water ( t200 m> facies, probably
deposited in a restricted epicontinental sea. Conversely, the South
China Sea oil displays a convex, waxy n-paraffin distribution
pattern, and therefore is interpreted to be sourced by a
non-marine, lacustrine algal facies. Because its n-paraffins are
isotopically heavy (6 13C values of -18 to -21 %o), its source
rocks were probably deposited in a large, deep- water synrift
trough, with restricted circulation near the bottom but active
circulation in a long (>500 m) water column above.
dnder certain circumstances a specific organism may constitute
the major portion of the organic matter of a given source rock.
Under these circumstances, the generated hydrocarbons inherit a
very specific, diagnostic pattern in the distribution of the normal
and iso-paraffins. For example, many pf the oils of West Texas,
Oklahoma, and other paleozoic basins display very peculiar
chemistry characteristic of primitive algae known as
Gloeocupsomorphu prisca (G. prisca). The dominant features of these
oils are shown in Figure 12 and summarized below:
1. Virtual absence of paraffins larger than n-CZ2.
2. Distinct predominance of the paraffins with odd numbers of
carbon atoms in the n-C17 to n-CI9 range.
3. Little or no isoprenoids (Figure 12) (pristane or
phytane).
4. Very light carbon isotopic compositions (6 13C 1) in the
crude provides a criterion
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170
to establish the dominance of the microbial or algal
contribution because tricyclics are characteristi- cally absent in
extracts from higher plant kerogens (Zumberge, 1987). C&s
enrid. G:d in tricyclics should be interpreted to have originated
in a distal marine facies far removed from any terrestrial input,
or in lacustrine shales containing Type I kerogen. This criterion
must, however, be tempered by the fact that the dominance of the
tricyclics ~2ay merely reflect the higher thermal stability of the
tricyclic terpanes and their inherent ability to persist to higher
maturation levels (Schou et al., 1984).
The presence or absence of significant quantities of oieanane in
an oil should signify whether or not remains of flowering plants
(angiosperms) contributed signifi- cantly to the kerogen mix within
the source rocks (Philp and Gilbert, 1986). This in turn aids in
inferring the extent of terrestrial input and therefore the nature
of the depositional facies that sourced the oil. The utility of
oleanane for this purpose is restricted to post-Middle Cretaceous
systems because flowering plants did not fully evolve until that
time.
Severely anoxic depositional environments are mani- fested by
unique distributions of biomarkers linked to certain
sulfur-reducing bacteria that produce 28,30- bisnorhopane as a
metabolic product (Katz and Elrod, 1983). Because this compound is
stable in the geologic environment, it can remain with the organic
material until oil is expelled, at which time it travels with the
oil. Thus, oils in which the bisnorhopane is very prominent, as in
the Miocene crudes of California, should be inter- preted to have
originated in rocks associated with bacterial mats deposited under
severely anoxic conditions.
Recognizing the significance of oleanane and bisnor- hopane as
paleoenvironmental indicators allows one to use their relative
abundances in a crude oil to infer the relative contribution of
terrestrial organics versus marine bacterial components. This would
in turn help in delineating, or at least speculating on, the
responsible source facies within the petroleum system.
An anomalously high content of the extended hopanes (C-31 to
C-35 homohopanes >75%) may indicate significant bacterial input
and may imply sourcing from rocks of 1 hypersaline facies where the
development of other living communities was inhibited (Dembicki et
al., 1976). Hypersaline environments impart distinctive
characteristics to the organic material of a source rock and
consequently to the generated crude oil. Oils enriched in
gammacerane and carotane, and impover- ished in. tetracyclic
terpanes are interpreted to have been sourced by rocks of a
hypersaline facies. Because
hypersalinity commonly accompanies anoxic carbonate facies
development, oils from hypersaline environ- ments will also display
features of oils generated in carbonate/evaporite rich rocks. The
following inversion criteria can be used for recognition of
hypersaline facies (ten Haven, et al., 1988):
1. Ph>>Pr. 2. Even-Odd-Preference @ C,,>>l.
3. High abundance of squalane. 4. High abundance of regular C-25
isoprenoid. 5. High abundance of gammacerane. 6. Full complement of
C-31 to C-35 extended hopane
series maximizing at the C-35 doublet. 7. Within the C-27, C-28
and C-29 regular sterane
series, BBR and BBS concentrations are higher than those of aaS.
