-
car
ati
A. A
, 423
; acce
publications (Schumacher and LeSchack, 2002), yet manygeochemistry calibration study demonstrates the importance
Marine and Petroleum GeoloE-mail address: [email protected] indications of migrating hydrocarbons provide the petroleum systems analyst critical information about source (organic
matter type), maturation (organic maturity), migration (migration pathway delineation), and in selected geologic settings, specific prospect
hydrocarbon charge. All petroliferous basins exhibit some type of near-surface signal, but the hydrocarbon leakage to surface is not always
detectable with conventional seep detection methods. Understanding the Petroleum Seepage System, hence petroleum dynamics of a basin, is
key to understanding and using near-surface geochemical methods for basin assessment and prospect evaluation. The relationships between
near-surface hydrocarbon seepage and subsurface petroleum generation and entrapment are often complex. The petroleum seepage system
contain four key elements: seepage activity (qualitative expressions of relative leakage rates, active vs passive, and episodic vs continuous),
seepage type (concentration of migrated thermogenic hydrocarbon relative to in situ material, macro vs micro), migration focus (major
direction of bulk flow leakage relative to the subsurface hydrocarbon generation and/or entrapment), and near-surface seep disturbances
(near-surface processes which can greatly alter or block seepage signals). The rate and volume of hydrocarbon seepage to the surface greatly
control near-surface geological and biological responses, and thus are the best method of sampling and analysis to detect hydrocarbon
leakage effectively.
To properly predict subsurface petroleum properties, interpretation of near-surface geochemical data must recognize many potential
problems including recent organic matter input, transported hydrocarbons, bacterial alteration, mixing, contamination, and fractionation
effects. Surface geochemical data should always be integrated with other geological data. Calibration datasets to determine the utility of near-
surface geochemical techniques within particular basinal settings are essential when evaluating prospects for hydrocarbon charge.
q 2005 Elsevier Ltd. All rights reserved.
Keywords: Surface geochemistry; Near surface migration; Petroleum systems
1. Introduction
Surface geochemistry is commonly called
unconventional, although used by the largest oil compa-
nies as well as small independents, as a method to explore
for oil and gas. Surface geochemistry methods have been
used extensively for more than 70 years (Horvitz, 1980,
1981, 1985). So why are surface geochemical methods
commonly called unconventional? Contractors and true
believers in surface geochemistry demonstrate how effec-
tive the surface geochemical tools can be in handouts and
This perceived unreliability and lack of understanding of
the petroleum seepage system contributes to the unconven-
tional classification.
A multi-year research study by Abrams (2002b) examined
surface geochemical surveys that used a variety of near-
surface geochemical methods, in different geological
settings. The study concluded that all petroliferous basins
exhibit a near-surface signal, but the signal is not always
directly above an accumulation and/or detectable with the
conventional seepage detection methods. Also, this surfaceSignificance of hydro
to petroleum gener
Michael
Energy and Geoscience Institute, University of Utah
Received 1 June 2003
Abstractbon seepage relative
on and entrapment
brams*
Wakara Suite 300, Salt Lake City, UT 84108, USA
pted 31 August 2004
gy 22 (2005) 457477
www.elsevier.com/locate/marpetgeosurface geochemical data requires the recognition of
background vs anomalous populations (hydrocarbon con-
centrations significantly higher than normal level found in
localized near-surface sediments), recent organic matter
(ROM, indigenous biological material) input, transported0264-8172/$ - see front matter q 2005 Elsevier Ltd. All rights reserved.
doi:10.1016/j.marpetgeo.2004.08.003
* Tel.: C1 801 581 8856; fax: C1 801 585 3540.petroleum explorationists have experienced failures.of well-founded interpretations. Many of the failures were
due to poor interpretations. Proper interpretation of near-
-
hydrocarbons in near-surface sediments confirms the
existence of a mature source rock and migrated hydro-
ap
lat
et
roleum2. Survey purpose
Deciding whether a surface geochemical survey is
appropriate requires understanding the petroleum system
elements and processes you are trying to address. Surface
geochemical surveys are usually conducted for regional
source rock evaluation (confirm presence of a mature source
rock) or prospect definition (trap charge). Surface geo-
chemical methods can also be used to evaluate oil quality
(Barwise, 1996), oil vs gas (Abrams, 2002a), by-passed oil
(Schumacher et al., 1997), and presence of non-hydrocarbon
gas (Abrams et al., 2001a,b).
2.1. Regional source rock characterization
The presence of seepage, with sufficient amounts of
hydrocarbon for detailed molecular characterization, can
provide the following key petroleum systems information
(Abrams et al., 2001a,b):
1. source type (organic matter type),
2. source age (if age diagnostic biomarkers are present),
3. level of organic maturity (LOM), and
4. primary (from source rock to carrier bed) and secondary
(carrier bed to trap) migration pathways.
The interpreter must remember that favorable key2001a,b; Abrams, 2002a).
The relationship between near-surface hydrocarbon
seepage and subsurface petroleum generation and entrap-
ment is often complex. The near-surface expression of
hydrocarbon migration varies greatly due to the changes in
leakage rates and concentration, major direction of bulk flow,
and near-surface processes which alter or block seepage.
Rates and volumes of hydrocarbon seepage to the surface
control the near-surface geological and biological responses
(Roberts et al., 1990) and, thus, the type of sampling required
to detect hydrocarbon leakage effectively. Interpreters must
firmly grasp these issues to understand significance of
migrated hydrocarbons within near-surface sediments.
Surface geochemical measurements provide powerful
empirical observations that must be integrated with
geological and geophysical data. Near-surface to subsurface
geochemical calibration datasets help to evaluate the utility
of surface geochemical methods within specific basinal
settings and surface sediments conditions.fiel
samped or laboratory contamination, and possible migration or
pling fractionation-partitioning effects (Abrams et al.,situ or post-sampling bacterial alteration (biodegradation),generated hydrocarbon included in sediment provenance), intrahydrocarbons seepage (movement of anomalous hydrocar-
bons from site of origin to second location via sediment
nsport), reworked source rock (mature source rock with
M.A. Abrams / Marine and Pet458troleum systems elements and processes do not guaranteemacro-seeps near 83% of the fields.
The key is in understanding that near vertical migration
hydrocarbons in low concentrations, microseepage, does
not always occur. Thrasher et al. (1996) and Abrams (1996)
demonstrate the importance of understanding the regional
and local geology when attempting to evaluate near-surface
geochemical anomalies relative to intra basin and/or
prospect specific charge systems. Assuming vertical
migration always occurs and is measurable may lead to
failures. Surface geochemistry should be used as a prospect
specific exploration tool only when a calibration surface
geochemical dataset has demonstrated near vertical leakage
is present in your study area.
3. Petroleum seepage system
The rates and volumes of hydrocarbon seepages to the
surface modifies the near-surface geochemical, geophysical,aregeions contain a leakage anomaly above or nearby. Bolchert
al. (2000) examined the Green Canyon and Ewing Bank
a in Northern Gulf of Mexico, and found no near byrolical near-surface geochemical anomalies above pet-
eum accumulations. However, not all petroleum accumu-andHorvitz (1969), Jones and Drozd (1985), Klusman (1993)
Schumacher and LeSchack (2002) document halo and5. identify by-passed zones in production settings.4.carbons if artifacts such as those caused by recycled
sediments can be ruled out. Absence of petroleum seepage
within a basin or above a prospect is not sufficient reason to
eliminate the possibility that an active source rock is present
or that there has been a charge to a specific prospect (with
some notable exceptions).
2.2. Prospect evaluation
Use of surface geochemical tools does not end when a
viable petroleum system has been established. Surface
geochemistry can also be used to:
1. delineate hydrocarbon bearing zone at depth when near
vertical leakage has been established by calibration
surveys;
2. evaluate hydrocarbon charge: gas vs oil by differential
leakage-entrapment;
3. evaluate fluid quality: reservoir oil gravity and elemental
sulfur content;
detect presence of non-hydrocarbon gases (CO2 and N2);a structure will be charged. Other active petroleum systems
may be present within the exploration area. Trap integrity,
reservoir, or migration issues may prevent charge and
retention for specific traps. The presence of mature
Geology 22 (2005) 457477ological, and biological responses. A Petroleum Seepage
-
sediments. The offshore Gulf of Mexico is a good example
roleumThe common terms used to define seepage type are macro-
and micro-seepage (Abrams, 1992). Macroseepage usually
refers to large concentrations of migrating hydrocarbons,
which are generally visible and related to bulk flow (Darcy
flow). Macroseepage concentrations are generally in excess
of 100,000 ppm (by volume) of total gas and 1000 ppm (by
volume) of hydrocarbon sediment extract. Microseepage
refers to low concentrations of migrating hydrocarbons, not
visiblebut detectablewith standard analytical pro-
cedures. Migration mechanism commonly proposed for
microseepage include buoyancy of micro-bubbles (Price,
1986; Klusman and Saeed, 1996; Saunders et al., 1999;
Brown, 2000). Microseepage concentrations are generally
less than 10,000 ppm (by volume) of total gas and 100 ppmof a region where many areas have experienced active
seepage both at the present time and in the past
(MacDonald et al., 1996). Seepage activity can also be
passive, slow subtle leakage from subsurface to near-
surface sediments. The offshore Navarin and Saint George
Basins (Bering Sea, Alaska) are good examples of passive
seepage (Abrams, 1992). In areas of active seepage,
hydrocarbon movement to the near surface is not always
continuous, but can be episodic (Roberts and Carney, 1997;
Quigley et al., 1999; MacDonald et al., 2000; Abrams and
Boettcher, 2000).
