LIST OF FIGURES
Surface geochemical prospecting for hydrocarbons includes a myriad of
techniques ranging from the direct detection of hydrocarbons escaping
from subsurface accumulations and source beds to identifying secondary
responses in the soils, rocks and biota in proximity to such accumulations
or source beds. In the historical sense, the observation of visible seepage
of hydrocarbons is the oldest method of prospecting for petroleum. Drake's
historic well near Titusville, Pennsylvania, was drilled on the basis
of a seep in the adjacent creek bed. The relationship of such "macroseeps"
to reservoirs was well established by Link (1952), who stated: "A
look at the exploration history of the important oil areas of the world
proves conclusively that oil and gas seeps gave the first clues to most
oil-producing regions. Many great oil fields are the direct result of
seepage drilling". In this respect, few would argue that the presence
of a macroseep indicates the presence of petroleum migration or surface
source beds. Microseeps, or smaller scale macroseeps, also occur because
of the physical continuity necessarily imposed by nature. These are invisible
seeps, usually detectable only by sensitive instruments or by the visible
result of their effect on the near-surface environment. These microseeps,
although perhaps not as obvious or dramatic as macroseeps, are just as
valid for the exploration of undiscovered reserves. This chapter presents
the conceptual and practical application of microseepage detection and
interpretation in the evaluation of areas for their subsurface hydrocarbon
Five factors are necessary to form a hydrocarbon reservoir. These are:
(1) a source, (2) a reservoir in which the hydrocarbons can collect or
concentrate, (3) a means of trapping these fluids in this reservoir (a
seal), (4) a pathway to the reservoir (migration) and (5) the proper timing
such that the source, reservoir, seal and migration pathway are present
when required. Near-surface seepage of thermogenic hydrocarbons indicates
the subsurface presence of a mature source and migration pathway. It also
suggests that, if the hydrocarbons are reservoired, the seal is imperfect.
This is true of both macroseepage or microseepage. Patton and Manwaring
(1984) found that even in an area of extensive evaporites (Hugoton Field,
Kansas), the seal was not perfect, and that microseepage could be detected
in the vicinity of the Syracuse Fault.
Basically, surface geochemical prospecting is a source rock tool applied
at the surface. The magnitude of a microseep from a reservoir is related
to the permeability of the migration pathway (and not to the economic
worth of the reservoir). A surface geochemical survey is not currently,
and perhaps never will be, a stand-alone prospect tool. However, with
judicious use, this technology can provide information on the maturity
of source beds in a basin and the composition of subsurface hydrocarbons.
In addition, detection of surface microseepage allows mapping the surface
expression of the migration patterns created by the expulsion of fluids
as a basin compacts and matures. When used in conjunction with geophysical
and geological information, geochemical data can refine subsurface models
of hydrocarbon trapping and migration configurations. It is only through
careful analysis and integration with other exploration tools that one
can achieve the optimum benefits from this technology.
Near-surface hydrocarbon detection techniques have been shown in both
the former USSR and the United States to be capable of distinguishing
basins (or large portions of basins) that are unproductive from those
that are productive, and of distinguishing the type of production (oil,
gas, or mixed oil and gas). This ability has been independently recognized
by Jones and Drozd (1979), Mousseau and Williams (1979), Janezic (1979),
Weismann (1980), Drozd et al. (1981), Jones and Drozd (1983), Richers
(1984), McCrossan et al. (1971), Richers et al. (1982, 1986), Horvitz
(1985) and Klusman and Voorhees (1983). Surface geochemical techniques
can select which of several frontier basins has the greatest chance of
containing reservoired hydrocarbons, and the expected composition (gas,
oil, mixed), in addition to high-grading portions of these basins that
have the highest potential. The premise that microseeps occur and that
they provide useful information for exploration is no longer questionable.