(i.e., C-27 BBR + C-27 BBS > C-27 aaS; C-29 BBR C-29 1313s >
C-29 aaS; Figure 15).
i.e.[2*n-C2, / {n-C,, + n-C,,}]>>l
C-28 BBR + C-28 BBS > C-28
In spite of the complexities and ambiguities encountered in
their interpretation, the distributions of sterane biomarkers in
crude oils provide valuable supporting information for geochemical
inversion. Figure 15 displays the biomarker traces for a Jurassic
crude oil from the Mississippi Salt Basin (USA). The tricyclic and
pentacyclic terpane fragmentograms (M/Z 191) of the oil are
complemented by the sterane fragmento- gram (M/Z 217) to capture as
much diagnostic infor- mation as possible. In general, the oil is
interpreted to have been sourced from an anoxic, possibly
hypersaline, carbonate-phosphate-rich source facies. At the outset,
the low abundances of the C-19 to C-22 and C-24 to C-26 tricyclic
terpanes relative to the C-23 tricyclic and C-24 tetracyclic
terpanes is typical of a carbonate- phosphate-rich source facies
(Sofer, 1990). The lower pentacyclic terpane (hopanes) abundance
relative to the steranes, reflects the strong influence of the
autochthonous algal input to the source. The C-27 to (2-29 sterane
ratio in a crude oil is traditionally used as an indicator of the
relative importance of marine (dominantly C-27) versus terrestrial
(dominantly C-29) organic matter into the source (Huang and
Meinschein, 1979; Hoffman et al., 1984; Wenger et al., 1988). In
the example of the Smackover crude oil described here, however, the
strong predominance of the C-29 over the C-27 regular steranes
cannot be interpreted along the traditional lines as higher-plant
related. The character- istics documented are in fact a common
feature in many CarbonateYevaporite-sourced oils. The high
proportion of C-29 sterane in this situation is obviously not
related to vascular plant input but perhaps to a very specific type
of non-terrigenous algal population contributing a C-29 sterane
precursor (Volkman, 1986; Brassel and
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Eglinton, 1983). Examples of oils with these character- istics
have been reported from the Silurian of the Michigan Basin
(Rullkotter et al., 1986) and the Late Precambrian of Oman
(Grantham, 1986).
LITHOFACIES
As noted in the previous paragraph, the chemistry of a crude oil
can provide information about the lithology of the source. Since
specific geologic environments will favor the deposition of certain
lithologies as well as certain organisms, these parameters can
overlap with those related to organic input. For example, the
Smackover oil, whose fingerprints are displayed in Figure 15,
shares the following distinguishing character- istics with typical
oils generated from anoxic, possibly hypersaline, dominantly algal
/ bacterial, carbonate- rich source facies:
1. Even carbon number n-paraffin predominance
2. Extended C-31 to (2-35 hopanes >> 55% of total
3. C-35/C-34 hopane ratio > 1.0; 4. Relatively high sulfur
contents (Gransch and
Posthuma, 1974; Orr, 1986); 5 . Pr/Ph ratios < 1.0; 6.
Aromatic-Naphthenic character (Tissot and Welte,
7. C-30 hopane/C-29 norhopane ratio < 1.0; 8. Moretanes <
6% of total terpane content.
(Welte and Waples, 1973);
hopane content;
1984);
Furthermore, minerals deposited with organic material can alter
the material during deposition and diagenesis and thus influence
the composition of the resultant biomarkers and hydrocarbons.
Because clay-rich sources effectively acid-catalyze backbone
rearrange- ment of regular steranes to rearranged steranes during
diageneses, crude oils exhibiting enrichment in the rearranged
steranes (diasteranes: C-27 R a S , RaR, and a B S ; C-28 aRS, OaR
and a13R; and C-29 RaS , 8aR and a R S ) relative to the regular
steranes (C-27 aaS, BBR, BBS and aaR; C-28 aaS, BRR, RRS and aaR;
and C-29 aaS, RBR, BRS and aaR) can be interpreted as having been
sourced from a clay-rich source facies. At the regional level, the
relative proportions of regular steranes to rearranged steranes in
crude oils provides clues as to the extent of clastic vs. carbonate
contri- bution to the petroleum system. This, in turn, aids in
delineating which part of a stratigraphic sequence is the main
contributor to the system. The very low diasterane content of the
Smackover oil described above (
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(1281/1291) in Cretaceous or younger crude oils may be
attainable in the near future.