3.2. Seepage type
Defined as the concentration of migrating thermogenic
hydrocarbon relative to in situ material. The in situ material
includes recent organic matter (ROM) derived from pelagic,
or reworked material from land based or subcrop sources.System (PSS) is defined as the interrelationships among total
sediment fill, tectonics (migration pathway), hydrocarbon
generation (source and maturation), regional fluid flow
(pressure regime and hydrodynamics), and near-surface
processes (zone of maximum disturbance, Abrams, 1992).
The petroleum system analysts must firmly grasp the
regional petroleum seepage system to fully appreciate the
significance of anomalous migrated hydrocarbons within
near-surface sediments. Relationships among near-surface
hydrocarbon seepages and subsurface petroleum generation
and entrapment are often complex and their significance
commonly misinterpreted (Abrams, 2002a). Key elements
of the petroleum seepage system include.
3.1. Seepage activity
Defined as the qualitative expression of relative leakage
rates (Abrams, 1989) with no specific relationship to
migration mechanism. The seepage activity can be active,
prolific ongoing leakage from subsurface to near-surface
M.A. Abrams / Marine and Pet(by volume) of hydrocarbon sediment extract.4. Intepretation surface geochemical surveys
4.1. Defining background and anomalous
All land or marine sediments contain some background
level of light, low molecular weight (LMW) and heavier
high molecular weight hydrocarbons (HMW). Identifying
background vs anomalous signatures for near-surface
hydrocarbon measurements can be complicated. An anom-
alous population is defined as a group of samples with total
hydrocarbon concentrations significantly above the estab-
lished background. Surface geochemical measurements
rarely follow a normal distribution but tend to be skewed,
log normal distribution (Fig. 1a). The application of normal
distribution descriptors such as mean, standard deviation,
and variance have no statistical validity in a log normal
surface geochemical dataset. Graphical data analysis
provides a simple and visual process to evaluate sample
distribution and assist in the identification of multiple
populations. The two most common graphical methods best
suited for surface geochemical datasets include frequency
histograms and cumulative frequency. Both methods
provide the interpreter with a quantitative method to
identify the presence of an anomalous population.
4.1.1. Frequency histogram
The histogram, or frequency distribution, separates the3.3. Migration focus
Defined as the major direction of near-surface leakage
relative to the subsurface hydrocarbon generation and/or
entrapment. The migration focus direction can be nearly
vertical when there are major migration pathways such as
faults and diapirs, or, lateral displacement related to basin
fluid flow dynamics (Thrasher et al., 1996). Schumacher and
LeSchack (2002) argue that despite major lateral migration
flow related to regional seals and key carrier beds,
hydrocarbons also leak vertically via the buoyancy of
micro-bubbles.
3.4. Near-surface seep disturbances
Defined as near-surface processes (physical and biologi-
cal) which alter or block the petroleum seepage signals. The
Zone of Maximum Disturbance, known as ZMD (Abrams,
1992), is a shallow near-surface zone where pore water
flushing; partitioning of migrated hydrocarbons between
vapor, solute, and sorbed phases; bacterial alteration; and in
situ hydrocarbon generation have altered the migrating
themogenic hydrocarbon signatures beyond recognition.
Additionally, shallow migration barriers such as hydrates,
permafrost, and cohesive shales can partially block the
migrating hydrocarbons.
Geology 22 (2005) 457477 459data values into bins, shown on the x-axis (Fig. 1a). Number
-
roleum Geology 22 (2005) 457477M.A. Abrams / Marine and Pet460of samples within each bin (frequency class or interval) is
represented on the y-axis. Rectangles are constructed over
each interval with the height being proportional to the
number of measurements (class frequency) falling within
each bin. Histograms are useful for depicting sample
symmetry or skewness. The histogram shape is very
dependent on the number of categories selected.
4.1.2. Cumulative frequency
A cumulative frequency, also known as quantile plot,
graphs cumulative frequency percent on the x-axis and the
measured geochemical parameter on the y-axis (Fig. 1b).
Three advantages of using a cumulative frequency plot over
the histogram plot are arbitrary categories (bins) are
Fig. 1. Population distribution of sediment headspace gas (P
C1C5) from sedime
field. (a) Histogram. (b) Cumulative frequency plot.required, all the data are displayed, and every point has a
distinctive position without overlap.
Fig. 1a displays a histogram and Fig. 1b a cumulative
frequency graphical plot for 36 core samples collected
within leakage zones above a field in offshore Gulf of
Mexico. Sediment samples with headspace gas concen-
trations less than 200 ppm by volume are considered to be
background (29 samples). Whereas sediment samples with
headspace gas concentrations greater than 100,000 ppm by
volume are considered to be anomalous (7 samples). In this
example, the separation between background and anom-
alous is relatively straightforward. The difficulties begin
when the separation of background and anomalous is not as
pronounced due to mixing, sampling problems, reworking
nt cores collected within leakage zones above an offshore Gulf of Mexico
-
source rocks, transported hydrocarbon, fractionation, or in
situ alteration-generation.
Most interpreters assume the anomalous samples are
non-indigenous (migrated) thermogenic hydrocarbons.
However, some anomalous populations may reflect indi-
genous or syngenetic hydrocarbons from bacterial activity
or an artifact of differences in sediment type (lithology),
sampling depths, and/or sampling times.
4.2. Determining origin of anomalous hydrocarbons
4.2.1. Light hydrocarbons (gas)
The molecular characteristics of surface sediment gases
vary with the type of gas present in the sediment (bacterial
vs thermogenic), as well as with gas extraction method
compositions and isotopic ratios (Abrams, 1989). Table 1
lists the gas compositions and isotopic ratios most
commonly used to evaluate sediment gases.
The relative amounts of methane, ethane, propane,
butane, and propane is the first clue to origin. Methane
may be derived from either thermogenic or bacterial
processes. The wet gases (ethane, propane, butane, and
pentane) are believed to be derived from only thermogenic
sources. Studies over the years, both in the laboratory as
well as empirical observations, indicate traces of ethane,
propane, and a number of other light hydrocarbons can
also be formed microbiologically (Hunt et al., 1980; also see
Davis and Squires, 1954; Oremland, 1981; Oremland et al.,
1988). Recent work, including compound specific isotopic
studies, have shown that traces of a number of light
ses
Pbove b
Gas wet percent C2 KC5= C1 KC5 !100 Evaluate thermogenic (non-
(non-
) vs u
rial
rial an
nate
M.A. Abrams / Marine and Petroleum Geology 22 (2005) 457477 461contribution
% Methane C1=P
C1C5 !100 Evaluate thermogenic
contribution
Ethane/ethene and propane/propene Saturate (thermogenic
(bacterial)
Carbon isotopes: d13C1, Dd13C1 and d
13C2,
Dd13C2 and d13C3
Thermogenic vs bacte
Hydrogen isotope: dDCH4 Thermogenic vs bacte
(fermentation vs carboTotal HC gas: C1C5 Identify anomalous (a
HC gasP P(Horvitz, 1985; Abrams, 1996; Bjoroy and Ferriday, 2002).
This section concentrates on gas parameters commonly used
to evaluate anomalous hydrocarbon source: bacterial,
thermogenic, or mixture. Analytical method variability
will be discussed in the Problems and Pitfalls Analytical
Methods section.
Conventional interpretation parameters developed for
reservoired hydrocarbon gas samples are not as effective
with surface geochemical screening datasets. Unfortunately,
hydrocarbon seepage found in many marine surveys are
fractionated (in situ, during migration, or sampling),
partitioned (based on the properties of the hydrocarbon
compound and physical environment), altered (bacterial),
and/or mixed rendering conventional reservoired interpret-
ation schemes relatively useless in most areas with low
levels of seepage.
Natural gases are characterized using three analyses: gas
composition (C1C5 and non-hydrocarbon components such
as CO2, O2, and N2), compound specific carbon isotopic
ratio (d13Cn), and hydrogen isotopic ratio (dDCH4) (Schoell,1983). Gas compositions and isotopic ratios depend on type
and maturity of source. Alterations during migration or
bacterial activity and mixing will also affect the gas
Table 1
Gas interpretation parameters commonly used for near-surface sediment ga
Parameter Information providedhydrocarbons are produced by microbiological processes
and a number of the organisms responsible have been
identified (Whiticar, 1999). In spite of this recent work, this
concept is still controversial within the petroleum geo-
chemical community. What is agreed is samples with
elevated total gas concentrations, and a wet gas fraction
greater than 5.0% PC2CC3=P
C1KC3!100, aremost likely derived from a thermogenic process (Bernard,
1978; James, 1983; Schoell, 1983). Thus, the gas wetness
ratio PC2 KC5=P
C1KC5!100, which includes notonly ethane and propane, but butane and pentane, is a
common parameter to help evaluate bacterial vs
thermogenic.