The formation of petroleum and natural gas from organic matter through
increasing depth of burial and temperature has been very well established
by many geochemical studies (Tissot and Welte, 1978; Hunt, 1979). As shown
in Fig. 5-1, the generation
of the light hydrocarbon gases, methane (C1), ethane (C2), propane (C3)
and the butanes (C4), occurs in three main stages: diagenesis (<50°C),
catagenesis (50-200°C) and metamorphism (>200°C) in which only
dry gas and ultimately graphite are formed. During the first stage bacteria
acting under reducing conditions on organic substrates in sediments form
predominantly methane. According to Hunt (1979), about 82% of the methane
and practically all the heavier hydrocarbon gases are formed in the next,
catagenic stage. Ethane, propane and the butanes are formed in the temperature
range from 70°C to 150°C with peak generation occurring around
120°C. As shown in Fig. 5-1, a very large thermal methane peak occurs
In addition to time, the quantity of gaseous hydrocarbons formed varies
with the type of organic source material, which can be broadly classified
as sapropelic (marine) or humic (terrestrial). As shown in Fig. 5-1, considerably
more C2-C4 and other oil-type hydrocarbons are generated from sapropelic
sources than from humic sources. In addition to the different volumes
and types of petroleum (oil versus gas) produced from the two source materials,
their carbon isotope compositions are different; terrestrial organic matter
is reported to have lower 13C concentrations than marine organisms (Galimov,
1968; Silverman and Epstein., 1958).
The carbon isotope concentration of 13C, as compared to 12C, is also very
useful for classifying natural gases as to their source type and/or maturity.
Maturity is generally proportional to the depth of generation. Schematic
diagrams published by Schoell (1983a, 1983b) distinguish the major natural
gas types into three end members, as shown in Fig.
5-2. Schoell suggests that most natural gases are admixtures of these
three basic end members. As shown in Fig.
5-3, further classification of reservoir gas types can made from data
for deuterium in methane 13C in ethane.
The near-surface occurrence of ethane through butanes is of fundamental
importance to the purpose of this chapter and to the usefulness of these
gases as prospective indicators of buried natural gas and petroleum deposits.
An extensive review of the literature suggests that C2-C4 hydrocarbons
can be generated biogenically; however, solid proof exists only for methane
and ethylene as major products of bacteria (McKenna and Kallio, 1965).
A review of the literature shown in Table
5-I provides conflicting evidence for the biogenic occurrence of the
C2-C4 hydrocarbons, although most of the literature suggests an abiogenic,
thermocatalytic origin for these gases. Compositionally, however, these
gases display large variations and do not resemble compositions characteristic
of petroleum gases. All these studies are further characterized by methane:ethane
ratios in excess of 1000 and a percent methane composition >99%, and
are quite uncharacteristic of petrogenic gases. Some of the results reported
before the invention of the gas chromatograph must be regarded with suspicion
due to limitations of the analytical methods employed and possible sampling
collection at locations contaminated by mixed biogenic and petrogenic
gases. Russian researchers have illustrated that some of the earlier analytical
methods, such as the combustion technique of Kartsev, et al (1959), can
measure gases which are mistaken for hydrocarbons.
Studies were conducted at Gulf Research & Development Company by
Janezic (1979) to investigate the anaerobic microbial evolution of C1-C4
hydrocarbons upon decomposition of various organic substrates including
green plant branches, grass clippings, plant roots, decayed wood and pure
cellulose. These substrates were chosen to compare results with those
of Davis and Squires (1954), Bukova, (1959), Smith and Ellis (1963), Kim
and Douglas (1972) and Voytov et al. (1975), who used similar substrates.
The experimental scheme for anaerobic decomposition is shown in Fig.
5-4. Exactly 1.5 g of each substrate was added to a modified 1 liter
Sohngen flask and autoclaved at 120°C and 15 psi to ensure sterility,
after which each flask was filled to capacity with a sterile inorganic
nutrient medium and pH adjusted. Next 50 ml of a heterogeneous innoculum
prepared from muds from a local lake was injected into each flask as "inoculates",
while 50 ml. of sterile nutrient medium was used for control samples.
Headspace C1-C4 hydrocarbons were measured prior to incubation to provide
baseline concentrations. Minimum detection limits were 3 ppb on a volume
basis using a high sensitivity gas chromatograph equipped with a flame
ionization detector. Samples were incubated at 25°C and 36°C over
a five week period.
The results are summarized in Table
5-II and Fig. 5-5. Of
the organic substrates fermented, green plant branches, grass clippings
and plant roots evolved significant quantities of gas after a few days
of incubation. Of the C1-C4 hydrocarbons determined, only methane was
observed in copious quantities, with minor amounts of ethylene co-produced.