SOURCE THERMAL MATURITY
Because the properties of oil and gas are related to the
maturity of the source rocks at the time of expulsion, the
molecular and isotopic compositions of the oils and gases can
provide useful indices for estimating the level of thermal maturity
at which the hydrocarbons were generated and expelled, provided, of
course, they were not subjected to further thermal alteration
subsequent to migration and emplacement in the reservoir. Because
thermal maturity of subsurface sequences can be independently
measured or modelled in terms of depth, temperature or time, the
correlation of the two maturity estimates provides a means for
inverting the information to source depth, location and, possibly,
identity.
This approach can be most useful in addressing problems of
inferring depth and identity of sources of gas accumulations. The
stable carbon isotopic compositions of thermogenic methane and
other hydro- carbon gases (ethane, propane and butane) reflect the
extent of thermal maturation of the parent kerogen in the source
rocks. Several relationships have been established. Figure 16 shows
the relationship between the 6 13C values of methane and the
vitrinite reflectance index of its source rocks (Stahl, 1977).
Faber (1987) demonstrated that thermal maturity of the source rocks
can be inferred also from the relationship of the 6 13C values of
the ethane and propane in the hydrocarbon mix (Figure 17). Thus,
one can measure the isotopic composition of methane and ethane, use
one or the other of the relationships in Figures 16 or 17 to invert
the isotopic information to a thermal maturation value, and relate
the latter to a depth/pick on a stratigraphic or seismic section of
the subsurface.
Figure 18 depicts a situation in which wet gas accumu- lations
occur in reservoirs at 9,000 and 13,000. The isotopic composition
of the methane was determined by isotope-ratio mass-spectrometry
(IRMS) to be about -44 % in both cases. Using Stahls relationship
of 6 13C vs. vitrinite reflectance, it was deduced that the methane
has been sourced from kerogens that attained maturation levels
corresponding to an R, value of 0.7%. Geochemical analysis of rocks
from the entire stratigraphic sequence revealed that organic-rich
rocks with varying levels of thermal maturity occur at various
depths within the section. However, only the organic- rich unit
near 13,500 shows R, values of about 0.7%. It is conceivable,
therefore, that the gas in both reser- voirs has been sourced
primarily from that unit.
Bissada et al. (1990) used this approach to infer a pre-
Tertiary source for a gas and oil discovery in the Plio-
Pleistocene trend in the Gulf of Mexico. Figure 19 depicts the
situation where the penetrated section never encountered an
adequate source rock. The anomalously heavy carbon isotopic
composition of the associated methane inverts to a kerogen thermal
maturity equivalent of 2.5% R,. Thermal maturation modeling using
interpreted seismic picks and regional heat-flow data indicate that
this level of maturity is attained at a depth exceeding 30,000 in
Cretaceous or Jurassic rocks.
Inverting molecular composition of hydrocarbons in crude oil to
thermal maturity information is more complex, and usually much less
significant than inversions drawn on hydrocarbon gases. Oil
generation and expulsion begin and end as pulses within a
relatively narrow thermal maturation window defined by the 0.68% R,
boundary near the top and the 1.2% R, boundary near the bottom
(Bissada, 1982). Fluids from these pulses mix and homogenize within
the overall accumulation, diluting and averaging the pulse- or
depth-specific information. However, because expulsion is effected
by pore-pressure-induced fractur- ing accompanying fluid build-up
within the source rock, onset of expulsion will occur at the mild
end of the peak generation window in very rich source rocks and at
a higher maturity level in lean source rocks. Thus, a brief
discussion of the significance of inversion of molecular data to
thermal maturity information is warranted in this section.
In oils that are known to have suffered no post- expulsion
maturation, and those that are known to be free of spurious
biomarkers entrained during migration through organically-rich
(coaly) carrier systems, biomarker distributions may provide clues
to the effective thermal stress and, thus, the stage of maturity at
which expulsion had occurred. This, in turn, provides clues to the
effective depth of burial of the source rocks, particularly in
tectonically simple systems.
Of the numerous biomarker-based thermal maturity indicators
proposed in the geochemical literature, the aa-sterane
epimerization products appear to be most popular (Waples and
Machihara, 1991). The ratios of three pairs of peaks on the sterane
GC/MS trace in Figure 15 are particularly significant:
The C-27 aaS : C-27 aaR , the C-28 aaS : C-28 aaR , and the C-29
aaS : C-29 aaR.