Ethene (ethylene) and propene (propylene) belong to a
class of hydrocarbons known as olefins. They contain one
double bound and therefore are unsaturated with respect to
hydrogen, and are almost always found in trace amounts in
surface sediments (Whelan et al., 1988). These compounds
appear to be rapidly hydrogenated via near-surface
anaerobic microbial processes and so are not detected in
measurable amounts in the vast majority of reservoired
gases. These compounds are derived primarily from
bacterial processes, not from conventional thermogenic
Interpretation process
ackground) total Histogram to identify background vs population
bacterial) Identify samples with elevated wet gas fraction and
anomalous total HC gas
bacterial) Identify samples with elevated % wet gas and
anomalous total HC gas
nsaturate Identify samples with anomalous total HC gas and
elevated ethane/ethene and propane/propene ratios
Identify samples with anomalous total HC gas and
methane carbon isotopes and/or wet gas isotopic
separations indicative of thermogenic origin
d type bacterial
reduction)
Identify samples with anomalous total HC gas,
determine C1 hydrogen isotopes for anomalous
samples, and plot on d13C and dD crossplot1 CH4
-
dramatically affects methane carbon isotopes, making them
heavier in 13C, so that resulting values from this process
overlap with the thermogenic petroleum range.
It is important to understand this process because
carbonate reduced methane is isotopically lighter than
methane formed by fermentation. Bernards (1978)
interpretation scheme for sediment gases conclude that
roleum Geology 22 (2005) 457477and catagenic reactions (Bernard et al., 2002; Ullom, 1988).
Thus, the ratio of ethane (thermogenic) to ethene (bacterial)
provides information on the gas origin. Bernard et al. (2002)
used the ethane/ethene ratio, in combination with the
isotopic ratio of methane, to evaluate the thermogenic
contribution. One must use this ratio, as well as the
propane/propene ratio, with caution because olefins are
more readily altered than alkanes in subsurface processes.
Compound-specific isotopic ratios numbers have
evolved as an important tool in surface geochemistry, with
the IR-GC/MS (continuous flow isotope ratio gas chroma-
tography/mass spectrometry). IR-GC/MS allow for isotopic
measurements in sediments with relatively small concen-
trations of gas. Early studies relied only on methane carbon
isotopes (Horvitz, 1981; Faber and Stahl, 1983; Abrams,
1989) due to equipment limitations. Thermogenic methane
is enriched in 13C compared with bacterial derived methane,
with values ranging from K50 to K20. The variation inethane, propane, and butane carbon isotopic ratios, as well
as hydrogen isotopic ratios, are additional ways to evaluate
sediment gas origin and possible secondary fractionation
(post-generation). The alteration story is much more
complex than originally thought because of anaerobic
microbial degradation of methane, which causes the isotopic
ratio to get heavier (less negative). Hydrogen isotopes
provide additional information which can help sort out a
complex history (Whiticar, 1999).
Compound-specific isotopic analysis (CSIA) also helps
biochemists understand bacterial formation of methane.
Methane generated in shallow marine sediments from
methyl type fermentation, such as acetate reduction
(shown below), has different carbon and hydrogen isotopic
signatures than methane formed by CO2 (reduction):
Carbonate reduction : CO2 C8HC0CH4 C2H2O
Acetate fermentation : CH3COOH0CH4 CCO2
In most marine sediments, sulfate rich zones curtail
methanogenesis. Non-methanogens (sulfate reducing bac-
teria) metabolize available labile carbon. Methanogensis
start using competitive substrates once available dissolved
sulphate is exhausted (sulfate reduction zone). This is
generally at a depth of 1 to 4 meters in most marine
sediments. Carbonate reduction becomes the dominant
methanogenic pathway under these conditions because
methanogenic substrates such as acetate are depleted, and
bicarbonate is availabile. Refer to Whiticar (1999) for
greater detail on the systematics of bacterial formation and
oxidation of methane. Oremlands and Whiticars work also
show that other methyl precursors are possible: methyl-
amine, methanol, methyl sulfides in specific environments
(Oremland et al., 1988). Chemotrophic methane oxidation is
an important process that appears to be very widespread in
anaerobic environments, which could include oil seeps and
M.A. Abrams / Marine and Pet462reservoirs (Larter et al., 2000). Unfortunately, the processmethane with an isotopic ratio lighter than K60 would bederived from a bacterial source. A 50:50 mix of thermogenic
with a methane isotopic ratio of K40, and carbonatereduced gas with methane isotopic ratio of K110 wouldresult in a gas with a methane isotopic ratio of K75. Evena gas which is 80% thermogenic would result in a mixed gas
with a methane isotopic ratio of K64 (Table 2). Based onthe isotopic ratio of methane alone, this would be classified
as bacterial using most interpretation charts. The presence
of elevated wet gas concentrations (wet gas ratio), and
ethane and propane isotopic ratios (if available), should
provide clues that these mixed gases have a thermogenic
component. Thus, understanding that carbonate reduced
gases are very isotopically light and do mix with migrating
thermogenic gases is important when evaluating gases
extracted from marine sediments. Claypool makes the
important point in one of his early papers that the way to
predict the microbial reduction of CO2 to CH4 is to look at
the differences in delta 13C between CO2 and methane in the
system, which always gives a constant value if anaerobic
reduction of CO2 is involved (Claypool and Kaplan, 1974).
Secondary alteration such as anaerobic bacterial activity
produces methane enriched in 13C. Resulting methane has
an isotopic ratio very similar to thermogenic derived
methane (Abrams, 1989, 1996). Bacterial consumption of
methane proceeds significantly faster than does that of
ethane, propane, and butane (Whiticar, 1999). The result is a
gas with elevated gas wetness. The ethane, propane,
and butane carbon isotopic ratios (d13Cn) assist in evaluating
thermogenic contribution. Because the ethane plus
hydrocarbons are derived primarily from thermogenic
sources, the isotopic separations between ethane and
propane, and propane and butane, are strongly dependent
on maturity level, when there is little or no secondary
alteration (James, 1983).
The hydrogen isotopic ratios (dDCH4) differentiatebacterial methane gas from thermogenic. Methanogens
derive a significant proportion of their hydrogen from
interstitial water during methane formation by carbonate
reduction (Whiticar, 1999). The dDCH4 for methane is
Table 2
Isotopic ratios for mixes of thermogenic and bacterial gases
Thermogenic
d13C1ZK40Bacterial
d13C1ZK110Resulting mix
d13C1
80% 20% K64
50% 50% K7540% 60% K82
-
derived from bacterial carbonate reduction range from
K150 to K250 (SMOW).The above gas composition and compound-specific
isotopic ratios are best used only for samples with elevated
concentrations. Samples with low concentration levels
(background) may not be representative of migrated gases.
Background (low concentration) samples are subject to
greater variation in composition among gas components due
to various alteration and fractionation processes. Headspace
extracted gas from 70 Gulf of Mexico seabed cores
collected above or near a subsurface petroleum accumu-
lation display four groups of samples (Fig. 2):
Group 1 Background: total gas concentrations less than
1000 ppm by volume and wet gas fraction less
than 0.05 (5.0%).
Group 2 Fractionated: total gas concentrations less than
1000 ppm by volume and wet gas fraction greater
than 0.05, up to 0.18 (18%).
gas fract
In con
based on wet gas percents and/or methane isotopic ratios.
However, when only traces of gases are present, small
alterations in one or more of the compounds present can
produce very misleading results. The problem is amplified
many times in depending on ratios involving very small
values, as occurs in analyzing samples with only traces of
hydrocarbons.
4.2.2. High molecular weight hydrocarbons (C15 plus)
The most common screening procedures currently used
for evaluating the presence of thermogenic high molecular
weight (HMW) hydrocarbons (C12 plus), include whole
extract gas chromatography (GC) and total scanning
fluorescence (TSF). A dried sediment sample is ground to
a uniform size by weight, extracted with an organic solvent
(Soxhlet or ASE, accelerated solvent extractor), and lastly
concentrated. Many surface geochemical laboratories cur-
rently use low polarity solvents such as hexane. Low
polarity solvents extract only low polarity compounds.
on P
M.A. Abrams / Marine and Petroleum Geology 22 (2005) 457477 463Fig. 2. Total headspace extracted sediment gas (P
C1C4) vs wet gas fractiabove an ofconcentrarating thermogenic gases.
clusion, care must be taken when working with low
tion samples. They may appear to be thermogenicfrom Gro
from migsed on the elevated total gas concentration and wet
ion). Compound-specific carbon isotopic ratios
up 4 samples confirm these samples are derivedGroup 3 Bacterial: total gas concentrations greater than
1000 ppm by volume and wet gas fraction less
than 0.05 (5.0%).
Group 4 Thermogenic: total gas concentrations greater
than 1000 ppm by volume and wet gas fraction
greater than 0.10 (10%).
Group 1 and 2 provide no information on migrated
thermogenic gases. Group 3 is most likely in situ derived
bacterial gas. Group 4 appears to be migrated thermogenic
gases (bafshore Gulf of Mexico field.C2 KC4=P
C1 KC4 from sediment cores collected within leakage zonesAnother approach would be to use a mixture of varying
range of polarity solvents to extract all components and then
separate the petroleum related compounds (saturated
hydrocarbons, unresolved complex mixture (UCM),
aromatics, and polars such as NSO and asphaltenes) from
the ROM (saturated hydrocarbons, ketones, alcohols, and
fatty acids) using multi-component silica gel column
chromatography.