Ethane, propane and butanes were not evolved, in good agreement with the
work of Kim and Douglas (1972) and Voytov et al. (1975). Peak concentrations
of methane and ethylene exceeded 25,000 ppm by volume and 8 ppm by volume,
respectively. Ethane evolution would be masked on the chromatographic
trace by these quantities of methane, but ethane above background levels
was not observed after seven days of incubation. No measurable C2-C4 gases
were found in the remaining 30-day incubation period. This experiment
suggests that biogenically-generated gases do not initially contain any
Another approach was that taken by Coleman (1979), who studied both the
chemical and isotopic composition of glacial till gases in Illinois. Coleman
obtained the same result, finding that C2-C4 gases are not present in
the glacial till gases in Illinois. Coleman also determined 14C age dates
on the gases and showed that the biogenic methane varied from about 10,000
years to as much as 40,000 years in age. This is particularly significant
since it suggests that no bacterial generation of C2-C4 hydrocarbons occurs,
either initially in test tubes or even within the first 40,000 years in
Distinguishing petrogenic and biogenic hydrocarbons
The results of the studies by Janezic (1979) and Coleman (1979) strongly
suggest that C2-C4 hydrocarbons are not generated biogenically. Most of
the previous studies cited appear to be compromised because they were
conducted in natural environments in which migrated petrogenic gases might
have also been present.
Even assuming that small quantities of C2-C4 gases are generated in biological
environments, a methane:ethane ratio greater than 500 appears sufficient
to delineate anaerobic gas production from thermocatalytic gases, since
such ratios do not occur in petrogenic natural gas deposits. As shown
in the test tube experiments (Table 5-II and Fig. 5-5), this value is
achieved within two to three days for all substrates studied and exceeds
100,000 after seven days of incubation. Similar values are cited in the
literature (Frank et al., 1970; Swinnerton and Lamontagne, 1974; Bernard
et al., 1976; Sackett, 1977; Reitsema et al., 1978) as the biogenic threshold
in marine geochemical prospecting (Table
The first attempt to relate soil gas hydrocarbon concentrations to oil
and gas deposits was made in 1929 in Germany by Laubmeyer (1933). Surveying
a known oil deposit, he collected samples of soil gas from systematically
located boreholes, 1 meter to 2 meters deep, after sealing them from the
atmosphere for 24 to 48 hour periods. Using portable analytical equipment,
he demonstrated that the samples over the deposits were enriched in methane.
Soil gas investigations were initiated shortly after this time in the
then Soviet Union by Sokolov (1933), who verified Laubmeyer's results
(Kartsev et al., 1959), but measured both methane and heavier hydrocarbons.
Research in the area of surface prospecting was also carried on in the
United States during the 1930's beginning with Teplitz and Rogers (1935),
Rosaire (1938) and Horvitz (1939). These investigations entailed the collection
and analysis of the soils themselves for hydrocarbon gases. The use of
adsorbed gas on soils was regarded as an important improvement upon soil
gas, as short-term diurnal variations in soil gas flux could be avoided
by the assumption that soil would have a tendency to establish over time
a metastable equilibrium with the regional flux.
In the years following these early studies, the basic concepts have remained
largely the same, except that detection limits have been improved with
technological advances. Recent work has focused on compositional ratios
or signatures of the light hydrocarbon gases and their relationship to
known hydrocarbon products in the investigated area (Weismann 1980; Jones
and Drozd, 1983).
Emphasis has also been placed on the fundamental principles of surface
seepage, and the interpretation of the data. It is the opinion of the
authors that the overall acceptance of microseep technology in the West
has been hindered not only by the emphasis and success of seismic methods
but also because of the lack of a comprehensive and public surface geochemistry
database. There are, by comparison, more publications on geochemical survey
data and basic concepts in the Soviet and Russian literature. As a consequence,
many of our discussions rely on experience gained in the private sector
in the West, supplemented by literature published in the East.
Although the Soviet Russian literature is clearly positive about surface
microseep technology, the western literature is strongly divided. Dehnam
(1969) has reviewed several cases crediting geochemical prospecting with
petroleum discoveries. Overall success rates range from 25% to 75%. Duchscherer
(1980) reports a success rate of 25%, slightly over the industry average,
of which 58% are stratigraphic traps. Sealey (1974) reported a success
rate of 80% in Texas using a microbiological technique.
Geochemical methods of prospecting are classified as direct or indirect.