These ratios, commonly referred to as the 20S/20R epimer ratios,
increase with increasing maturity. The biologically inherited forms
are exclusively the aaR.
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173
With increasing maturity the proportion of the 20S:20R increases
as some of the 20R molecules change con- figuration to the 20s
form. Ultimately an equilibrium ratio of 55% 20s : 45% 20R is
attained. Beyond that point maturation of the parent kerogen can no
longer be traced. From an operational point of view, the following
indices may be found useful:
Stage Equivalent R, aa(20S) :aa(20R)
Biological precursor 0 0.3% Zero Pre-generation 0.51% 30 : 70
Onset of generation 0.55-0.68% 40 : 60 Peak gener./expulsion
0.68-0.80% 45 : 55 Equilibrium ratio > 0.8% 55 : 45
At the higher maturity side of the generation window, another
set of biomarkers may be useful as supple- ments to the 20S/20R
sterane ratios. These are represented by the C-27 Ts
(l8a-trisnorhopane) and the C-27 Tm (17a-trisnorhopane) peaks on
the penta- cyclic triterpane trace (M/Z 191) in Figure 15. Although
the ratio is somewhat dependent on organic matter input, generally,
oils that are substantially expelled from the source system at
maturation levels below 0.9% R, display Ts/Tm ratios of less than
one. The ratio begins to increase gradually as the Tm isomer
gradually disappears under increased thermal stress.
INFERRING MIGRATION PATTERNS AND HYDROCARBONPROVENANCE
In the previous section we dealt primarily with direct means for
inferring source identity using attributes in the hydrocarbon
composition that are directly related to the source character and
maturity. Interpretation of the systematic variations in fluid
chemistry within the regional geologic context and drawing
inferences on sourcing direction, degree of hydrocarbon mixing,
relative contribution of multiple sources, and relative migration
distances can he even more useful. Migration- sensitive and
alteration-sensitive parameters are particularly useful in this
approach and integration of the geochemical data with available
geologic and geophysical information is most critical.
Robison and Bissada (1992) used this approach to identify and
delineate the depth and areal extent of the unpenetrated probable
effective generative sequence within the Zhu 1 depression in the
Pearl River Mouth basin, South China Sea. Figure 20 depicts the
situation where drilling netted numerous discoveries but en-
countered no source rocks within the penetrated section. The oils
show identical "genetic codes", inasmuch as their isotopic { 6 13C
} and biomarker
{isoprenoids, triterpanes (M/Z 191) and steranes (M/Z 217))
characteristics are essentially identical. The physical and gross
chemical characteristics that are diagnostic of post emplacement
alteration, however, show distinct differences: The shallowest oil
exhibits the lowest API gravity (22.3,), the highest isoprenoid/
n-paraffin ratio (Pr/n-C,+ 4.0), and a virtually feature- less
saturate hydrocarbon chromatogram. These are characteristics of a
severely biodegraded crude. The degree of biodegradation appears to
decrease with depth, becoming virtually imperceptible below the
"biological sterility boundary" at 160" F (red horizontal marker on
Figure 20). From these observations it was inferred that the oil
was generated from one source system at depths below the top of the
oil window (green horizontal marker on Figure 20), migrated
generally up-dip from the NW towards the SE, and entrapped to spill
point in structural traps along the migration path. Because the
non-biodegraded crudes display non- marine, highly waxy
characteristics, they are inferred to have been generated in a
lacustrine source system within the synrift sequence identified on
the seismic section.
The example from the Pearl River Mouth basin is a simple one
where sourcing appears to be limited to one trough in the Zhu 1
depression. In many cases, how- ever, the oil found in a reservoir
may not be from a single source, but is the composite of
hydrocarbons derived from two or more sources that have converged
upon the same trap. In such cases the composition of the oil will
display contradictory features that make classification and
inversion difficult, unless a mixing scenario i s invoked. In cases
where "end member" oils from each contributing source are also
available, the process of deconvolution of the mixed
characteristics becomes feasible. Figure 21 illustrates this
application with an example from an offshore rift basin in South-
east Asia. Recent discoveries indicated the existence of at least
two distinct families of oils and a mixed group. Each of the two
primary oil families exhibits distinctive distributions of steranes
and triterpanes as well as carbon isotopic compositions that makes
them easily distinguishable. The third type possesses complex
characteristics that in some ways more resemble one group of oils
and in other ways more resemble the other. Specifically, one family
appears consistent with a freshwater to brackish lake source as
evidenced by a high proportion of C3" steranes, absence of gamma-
cerane, low proportion of tricyclics and waxy character. The second
family exhibits high gammacerane content and an absence of C30
steranes suggesting a hypersaline, lacustrine source. The third
family exhibits mixed characteristics of the other two. Placing all
the infor- mation into the basinal structural framework of a system
of two partially overlapping, opposing half
-
174
grabens (Figure 21) revealed that Group I and Group I1 oils were
focussed on the hinge margins (platforms) of the two discrete
generative troughs and that the mixed group was located on the
interference ridge appropriately situated to receive hydrocarbons
from both troughs.