4.2.2.1. Whole extract gas chromatography. Sediments
containing moderate levels of upward-migrating thermo-
genic high molecular weight (HMW) hydrocarbons
are characterized by an UCM, discernible C15C32n-alkanes and isoprenoids, and an overprint of odd n-
alkanes greater than C23 from terrigenous plant biowaxes.
-
fluorescence intensity) are adjusted by multiplying
Table 3
Interpretation parameters for sediment whole extract gas chromatography (GC)
Parameter Provides information on
Total UCM (mg/g; unresolved complex mixture) Quantification of extractable hydrocarbons not resolvable in gas chromatography
(mainly NSO and asphaltene compounds)
UCM (mg/g)!C23 UCM representative of migrated thermogenic portionUCM (mg/g)OC23 UCM representative of recent organic matter portion
resen
resen
n of to
M.A. Abrams / Marine and Petroleum Geology 22 (2005) 457477464Samples containing elevated bitumens often are extensively
biodegraded containing only a UCM (Brooks and Carey,
1986). Whole extract gas chromatograms can be subdivided
into several major groups:
Resolvable peaks: The total hydrocarbon fraction from a
non-degraded petroleum seep is usually dominated by n-
alkanes, with a lesser amount of branched alkanes
(including isoprenoids) as well as some cyclic alkanes,
and alkyaromatics.
Unresolved complex mixture (UCM): The unresolved
complex mixture, otherwise known as UCM and naphthe-
lene hump, is a quantification of unresolvable hydrocarbon
and non-hydrocarbon compounds.
Recent organic matter (ROM): Extract gas chromato-
grams from recent sediments generally display an odd
carbon preference within the n-C25 and n-C33 range due to
the elevated contribution from recent plant waxes.
Key parameters commonly used to evaluate sediment
extract chromatograms for the presence of migrated
themogenic hydrocarbons include: total extractable
material (EOM, total concentration of solvent extractable
material in ng/g), total unresolved complex mixture (UCM:
total amount of unresolved material in mg/g by weight),unresolved complex mixture greater or less than C23(relative amounts of OC23 ROM vs !C23 migratedhydrocarbons), and total alkanes (total amount of alkanes
greater than n-C15 in ng/g) (Table 3).
4.2.2.2. Fluorescence spectrometry. Total scanning fluor-
escence (TSF) detects and measures organic compounds
containing one or more aromatic rings. Oil seepages have
distinctive fluorescence fingerprints because they contain
petroleum related compounds with one or more aromatic
n-Alkanes (ng/g) !C23 n-Alkanes repn-Alkanes (ng/g) OC23 n-Alkanes repTotal EOM ppm by weight (extractable OM) Quantificatiorings and their alky homologues. A solution of sediment
extract is irradiated with light from about 250 to 500 nm at
10 nm intervals. The fluorescence emissions spectrum is
recorded for each excitation wavelength again scanning
Table 4
Interpretation parameters for sediment extract total scanning fluorescence (TSF)
Parameter Provides information on
MFI (units) Max_Em and Max_Ex (1) Magnitude/level of seepage (macro vs
R1: 360/320 nm at 270 nm (1) Type of seepage (oil, condensate, recen
Type of equipment Changes in MFI values due to equipment
Dilution Dilution factor used to correct MFImeasured MFI by the dilution factor to obtain a corrected
MFI:
Corrected MFI Z Measured MFI!Dilution factor
4.2.2.3. Gas chromatography/mass spectrometry. When
anomalous high molecular weight hydrocarbons are found
with the screening procedures, further molecular character-
ization is helpful. GC/MS, or gas chromatography/mass
spectrometry provides detailed molecular information on
biological markers. Biological markers are chemical
compounds in the reservoired oils and sediment extracts
with the basic molecular structure which can be linked to a
known biological precursor. Different organic source facies
contain different assemblages of organisms (bacteria, algae,
marine algae, and higher plants). GC/MS biomarker data, in
conjunction with non-biomarker parameters, resolve the
organic source facies depositional environment, as well asfrom about 250 to 500 nm building a 3D spectrum (Brooks
et al., 1983). The emissions maximum fluorescence
intensity (MFI) is recorded along with emissions wave-
length (Max_Em) and excitation wavelength (Max_Ex)
(Table 4). A second parameter commonly used to evaluate
TSF data is the R1 ratio. R1 is the ratio of emissions at
360 nm compared to emissions at 320 nm when excitation at
270 nm is used (Table 4). This ratio characterizes the shape
of fluorescence spectra which can be related to API gravity
using an empirical relationship derived from a calibration
set (Barwise and Hay, 1996).
Samples with relatively large concentrations of extract
may require dilution. If so, measured MFI (maximum
tative of migrated thermogenic portion
tative of ROM portion
tal extractable HClevel of thermal maturity. Key biomarker compounds are
measured in oils and seep extracts, therefore, providing a
method to correlate surface seep to subsurface oils and/or
source rocks (Hunt, 1996; Peters and Moldowan, 1993).
micro), (2) type of seepage (oil, condensate, recent organic matter)
t organic matter), (2) API gravity when calibrated (see Barwise et al., 1996)
type
-
alkanes with a predominance of odd-over-even carbon
roleum Geology 22 (2005) 457477 4654.3. Integration of LMW and HMW geochemical data
Interpretation of surface geochemical data to evaluate
subsurface hydrocarbon generation and migration first
requires that the gas (low molecular weight or LMW) and
liquid (high molecular weight or HMW) hydrocarbon data
be integrated. Not all analytical procedures provide similar
results. The differences provide a way to classify anomalous
hydrocarbons detected in near-surface sediments. There are
five general thermogenic signatures of LMW and HMW
geochemical data:
Active (fresh) migrated thermogenic oil. Sediment
samples have elevated total hydrocarbon gas (anoma-
lous) with thermogenic gas signatures (elevated gas
wetness and thermogenic d13Cn) as well as elevated high
extracted HMW hydrocarbons with a relatively unde-
graded thermogenic gas chromatogram and biomarker
signatures.
Relict (passive) migrated thermogenic oil. Sediment
samples contain background total hydrocarbon gas with
anomalously high extracted HMW hydrocarbons. The gas
chromatogram is severely degraded with only an elevated
UCM. In addition, the biomarker data displays strong
indications of degradation with only the more resistant
thermogenic compounds present.
Relict migrated thermogenic oil with possible recharge.
This is similar to the Relict (passive) Migrated Thermo-
genic Oil signature but with an addition of resolvable
compounds in the C12C20 range on the gas chromato-
gram and above background thermogenic gas (elevated
gas wetness and thermogenic d13Cn). These features
indicate a relict degraded seep has been recharged with
recent seepage.
The fourth and fifth thermogenic signatures, transported
and reworked, do not indicate local seepage. They are
discussed in detail in Section 4.45.
4.4. Pitfalls and problems
4.4.1. Recent organic matter interference
Surface sediments contain ROM derived from
rock fragments with organic content and/or biological
remains unrelated to hydrocarbons migrating from depth.
The type of in situ extractable organic material present in
the sediment sample will be dependent on the origin
(provenance) and local biological setting. The indiscri-
minate extraction process dissolves all organic matter,
including both the migrated seep hydrocarbons from
subsurface reservoirs or mature source rocks, and in situ
organic materials. The presence of ROM may mask
and/or modify peaks on the extract gas chromatograms
(GC) and gas chromatography-mass spectrometry
(GC/MS) fragmentograms, and alter fluorescence spec-
trometry results relative to migrated thermogenic hydro-
carbons from depth. Whole extract GC, TSF, and GC/MS
M.A. Abrams / Marine and Petdisplay predictable changes depending on the relativenumbers (Fig. 3a). By contrast, extract GC for cores
dominated by thermogenic hydrocarbons display abundant
saturate and isoprenoid peaks, raised baseline from UCM,
and C23C35 n-alkanes with some predominance of even
over odd carbon numbers (Fig. 3b).
4.4.1.2. Total scanning fluorescence. TSF for surface
sediment cores with a thermogenic oil signature display
maximum fluorescence intensity excitation (Max_Ex) and
emission wavelengths within the thermogenic petroleum
range; excitation between 280 and 330 nm and emission
between 380 and 400 nm (Fig. 4a) By contrast TSF
fluorograms for cores with a ROM signature display
maximum fluorescence intensity excitation (Max_Ex) and
emission (Max_Em) wavelengths within the perlylene
range; excitation 330C nm and emission 400C nm(Fig. 4b).
4.4.1.3. Gas chromatography-mass spectrometry. The
interpretations of biomarker data from surface sediment
seepages requires a different approach than conventional
oiloil and oil-source correlation. Because ROM inter-
feres and biodegradation is common, most conventional
biomarker ratios do deviate from true migrated value as
the relative amounts of in situ ROM increase relative
to the migrated hydrocarbon (Fig. 5). The key is not to
use the conventional biomarker ratios found in
publications such as Peters and Moldowans (1993)
Biomarker Guide but instead use lesser known, yet
previously established biomarker parameters (diasterane
equivalents and aromatic parameters) and substitute
traditional biomarker ratios with novel ratios: extended
tricyclics ratio, gammacerane to diahopane index, and
oleanane to diahopane index (Holba and Huizinga, 2002).