As previously discussed, the processes of segregation and
alteration during migration, and subsequently in the reservoir, can
have a profound effect on the ultimate composition of the produced
fluids in different sites, even though they may have had a common
source. Failure to consider such effects can lead to erroneous
conclusions concerning the genetic relationships and the provenance
of the oils. Conversely, proper consid- eration of these factors
can provide additional infor- mation upon which the geoscientist
can base his inferences. This is illustrated in the case example
shown in Figure 22 where exploitation planning in the region
required analysis of the critical factors in the hydro- carbon
generation and migration process that might have controlled the
observed distribution of oil and gas in the productive resexvoirs.
Examination of fluids produced from numerous fields in the region
revealed a variety of accumulations ranging from oils with various
oil-gas ratios to virtually all gas in an apparently random
pattern. The molecular and isotopic charac- teristics of all the
oils inverted to a lacustrine source facies, sometimes with
hypersaline attributes. Because no viable lacustrine source facies
has been encountered in exploratory drilling in the area, the
inference instigated a detailed examination of seismic data in
search for manifestations of deep troughs within which lacustrine
facies might have developed. Mapping of the positions of these
troughs with the occurrence of oil vs. gas in the area (Figure 22)
and superimposing the molecular and isotopic characteristics
revealed that the oil-gas-condensate distribution and the biomarker
patterns are related to the distance of the reservoir from the edge
of the seismicly-delineated troughs.
SUMMARY
In this paper the principles underlying geochemical "inversion"
were described and examples of its appli- cation in exploration and
exploitation settings were provided. Various indices used in
inversion of geo- chemical characteristics of migrated hydrocarbons
to specific attributes of the source were summarized and their
application in inferring character, age, identity, maturity and
location of that source were discussed. The utilization of the
systematic variations in fluid chemistry within a geologic setting
to infer source location, degree of hydrocarbon mixing and relative
migration distance were illustrated. It is hoped that thc review
will draw attention to the utility of the tools in
addressing such problems as delineation of gathering areas for
hydrocarbon volumetrics analysis, predicting hydrocarbon quality
and producibility for risk assess- ment, and defining migration
paths and pay-zone inter- relationships for exploitation planning.
Whereas the tools and techniques described here may prove
invaluable to the explorationist and exploitation geologist, it is
important to recognize that, as with all predictive and
interpretive aspects of geoscience, any inferences or conclusions
based on this methodology must be treated as probabilistic rather
than absolute. The interpreter should use all available information
in conjunction with the geological data in making the pertinent
inferences.
ACKNOWLEDGMENTS
The authors are grateful to Texaco Exploration and Production
Technology Department for making their facilities and data
available for the work. We thank Texaco Inc. for permission to
publish. We would also like to express our sincere thanks to Dr. C.
R. Robison for his contribution to Figure 21 and to Dr. P. A. Kelly
for supplying Figure 22, to Mr. J. T. Motelet for assistance in
preparing Figure 20, and to Ms. R. J. Ash and Ms. D. J. Tucker for
their assistance in preparing many of the figures and the
manuscript.
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-
177
00 W OC~o o- I - WZ 13Cw
~c~ ~l. I J
g,
0 0
O0 0
Z
~ ~00 ~ 0 0 0 0 0 0 O0 '~'~ 0 '~ '~ '~ '~ '~ '~
ZO O0 0 0 0 0 0 0 Z
a
o o z~ e ~g
zz~~
0 ~ ~ Z
Z
e9
0 ! O4
0
0 !