These novel ratios are less susceptible to interferences by
recent organic matter and biodegradation than found in
the conventional ratios.
4.4.2. Identifying transported and reworked thermogenic
hydrocarbons
Thermogenic HMW hydrocarbons extracted from shal-
low sediments may not be derived from local seepages but
could be derived from materials within the sediment
provenance (reworked mature source rock) or carried by
displaced sediments which contain migrated mature hydro-amount of recent organic matter and migrated thermo-
genic hydrocarbons (derived from the thermal breakdown
of organic matter) (Abrams et al., 2001a,b).
4.4.1.1. Gas chromatograms. Extract GC for surface
sediment cores dominated by ROM display abundant
unsaturated compounds, low isoprenoids, and C23C35 n-carbons (transported).
-
M.A. Abrams / Marine and Petroleum Geology 22 (2005) 4574774664.4.3. Reworked signature
Recently deposited thermally mature source rock derived
from near-by uplifted and eroded sediment provenances can
be confused with localized migrated hydrocarbon seepage
(Piggott and Abrams, 1996). Key geochemical character-
istics which indicate reworked mature source rock may be
present includes strong thermogenic signal with little or no
ROM character; extract GC with a full compliment of
normal paraffins (no evidence of bacterial alteration);
relatively low levels of high molecular weight hydrocarbon
extract (solvent extract less than 100 mg/g extract); little or
Fig. 3. Solvent extract GC from a Gulf of Mexico seabed geochemical survey: (a
dominance.no associated sediment gas, elevated total organic carbon;
thermogenic seep signatures present in more than 30% of
cores; and cores with a thermogenic signature within and
away from migration pathways zones. If this geochemical
signature is present, the following additional information
will provide confirmation that a reworked source rock is
present: biostratigraphic evaluation of core samples to look
for palynological and paleontological evidence of reworked
detrital kerogen; Rock-eval pyrolysis and pyrolysis-GC
(elevated S1 free hydrocarbons), geologic maps with mature
source outcrops present in study area; and comparison of
) migrated thermogenic hydrocarbon dominance, (b) recent organic matter
-
chem
roleum Geology 22 (2005) 457477 467Fig. 4. Solvent extract TSF fluorograms from a Gulf of Mexico seabed geomolecula
source ro
4.4.4. Tra
Near-s
carbons
along wit
downdip.
contain
hydrocar
A case
by Cole
hydrocar
surveys i
Group 1
Group 2
The or
1 (macro
on drilli
(micro se
matter domM.A. Abrams / Marine and Petr characteristics of seep to local provenance
ck outcrop.
nsported signature
urface thermogenic high molecular weight hydro-
derived from subsurface leakage can be carried
h displaced sediments and transported to locations
The displaced thermogenic hydrocarbons will
relatively low concentrations of thermogenic
bons relative to localized hydrocarbon seepage.
history of the eastern deepwater Gulf of Mexico
et al. (2001) found two anomalous populations of
bons (above general background based on multiple
n study area):
Sediment cores with very large concentrations of
thermogenic hydrocarbons and migrated mature
hydrocarbon signal much greater than in situ
ROM;
Sediment cores with low concentrations of
thermogenic hydrocarbons and in situ ROM signal
greater than thermogenic.
ganic facies based on biomarker results for Group
seepage) match the subsurface hydrocarbons based
ng results. The organic facies for Group 2
epage) did not match the subsurface hydrocarbons
inance.ical survey: (a) migrated seep hydrocarbons dominance, (b) recent organicbut was similar to the organic facies found in shelf-
reservoired hydrocarbons. Shallow high resolution seismic
profiles indicate slope unstability and the movement of
sediments from updip locations to the transported signal
area. Furthermore, fluid flow models strongly suggested the
Group 2 anomalous seabed cores are unrelated to the
subsurface petroleum system, where as the migration flow
paths only go to the Group 1 seep sites (Cole et al., 2001a,b).
Thus, the interpretation of transported hydrocarbons is not
Fig. 5. Changes in conventional biomarker ratios with increased ROM input
relative to migrated thermogenic hydrocarbons (adapted from Abrams and
Boettcher, 2000).
-
only based on geochemical data, but an evaluation of
sediment transport and migration pathway analysis.
The identification of transported thermogenic hydrocar-
bons is subtleand at times difficult to interpretbut
extremely important. Several ways to identify transported
hydrocarbon seepage include:
4.4.4.1. Seepage magnitude. Transported hydrocarbon
seepage will have lower concentrations of hydrocarbons
relative to in situ migrated hydrocarbon seepage. Cole et al.
(2001) have recognized a group of samples called low
confidence based on an extensive Gulf of Mexico database.
The low confidence cores contain MFI values from TSF
analysis less than 30,000 units and UCM values from GC
analysis less than 100 mg/g, and have been shown by
4.4.5. Variation in anomalous signature due to different
analytical procedures
Multiple analytical procedures have been developed to
remove migrated gases from sediments (Abrams, 1996;
Abrams et al., 2001a,b). The terminology used for each
sediment gas extraction method generally refers to the
physical removal process and not the phase. Migrated
gases are either in the interstitial pore spaces as a free or
dissolved phase, bound to mineral or organic surfaces, or
entrapped in crystal inclusions (Fig. 6). The exact nature
(physical binding state) of the gases removed by each
procedure is still poorly known; therefore, these procedures
should be considered to be operational definitions and not
representative the actual in situ physical state of the gases
in the sediment. Consequently, it is very important, in
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M.A. Abrams / Marine and Petroleum Geology 22 (2005) 457477468biomarker analysis to be transported not in situ seepage.
These cut-off values will vary for different seepage systems
(seepage activity and type).
4.4.4.2. Location seepage. Transported hydrocarbons will
be present in areas away from major migration pathways as
well as within migration zones. Thus, sampling programs
should contain some core locations away from potential
migration pathways and within areas of major sediment
transport.
4.4.4.3. Seepage activity. Transported hydrocarbons are
most likely to occur in basins with prolific active
hydrocarbon seepage (Abrams et al., 2001a,b). Examine
geophysical, geological, and geochemical data to document
seepage activity and assist in evaluating transported
hydrocarbon seepage risk.
4.4.4.4. Variation in seepage with core depth. Compare
geochemical signal from different parts of the core. Do the
thermogenic hydrocarbon anomalies correspond to specific
depositional packages? Transported hydrocarbons should
correspond to specific sediment packages re-deposited by
major fluvial and/or slope failure systems.
Bound gasBound gas
Interstitial g asInterstitial g asNon-mNon-m
MecMec
Aci d Acid e
VacuumVacuu mbound to mineral and organic surfaces; or entrapped in crystal carbonate inclusions
Phase
Bound gasBound gas
Interstitial g asInterstitial g asNon-mNon-m
MecMec
Aci d Acid e
VacuumVacuu m mi s s;
in
Bound gasBound gas
Interstitial g asInterstitial gasNon-mNon-m
Mec
Aci d Acid
Vacuums;
Mec
Vacuum
interstitial pore gas as dissolved or free phaseFig. 6. Sediment gas extrcomparing results from different laboratories or times, to
make sure that the same experimental procedures were
used. The removal procedures range from simple shaking,
mechanical break-up, vacuum, and chemical (acid treat-
ment of sediment).
Interstitial gases can be sampled by either non-mechan-
ical or mechanical methods:
Non-mechanical: The headspace gas collects interstitial
gases which can be released by simple shaking. The sample
can contains an aliquot of sediment, degassed distilled or
filtered seawater, and air or inert gas (helium or nitrogen).
The can is vigorously shaken using a paint shaker and
heated prior to sampling (laboratory dependent). The
interstitial gases within sediment pore spaces move to the
headspace within the can which is then sampled through
silicone septum on the top of specially modified can
(Bernard, 1978).
Mechanical. The ball mill gas extraction method utilizes
a steel ball within a stainless steal container to mechanically
break up a measured aliquot of unconsolidated sediments.
The container is vigorously shaken. The steel ball pulverizes
sediment sample, releasing gases which are collected from
the container headspace through a septum (Bjoroy and
Ferriday, 2002).
anicalnical
ica l1cal1 Blender (rotating blade)
ctio n3tion 3
orp tion 4orp tion 4
Extraction
anicalnical
ica l1cal1
ctio n3tion 3
orp tion 4orp tion 4
anicalanical
ica l1
ctio n3ction3
orp tion 4
Disrupter (fixed blade)
Ball & mill (ball & vessel)cal1
orption4
Sorbed (acid-vacuum)
Adsorbed (vacuum)
Headspace (shake can)
1 physical break up mechanism2 also called occluded3 Horvitz method4 See Zhang(2003)action procedures.
-
geochemical extraction procedure to ever know the
absolute amount or state of compounds extracted. The
best that can be hoped for is to obtain consistent results from
sample to sample, so comparisons are possible. More
evaluation to relate extraction procedures to in situ physical
state of hydrocarbons recovered is required.