0
m
m
Z
oO
0 0 0 0 0 >-
I - 0
ILl
0
Z w a
0 0
0
O~
Q) ~
0 E 0
-
Geo
chem
ical
Cor
rela
tion
Oil
- Sou
rce
Cor
rela
tion
oil
- oil
Cor
rela
tion
Source S
ampl
es
Not
Ava
ilabl
e fo
r C
orre
latio
n b 4
FIG
UR
E
1 -
Con
cept
of
oil-
to-o
il an
d oi
l-to
-sou
rce c
orre
latio
n. O
il sa
mpl
es c
an b
e co
mpa
red
to o
ne a
noth
er to
de
term
ine
gene
tic
rela
tions
hips
an
d to
so
urce
sa
mpl
es
to
dete
rmin
e th
e so
urce
-pro
duct
re
latio
nshi
ps. M
ore
freq
uent
ly, r
elat
ions
hips
of t
he o
ils a
re d
eter
min
ed, b
ut s
ampl
es o
f the
sour
ces
of t
he o
ils a
re n
ot a
vaila
ble
for
oil-
sour
ce c
orre
latio
n.
-
Cor
rela
tion
Cha
ract
eris
tics
Inpu
t In
vers
ion
4
Ther
mal
Mat
urity
(Ro
)
Ana
lytic
al P
roto
col
I r,
a l3 C
& a D
of C
,, C,
, et
c.
Org
anic
Mic
rosc
opy
(R, , T
AI,
etc.
) Is
otop
e-R
atio
Mas
s Spe
ctro
met
ry (I
RM
S)
I
C, -
C, H
ydro
carb
ons
Isom
er D
istri
butio
n -
Gas
Chr
omat
ogra
phy (
G C
) -
I G
as C
hrom
atog
raph
y / Is
otop
e-R
atio
M
ass S
pect
rom
etry
(G C
/ IR
MS)
C,-
C, H
ydro
carb
ons
Isom
er D
istri
butio
n a l
3 C
of I
ndiv
idua
l C
ompo
unds
Cls
+ Ex
tract
Sa
tura
tes,
Aro
mat
ics,
Res
ins
& A
spha
ltene
s
Chr
omat
ogra
phy
(PIN
)
C,,
+ Sa
tura
tes
iso-
Para
ffin
s cy
clo-
Para
ffin
s (B
iom
arke
rs &
a l3
C of
In
divi
dual
Com
poun
ds)
I GC
/MS
&G
C /I
RM
S I
Cls
+ Fr
actio
n Sa
tura
tes,
Aro
mat
ics,
Res
ins
& A
spha
ltene
s
C,, +
Sat
urat
es
n-Pa
raff
ins
iso-
Para
ffin
s cy
clo-
Para
ffin
s (B
iom
arke
rs &
a l3
C of
In
divi
dual
Com
poun
ds)
71
IR
MS
I N
atur
al G
as
FIG
UR
E
2 -
Ana
lytic
al p
roto
col f
or g
eoch
emic
al c
orre
latio
n an
d in
vers
ion.
-
Hyp
othe
tical
Rea
ctio
n of
Adi
anto
ne
to B
isno
rhop
ane
Adi
anto
ne
H
Red
uctio
n
111+
t
Red
uctio
n
Rea
rr.
-Met
hyl
Sei
ferl
et
al.,
1978
FIG
UR
E
3 ~
Hyp
othe
tical
rea
ctio
n of
th
e co
nver
sion
of
the
bioc
hem
ical
"ad
iant
one"
to
the
bio
mar
ker
"bis
norh
opan
e".
The
pre
curs
or i
s ge
olog
ical
ly u
nsta
ble.
The
pro
duct
is
geol
ogic
ally
sta
ble
and
reta
ins
muc
h of
the
spe
cific
str
uctu
re a
nd s
tere
oche
mis
try
of t
he p
recu
rsor
.
-
eoch
emic
al I
nver
sion:
In
fere
nce
of Oil P
rove
nanc
e vi
a D
econ
volu
tion
of O
il C
ompo
sitio
n
~
Org
anic
Mat
ter
Alg
ae
Bac
teria
H
ighe
r Pl
ants
Man
ne
Lacu
strin
e H
yper
salin
e
Sour
ce D
epos
ition
al E
nviro
nmen
t
Subh
ur R
educ
ing
Cla
stic
C
arbo
nate
1
Sour
ce M
atur
itv
/ A-
Sour
ce L
ithol
ogy U
Dep
th
/ /
Dis
tanc
e C
arrie
r Be
d?