4.4.6. Variation in anomalous gas signature due to near-
surface sediment type
Sediment gas concentrations and compositions will vary
by sediment type (grain size and composition). Partitioning
of migrating gases in near-surface sediments depends on
many factors: migration phase (vapor or solute), gas
characteristics (solubility, Henrys constant, and sorption
kinetics), sediment characteristics (grain size, type minerals,
organic matter content, and type of organic matter), and
sediment gas extraction method (headspace, blender,
Fig. 7. Comparison of gas composition and isotopic compositions using
different gas sediment extraction methods: (a) headspace and blender
hydrocarbon gas compositions from replicate samples (adapted from
Abrams, 1992), (b) adsorbed and headspace methane carbon isotopic
(d13C1) compositions from replicate samples (adapted from Abrams, 1989).
roleumThe blender gas method, also known as loosely bound or
cuttings, utilizes a blender to mechanically break up aliquot
of sediment and release interstitial gases within unconso-
lidated sediments. The released gases are sampled through a
septum on the blender cap (Abrams, 1996).
The disrupter gas method uses a fixed blade to break up
sediment within a sealed chamber. The sediment sample is
moved through fixed blades by vigorous unidirectional
shaking. The released interstitial gases are sampled through
a septum on the top of disrupter chamber (Abrams, 2004).
Bound gases can be sampled by two basic methods:
The acid extractionalso known as Horvitz, adsorbed,
sorbed, and boundmethod captures gas bound to the fine
grain sediments (Horvitz, 1981), captured within authigenic
carbonate (Abrams, 1996), or bound by structured water
mineral surfaces (Whiticar, 2002). The coarse-grained
fraction (greater than 63 mm) is removed by wet sieving abulk sediment sample. The fine-grained portion (63 mm andsmaller) is heated in phosphoric acid in a partial vacuum to
remove bound hydrocarbons. A modified version, called
called microdesorption, of the original Horvitz method-
ology is used by Whiticar (2002).
Vacuum desorption also removes the bound gases and is
similar to the acid extraction method but does not include
the addition of acid (Zhang, 2003).
Horvitz (1981) reported that different gas sediment
extraction methods (shaking-headspace, blender, and acid
extraction) provide different results on replicate samples.
Studies by the author in the early 1980s provided similar
results (Fig. 7a and b) (Abrams, 1989). Bjoroy and Ferriday
(2002) data support similar conclusions. Horvitz (1981,
1985) and Bjoroy and Ferriday (2002) both concluded the
adsorbed sediment gas extraction methods were superior
since resulting sediment extracted gases contain higher wet
gas concentrations. Bjoroy and Ferriday (2002) concluded
that the ball mill was also superior since the resulting gases
contain higher wet gas concentrations. Without any
comparison to the migrated gas composition, it is imposs-
ible to verify their conclusions. One needs to compare the
sediment and reservoir gas composition in order to make
such a conclusion. Abrams (1989) did compare the sediment
extracted methane gas isotopic composition from
two different sediment extraction methods (adsorbed and
headspace) to the reservoir gases in a leaky system (bulk
flow via a leaky fault). Abrams concluded the adsorbed
extracted sediment gases compared well with the reservoir
gases (Fig. 7b). Additional studies are currently
underway by the author to evaluate the various sediment
gas extraction methods under controlled laboratory con-
ditions (Abrams, 2002b).
In the authors opinion, the only statement which can be
made with confidence is that different sediment extraction
methods do provide different gas compositions and com-
pound specific isotopic ratios. To determine which method
best represents the in situ gas composition and isotopic ratio
M.A. Abrams / Marine and Petrequires additional study. It is almost impossible with anyGeology 22 (2005) 457477 469mechanical, or acid extraction).
-
Surface geochemical surveys rarely evaluate the sedi-
ment characteristics and assume different distributions of
near-surface sediment gases reflect only the presence of
migrated thermogenic gases. In cases of very large-volume
seepage (macro), the effect of sediment is most likely
second order, and has minimal effect on final interpretation.
But in areas of lower-volume seepage, the variation in total
sediment gas concentrations and gas compositions are
greatly affected by the type of analysis and sediment type.
The headspace and blender methods examine free or
interstitial gases. Abrams (1989) demonstrated the varia-
bility of free (interstitial) sediment gases by sediment size
(percent sand, fraction greater than 63 mm).Horvitz (1980) noted the effect of sediment grain size on
ethane plus adsorbed hydrocarbons in the Gulf of Mexico
seabed coring surveys. He concluded that the differences
were the result of highly adsorptive clays present in
type or grain size, there is a good chance the anomalous
population is not related to local seepages.
4.4.7. Comparison of near-surface sediment and reservoir
gas composition
Few published studies compare surface gas compositions
and compound specific isotopic ratios to subsurface trapped
gases. A recent paper given by Whiticar at the 2004 AAPG
conference concluded that the sorbed surface gases
compared well with the subsurface reservoired gases
(Whiticar, 2004). Studies by the author in the offshore
Gulf of Mexico, using 15 piston cores sampled at varying
depths collected along key migration pathways (as deter-
mined by seismic) and over a recent discovery, did not look
similar. The headspace extracted sediment gases ranged
from 0.01 to 32.7% gas wetness for samples with above
background concentrations (greater than 10,000 ppm by
Th
M.A. Abrams / Marine and Petroleum Geology 22 (2005) 457477470the surface sediments. Adsorbed (acid extraction) gases
may also vary by composition (mineralogy). Shallow
sediment samples were collected using a grid survey over
two onshore fields during a recent calibration study (Abrams,
2002b). The Area 1 samples contain adsorbed gas concen-
trations between 10 and 100,000 ppm with one value around
300,000 ppm. Area 2 contain samples with adsorbed gas
concentrations from 100,000 to 300,000 ppm with one value
around 700,000 ppm (Fig. 8). The contractor report
indicated Area 2 is above a petroleum bearing reservoir
whereas Area 1 was not. In reality both sets of samples were
collected above petroleum bearing traps. Area 1 has CaCO3less than 30% and Area 2 has CaCO3 greater than 30%. The
differences in gas volumes using the adsorbed sediment gas
extraction method appears to be unrelated to presence of
hydrocarbon accumulation but controlled by CaCO3. This is
not a unique observation, and sediment type should be
considered when evaluating any surface geochemical survey
data, especially in areas of low volume seepage. If the
anomalous population is strongly correlative to sedimentFig. 8. Variation in adsorbed (acid extraction) sediment gas concentratThe samples with methane isotopic compositions lighter are
the result of mixing with in situ derived bacterial gases. The
samples with methane isotopic compositions heavier are the
result of secondary alteration due to bacterial oxidation.
There are several possible explanations for the differ-
ences between near surface sediment and reservoir gases:
Sediment extraction method fractionation (Abrams,1989, 1996; Abrams et al., 2004);
Migration fractionation (chromatographic effect, Kroossand Leythaeuser, 1996);
Secondary alteration (bacterial activity); Mixing with in situ derived bacterial gases.Kresionse reservoir methane gas ranged from d13C1 K57 to54. Only 5 of the 15 near surface samples provided
ults within the reservoir gas boundaries (Abrams, 2004).sedIn another example, methane isotopic ratios from surface
iment cores range from d13C1 K68 to K37 (Fig. 10).10.5 to 18.5% (Fig. 9; Abrams, 2004).volume), whereas the reservoired gas wetness ranged fromrelative to percent calcium carbonate (CaCO3) of sediment.
-
Migration pathway analysis is critical in understanding
from
M.A. Abrams / Marine and Petroleum Geology 22 (2005) 457477 471the near-surface seepage in terms of petroleum system
dynamics (Macgregor, 1993; Thrasher et al., 1996). Fluid
flow modeling, seismic attribute evaluation (mapping
vertical noise trails), and surface morphology analysis are
independent non-geochemical ways to interpret near-In reality all of the four processes play some role in the
measured near-surface sediment extracted gases. Which
process is important in your study area will depend on the
local petroleum seepage system.
5. Migration pathway analysis
Fig. 9. Comparison of normalized hydrocarbon gas compositions obtained
survey and MDT exploration tests.surface geochemical anomalies and how they relate to
subsurface hydrocarbon generation and entrapment. Pet-
roleum seepage along major migration pathways is well
documented and targets surface geochemical core locations
Fig. 10. Comparison of methane carbon isotopic ratios obtained from headspace
MDT exploration tests.(Abrams, 1992, 1996; Reilly et al., 1996; Abrams et al.,
2001a,b). Early surface geochemical surveys relied on the
vertical leakage concept and collected cores using grid
patterns (Matthews, 1996). Few studies have sought to
correlate seeps with specific migration pathways identified
from reflection seismic, seafloor bathymetry, and geochem-
ical measurements. Mapping thermogenic hydrocarbon
seeps (oil and gas) relative to potential cross-stratal
migration pathways is one way to establish effective
migration pathways to charge potential traps.
Fluids either flow predominantly along major stratal
surfaces or they cross stratal surfaces via faults, dipairs, or
major fracture systems. Fluids migrating along stratal
surfaces are well documented and relatively well under-
headspace extracted seabed cores collected during a surface geochemicalstood (Toth, 1980, 1996). In contrast, cross stratal migration
requires sufficient pore pressures to overcome capillary
entry pressure in lowered capillary pressures zones. Entry
pressure is a function of rock pore throat size and grain
extracted seabed cores collected during a surface geochemical survey and
-
the fluids may include gas (biogenic or thermal) and water,
roleumwettability. Factors reflecting pore throat size and wett-
ability include rock net-to-gross (sandshale ratio), variable
fault slip, stress regime, and pore fluid composition. The
increased pore pressures can be due to several factors such
as rapid deposition, petroleum generation, and local
hydrocarbon column heights. These factors may change
quickly as evidenced by the episodic nature of petroleum
leakage in near-surface sediments (Roberts and Carney,
1997; Quigley et al., 1999; MacDonald et al., 2000; Abrams
and Boettcher, 2000).