FIG
UR
E
4 -
Con
cept
of
geoc
hem
ical
inv
ersi
on. I
n th
e ab
senc
e of
sou
rce
sam
ples
for
com
pari
son
to a
n oi
l, th
e co
mpo
sitio
n of
the
oil c
an b
e us
ed t
o in
fer s
peci
fic c
hara
cter
istic
s of
the
sou
rce.
-
Fact
ors C
on t r
o 11 in
g th
e G
eoc h
e m i c
a 1 C
11 a ra
c t e r
of
Res
ervo
ired
Pet
role
um
Org
anic
Inpu
t
GA
S
BPI G
ravi
ty
Mod
ified
from
Bai
ley
et a
l., 1973
FIG
UR
E
5 -
Post
-em
plac
emen
t fac
tors
influ
enci
ng t
he c
hem
ical
cha
ract
er o
f re
serv
oire
d pe
trol
eum
.
-
Expe
cted
n-P
araf
fin D
istrib
utio
ns
from
Var
ious
Pre
curs
ors
Reg
iona
l Var
iatio
n in
n-P
araf
fin
Com
posit
ion
of N
orth
Sea
Oils
5 10
15
20
25
30
35
n-
Para
ffin
Chai
n Le
ngth
(Car
bon
Num
ber)
Li
mba
ch, 1
975
Nor
thw
est
Sout
heas
t I
14
/19
-4
14
/20
-1
15
/16
-1
15/1
7-1
1512
9-2
- -1
+
Incr
easin
g H
ighe
r Pla
nt
- Kero
gen
in S
ourc
e Rocks
Biss
ada,
198
3
FIG
UR
E
6 -
(a)
Tnflu
encc
of
orga
nic
mat
ter
inpu
t on
the
dis
trib
utio
n of
nor
mal
par
affi
ns i
n oi
l. T
he w
axes
co
ntri
bute
d fr
om
high
er-p
lant
cut
icle
im
part
an
incr
ease
d ab
unda
nce
of
the
CZ
2+ pa
raff
in
com
pone
nt
in o
ils.
(b)
In t
his
exam
ple
from
the
Nor
th S
ea,
the.
infl
uenc
e of
hi
gher
pla
nt
cont
ribu
tion
is m
anif
este
d in
the
reg
ular
inc
reas
e in
the
CZ
2+ co
mpo
nent
of
the
oils
in
a so
uthe
aste
rly
dire
ctio
n pa
ralle
ling
the
incr
ease
d co
ntri
butio
n of
hig
her p
lane
t inp
ut to
the
sour
ce-
rock
ker
ogen
. Y
co
w
-
184
I o ~
0 ~ I
o ~ = L - ~ ~~_ ~ ~
el,ml t~ I
0
0
+
m
.0 tt'~ I
L
!
L
I
L
I _
~o
o:9
o
!
r~
0
-c:~ ,..c)
S
~8
K~
~ ~8 ~
-
185
0
-
-24
-25
-26
-21
- -2
8
E 3 -3
0
v)
.r(
c,
u -2
9
u- -3
1
-32
-33
-34
-35
-36
Ccl
H co
Isot
opic
Cha
ract
eriz
atio
n of
Cru
de O
ils
/ A
"Non
-Mar
ine"
Oils
/
larin
e" O
ils -
-36
-35
-34
-33
-32
-31
-30
-29
-28
-21
-26
-25
-24
Tem
plat
e af
ter S
ofer
,198
4 (S
atur
ates
) D
ata
From
Tex
aco
File
s 6
l3C
FIG
UR
E
9 -
Rel
atio
nshi
p of
ca
rbon
is
otop
ic
com
posi
tions
of
sa
tura
ted
and
arom
atic
frac
tions
of
mar
ine
and
non-
m
arin
e oi
ls.
-
Effe
cts o
f Env
ironm
ents
and
CO
Sou
rces
on
3 13
C of
Org
anic
Mat
ter &
P&
role
urn
-50
Diss
olve
d CO
, in
Equ
ilibr
ium
with
Atm
osph
ere
GO
, In
Pho
tic Z
ones
Ove
rlyin
g:
0
Wel
l-circ
ulat
ed, D
eepw
ater
Bas
ins
(>50
0 m
) *
Res
trict
ed, S
tratif
ied,
Sha
llow
-wat
er B
asin
s (