5.1. Fluid flow modeling
Multidimensional fluid flow, both along strata and cross
stratal, are simulated by modeling programs, e.g. PRA
BasinFlow, IES PetroFlow, and IFP Temis. Water and
hydrocarbon flows are modeled in two or three dimensions.
These modeling programs depend on capillary entry
pressure, pore fluid dynamics (pore pressure and type),
and regional hydrodynamics, which are largely unknown in
most exploration areas. Nevertheless, the programs provide
generalized understandings of major fluid flow directions.
Cole et al. (2001) use 2D fluid flow modeling, in
conjunction with seabed geochemical measurements, to
document a transported thermogenic sediment petroleum
signal in the deepwater Gulf of Mexico. They concluded
that the low concentration thermogenic samples are likely
the redistributed oil-bearing sediments from shelf-slope
failures. The models strongly suggest that a group of cores
with low concentration thermogenic hydrocarbons, ident-
ified as low confidence samples, are unrelated to the
subsurface petroleum charges. Reservoir oils collected after
the geochemical surveys confirm the low confidence
samples are sourced from a different organic facies, and
thus unrelated to local charge. Identification of transported
hydrocarbons (low confidence) by Cole et al. (2001)
provides an explanation for discrepancies between predicted
(pre-drill) and post-drilling source facies maps published by
Wenger et al. (1994). These maps are based on both high
and low level seepage, thus mixing the transported (low
confidence) and in situ hydrocarbon (high confidence)
signals.
5.2. Seismic attribute analysis
Single-trace attributes such as amplitude and frequency
can be used to document acoustic anomalies believed to be
related to migrating or shallow-generated gas. Gas clouds,
gas chimneys, bright spots, pull downs, wipe outs, gas
disturbed zones, and blank-out zones are well described in
the literature (Sweet, 1973; Anderson and Hampton, 1980;
Siddiquie et al., 1981; Edrington and Calloway, 1984;
Abrams, 1992). Many geophysicists consider these features
as seismic noise that degrades the quality of seismic
reflections. They devote great efforts to this problem and
M.A. Abrams / Marine and Pet472filter out gas signals.as well as oil. Fluid expulsion features result from fluid
releases due to geopressure (pore pressure in excess of
hydrostatic) along a major cross-stratal migration feature
(faults, fractures, and diapers). Thus, near-surface fluid
expulsion features by themselves do not confirm a mature
source is present. Sediment samples must be collected and
analyzed to confirm that these potential migration pathways
are or have been associated with hydrocarbon generationIn 3D seismic cubes and sophisticated attribute analysis,
these noise features assist surface geochemists in mapping
migration pathways to near-surface (Loseth et al., 2002;
Heggland, 1998). A semiautomatic method that highlights
vertical noise trails in seismic data uses assemblies of multi-
trace seismic attributes and neural networking. A chimney
cube is a 3D volume of seismic data that highlights vertical
chaotic seismic feature (Aminzadeh et al., 2002).
5.3. Surface morphology reflects of hydrocarbon migration
Leaking hydrocarbons, and accumulated fluid flow
affects shallow sediments and sea floor character. Seabed
morphology depends on several factors: rates and volume
of leakage, type of migrating fluid (water, oil, and/or gas),
sediment environment, time frame (long vs short term),
and oceanographic conditions (salinity, temperature, and
bottom water currents) (Hovland and Judd, 1988).
Morphology features may be positive relief (constructive)
or negative (destructive). Constructional features can result
from slow accumulation of fluidized mud, hydrates
(depends on pressure and temperature regime), and/or
carbonate hardground (authigenic carbonate from bacterial
activity), whereas depressions are produced from the
release of geopressured fluids or the collapse of fluidized
sediments. These seabed features range from very small
(less than a meter), up to 1 km wide and 50 m high, and
therefore are often recognized on seismic and sonar data
(Hovland and Judd, 1988; Roberts et al., 1990; Kaluza and
Doyle, 1996).
The seafloor at fluid-expulsion sites generally have an
acoustic character significantly different than that of
adjacent areas, displaying localized amplitude anomalies.
Dip maps on the seafloor and artificially illuminated time-
structure maps with amplitude overlays from 3D seismic are
effective for locating bathymetric variation, which may be
related to leakage. In the absence of near-surface 3D data,
high resolution sub-bottom profiling (CHIRP), side-scan
sonar, 2D seismic profiles (sparker, air-gun, etc.), and swath
(multi-beam) bathymetry-backscatter maps also may locate
fluid expulsion features, possibly related to migration
pathways.
The seabed morphology features described above
provide evidence of near-surface fluid expulsions where
Geology 22 (2005) 457477and migration.
-
recent tectonic activity are less leaky and have lower total
sediment gas and C12 plus solvent extract concentrations
Fig. 12. Gas vs oil evaluation using seepage magnitude in basins with
roleum Geology 22 (2005) 457477 4736. Hydrocarbon charge vs surface signal
6.1. Presence mature source rock
Localized seepage indicates a generating source is
present. Source rock character can be examined if sufficient
seep material is available for detailed molecular character-
ization (GC and GC/MS). Source type (organic matter type),
source age (if age diagnostic biomarkers are present), and
organic maturity (hydrocarbon generation temperature) may
be interpreted, keeping in mind that migrating hydrocarbons
in near-surface sediments do not guarantee a nearby
structure will be charged with an economic accumulation
(Abrams, 2002a). Bolchert et al. (2000) found that many of
the major seeps in the northern Gulf of Mexico are in areas
with no fields or discoveries, and that many of the fields do
not have a near-by surface seep. Thus, the significance of
seepage at or near-by a potential prospect is not straight
forward. Thermogenic seepage in near-surface sediments at
or near a prospect confirms the existence of a mature source
rock. Tying a seep to a specific trap should include
migration pathways analysis, using both seismic data and
fluid flow modeling. Nor does the lack of hydrocarbon
seepage condemn a basin or prospect area. Not all petroleum
bearing basins have detectable seepage.
6.2. Hydrocarbon charge and charge type
Another key goal of surface geochemistry is to predict
the likely petroleum phase and composition. Predicting oil,
condensate, and gas using near-surface geochemistry has
been discussed for years (Horvitz, 1981, 1985). Jones and
Drozd (1985) collected gas samples from shallow holes
using an inflatable packer and pump system. They compared
the soil gas composition to reservoir charge type, and
developed empirically determined ranges for sediment gas
hydrocarbon measurements over different reservoirs. This
was a first and important step in demonstrating that the near-
surface signal may be related to the reservoir composition.
The gas composition data was plotted on Pixler plots
(Pixler, 1969), using empirically derived ratios to define
probable phase. These empirically derived guidelines may
work for the type of sampling used by Jones and Drozd
(1985), but should not be directly applied to other near-
surface gas collection methods.
A comparison of anomalous sediment gases with
reservoir gases led to similar conclusions. Headspace
hydrocarbon gas compositions from shallow sediment
samples collected at major migration pathways above
several Gulf of Mexico offshore fields show systematic
changes with reservoir charge (Fig. 11). Samples with gas
compositions similar to Line A trend usually contain oil and
gas. Samples with gas compositions similar to Line B trend
usually are dry. Note the distinction between dry hole
(Trend B) and oilgas reservoir (Trend A) is based on very
M.A. Abrams / Marine and Petsmall gas compositions changes, less than 0.1%. Thus, usingheadspace extracted sediment gas data to define reservoir
charge must be used with great caution.
The charge phase (gas vs oil) may also be evaluated
using seepage magnitude. Gas vs oil may be a function of
source and/or retention (differential entrapment) in selected
geological settings. The gas vs oil field distribution in the
South Caspian Basin could be a function of differential trap
retention more than charge (van Grass et al., 2000; Abrams
et al., 2001a,b). Traps with similar oil and gas charges, and
very recent tectonic activity, tend to retain oil over gas by
differential entrapment resulting in a more oily accumu-
lation. In contrast, other traps with similar oil and gas
charges, but no recent tectonic activity, tend to retain both
the oil and gas resulting in a more gassy accumulation. The
resulting surface signatures differ in the two scenarios. The
accumulations with recent tectonic activity are more leaky
and have prolific seepage signatures, very high total
sediment gas and C12 plus solvent extract hydrocarbon
concentrations (Fig. 12). Accumulations with little or no
Fig. 11. Hydrocarbon charge evaluation using headspace sediment gas
composition.differential entrapment controlling gas-condensate to oil trap distribution.
-
If near-vertical leakage is well documented from
ga
sel
dio
6.4. Oil quality prediction
roleuminvolve temperature history analyses because basins with
large concentrations of reservoired carbon dioxide and
nitrogen are often associated with elevated temperature
gradients (Giggenbach, 1997). This method should not be
used for prospect specific predictions because other factors,
such as migration and entrapment may also be important.
A more empirical method for non-hydrocarbon gas pre-omdicxide and nitrogen, greatly affect the production econ-
ics. Nitrogen and carbon dioxide gas predictions usuallycoected geologic settings, such as southeast Asia. Large
ncentrations of non-hydrocarbon gases, such as carbonobs concentrations in areas where petroleum is the main
jective. Non-hydrocarbon gases are equally important in(California) and Vassar Waterflood (Oklahoma) were
undertaken to help evaluate drainage patterns, infill
locations, step-out potential, and hydrocarbon potential in
abandoned fields (Schumacher et al., 1997). Comparison of
microbiological surface anomalies appear to match pro-
duction and drill well activity results according to
Schumacher et al. (1997). Again, caution should be used
when utilizing surface geochemistry methods for evaluating
by-passed oil due to possibilities of:
Insufficient direct communication with surface (novertical migration);
Variation among sampling methods and sedimentconditions;
Possible surface contamination in a producing region.
6.3. Non-hydrocarbon gas
Most surface geochemical surveys measure hydrocarbon(hy
abt in production (by passed) from drained compartments
drocarbon already produced). Microbiological surveys
ove active and abandoned fields in the Sacramento Basineit
nocro-seepage over a field may reflect reservoir heterogen-
y, and distinguish hydrocarbon charged compartmentspre
mivious surface geochemical surveys, the pattern of(Fig. 12). The presence of a seismic gas chimney above or
near the trap may provide physical evidence of differential
gas loss (Phipps and Carson, 1982).
Factors to remember when predicting reservoir charge
using near-surface gas composition and/or seepage magni-
tude include:
Relatively direct and active migration pathway from thereservoir to near-surface sediments;
Limitations of method of sediment hydrocarbon gas extra-ction (headspace, blender, ball mill, or adsorbed/sorbed);
Limitations of method of sediment hydrocarbon oil extra-ction (extraction method, solvent, or sieved vs bulk);
Variability (noise to signal ratio, precision, and accuracy)of seep detection method being utilized.
M.A. Abrams / Marine and Pet474tion is near-surface geochemistry. When concentrationsPrediction of oil properties using surface geochemistry
uses several methods. Horvitz (1985) noted the fluorescence
spectra shape varied with oil type. The general shape is
defined by the R1 ratio: intensity of the emission band at
360 nm divided by that of the 320 nm band using a 270 nm
excitation in both cases. Barwise and Hay (1996) derived an
empirical relationship between the fluorescence R1 and fluid
API gravity using 130 oils. Barwise concluded R1 could be
used to predict oil gravity. However, thermal maturity,
biodegradation, and recent organic matter input will also
affect the fluid gravity prediction relationship.
Molecular characteristics (as determined by high resol-
ution gas chromatography and gas chromatographymass
spectrometry) can be directly or indirectly related to API
gravity in both oils and surface seeps. Kennicutt and Brooks
(1988) chose two molecular parameters to evaluate API
gravitypristane/phytane and bisnorhopane/hopanein
southern California oils. API gravities predicted using
pristane/phytane and bisnorhopane/hopane ratios were in
good agreement with those measured in oils from near-by
reservoired fluids. These molecular ratios should be used
cautiously because they depend on the same oil being
present throughout an area, and these ratios are affected to
varying degrees by a number of oil alteration processes,
including biodegradation, water washing, and thermal
degradation, as well as recent organic matter interference.
It is important to choose molecular parameters which
strongly correlate to API gravity and are not easily altered
by any of these processes or factors.
7. Summary
Near-surface indications of migrating hydrocarbons
provide critical information on source (organic matter
type), maturation (organic maturity), migration (migration
pathway delineation), and in selected geologic settings,
prospect specific hydrocarbon charge (phase, composition,
and quality).
Petroleum seepage system evaluation integrates near-
surface geochemical analyses for basin assessment and
prospect evaluation. The PSS has four elements: seepageof thermally derived non-hydrocarbon gases are elevated in
near-surface sediments, there is a high risk of non-
hydrocarbon gases in near-by reservoirs. Headspace sedi-
ment gases from a recent site-specific seabed sampling
survey above a field contain 7080% CO2. The resevoired
gas is 6070% CO2. Stable carbon isotopic ratios from
sediment extracted gases with elevated CO2 gases confirms
most of the anomalous seabed carbon dioxide gas is thermal,
not bacterial, with values similar to the reservoir gases
(Abrams, 1996).
Geology 22 (2005) 457477activity (qualitative evaluation of leakage rates: active vs
-
Abrams, M.A., 1989. Interpretation of surface methane carbon isotopes
extracted from surficial marine sediments for detection of subsurface
Annual AAPG Convention, Dallas, TX, April 1821, 2004.
roleum Geology 22 (2005) 457477 475passive, and episodic vs continuous), seepage type (concen-
tration of migrating thermogenic hydrocarbons relative to in
situ materials, macro- vs micro-seepage); migration focus
(direction of leakage relative to subsurface hydrocarbon
generation and/or entrapment); and near-surface seep
disturbances (near-surface processes which alter or block
the seepage signals). The rate and volume of hydrocarbon
seepage to the surface affects near-surface geological and
biological responses, and thus is the optimal type of sampling
procedures for detecting hydrocarbon leakage.
Best practices for the interpretation of near-surface
geochemical measurements should include:
Recognition of background vs anomalies in surface
geochemical surveys. Identify presence of multiple popu-
lations (background vs anomalous) using statistical pro-
cedures and graphs, i.e. histogram and cumulative
frequency plots.
Use of multiple parameters and integrated interpretation.
Natural gases are generally analyzed in three ways: gas
composition (C1C5 and non-hydrocarbon component such
as CO2); compound specific carbon isotopic ratios (d13Cn);
and hydrogen isotopic ratios (dDCH4). Gas composition andisotopic ratio depend on type and maturity of sources and on
the degree of secondary alteration. Basic screening of high
molecular weight (HMW) hydrocarbons includes whole
extract gas chromatography (GC) and total scanning
fluorescence (TSF), followed by gas chromatography/mass
spectrometry (GC/MS, biomarkers) for samples with anom-
alous HMW hydrocarbons. Interpretation of biomarker data
from surface sediment seepages differs from oiloil and oil-
source correlation studies because of recent organic matter
and bacterial alteration which will change the molecular
character. It is important to utilize biomarker ratios, which
are less susceptible to interferences rather than those
commonly used for reservoir analyses.
Recognition of pitfalls and problems with surface
geochemical data. It is important to recognize and avoid
pitfalls and problems caused by transported hydrocarbons
seepage (displaced seepage), reworked mature source rocks
(source rock contained within sediment provenance), and
potential field or laboratory contamination. Additional
problems include variation due to differing analytical
methods, changing sediment types, and migration or
sampling fractionation-partitioning effects.
Migration pathway analyses. Fluid flow modeling,
seismic attribute, and surface morphology analyses provide
independent non-geochemical ways to interpret near-
surface geochemical anomalies. Petroleum seepages along
major migration pathways can potentially be tied to specific
traps or sources.
All petroliferous basins exhibit near-surface signals, but
some geochemical signatures are not distinguishable from
background sediment signals with methods currently used by
industry. Relationships among near-surface hydrocarbon
seepages and subsurface petroleum generation and entrap-
M.A. Abrams / Marine and Petment are often complex. We need to recognize complexities,Abrams, M.A., Boettcher, S.B., 2000. Mapping migration pathway using
geophysical data, seabed core geochemistry, and submersible obser-
vations in the central Gulf of Mexico. In: American Association of
Petroleum Geologist Convention Abstracts, Annual AAPG Convention,
New Orleans, Louisiana, April 1619, 2000.
Abrams, M.A., Segall, M.P., Burtell, S.G., 2001. Best practices for detecting,
identifying, and characterizing near-surface migration of hydrocarbons
within marine sediments. In: Offshore Technology Conference, Hous-hydrocarbons. Association Petroleum Geochemical Exploration Bulle-
tin 5, 139166.
Abrams, M.A., 1992. Geophysical and geochemical evidence for subsur-
face hydrocarbon leakage in the Bering Sea, Alaska. Marine and
Petroleum Geology Bulletin 9, 208221.
Abrams, M.A., 1996. Distribution of subsurface hydrocarbon seepage in
near surface marine sediments. In: Schumacher, D., Abrams, M.A.
(Eds.), Hydrocarbon Migration and its Near Surface Effects. American
Association of Petroleum Geologist Memoir No. 66, pp. 114.
Abrams, M.A., 2002a. Significance of hydrocarbon seepage relative to sub-
surface petroleum generation and entrapment. In: American Associ-
ation of Petroleum Geologist Convention Abstracts, Annual AAPG
Convention, Houston, TX, March 1013, 2002.
Abrams, M.A., 2002b. Surface geochemical calibration research study: an
example of research partnership between academia and industry. In:
New Insights Into Petroleum Geoscience Research Through Collabor-
ation Between Industry and Academia, Geological Society, London,
UK, May 89, 2002.
Abrams, M.A., 2004. Significance of gas extracted from marine sediments
to evaluate subsurface hydrocarbon generation and charge. In:
American Association Petroleum Geology Convention Abstracts,make sense of observations, and reduce exploration risk by
better integration of near-surface geochemical measure-
ments. Surface geochemistry is a potentially powerful
exploration and production tool which can greatly assist
the petroleum systems analyst reduce charge risk if properly
used.
Acknowledgements
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