The direct methods involve detecting the presence of dispersed oil and
gas components in the form of hydrocarbon gases or bitumens in the soils,
waters or rocks in the vicinity of oil and gas accumulations. The indirect
methods involve detecting any chemical, physical, or microbiological changes
in the soils, waters, rocks, or vegetation associated with the oil and
gas deposits. Figure 5-6 is
a schematic diagram outlining most of the direct and indirect methods
currently in use (Kartsev et al., 1959).
Identifying secondary responses generated by leakage of hydrocarbons at
the surface has merit and has been reported by many investigators. These
include the use of (1) soil microbes (Soli, 1954, 1957; Kartsev et al.,
1959; Sealey, 1974); (2) reduction effects (Pirson et al., 1969; Donovan,
1974; Ferguson, 1975); (3) carbon and oxygen isotopes (Donovan et al.,
1974) and many other effects as reviewed by Matthews (1985).
As an exploration tool, the identification of hydrocarbon seeps is particularly
useful when coupled with remotely sensed images and photographs. Case
studies by researchers in the West have shown that secondary indicators
of microseepage are often present in the near-surface environment. Examples
noted by Horvitz (1972), Donovan (1974), Donovan and Dalziel (1977), Matthews
(1985) and Ferguson (1975) have indicated the presence of diagenetic alteration
of soils above or adjacent to hydrocarbon accumulations. Work by Rock
(1985), Matthews et al. (1984) and Patton and Manwaring (1984) has shown
that these effects may often be reflected in the health and type of vegetation
over the seep, which also alters the spectral response detected by satellite
and airborne sensors. These methods of geochemical prospecting for oil
and gas are reviewed in more detail in Chapter 7.
Others have noted changes in resistivity or radioactive signatures above
accumulations due to the seepage and possible interaction of ascending
fluids and solutions with the encapsulating medium. In some cases the
actual removal or addition of soluble chemical species has been noted.
It appears therefore that the direct detection of hydrocarbon gases is
not the only means of identifying areas of active microseepage, but that
a myriad of other possible secondary techniques can be used either as
adjuncts, or as solitary techniques in themselves, to infer the presence
of hydrocarbons in the subsurface environment. Most of these utilize the
detection and subsequent analysis of gaseous hydrocarbons, while other
methods employ the detection and analysis of liquid hydrocarbons, non-hydrocarbon
gases, the presence and relative concentration of bacteria, and even the
presence (or absence) of inorganic compounds and elements. For the most
part, however, methods that directly measure the hydrocarbon content of
soils or soil atmospheres have met with the most acceptance.
The fundamental assumption of near-surface hydrocarbon prospecting techniques
is that thermogenic hydrocarbons generated and trapped at depth leak in
varying quantities towards the surface of the Earth. That these hydrocarbons
present in the near-surface environment represent the products of generation
and migration from subsurface points of origin is a necessary conclusion
that is universally accepted with respect to hydrocarbon macroseepage.
Examples abound, such as the Santa Barbara Channel seeps, the La Brea
Tar pits of Los Angeles, the Athabasca Tar Sands, etc. The same relationship
has been equally well established, although less commonly accepted, for
A further assumption is that the pattern and intensity of this leakage
also provides information on preferential pathways that the leakage follows,
and as such can be combined with additional geologic information to predict
broad subsurface hydrocarbon fairways. In fact, in some instances it has
been claimed that such data can identify areas of reservoired hydrocarbons.
This last claim is often the subject of heated debate, however, commonly
depending in which camp (for or against geochemistry) the explorationist
The physical state of the hydrocarbons during transport is not well known.
The reader is referred to Matthews (1996) for a more complete discussion.
Nevertheless, most of the models proposed for the transport of these fluids
from source to reservoir (aqueous transport, micellular, discrete oil-phase
transport, gaseous transport, etc.) are applicable to the continued transport
of hydrocarbons from these source beds and/or reservoirs to the near-surface
environment. An additional constraint on land is that the last stage of
transport is generally above the water table. The physics of transport
can be subdivided into two categories, effusion and diffusion.
Effusion transport is believed to be the dominant mode of moving hydrocarbons
to the reservoir and to the near-surface environment. The sharp localized
nature of many anomalies associated with microseepage and macroseepage
is more consistent with an effusion model rather than a diffusion model.
The experience of the authors in monitoring leakage from gas storage reservoirs
and controlled experiments where subsurface gas pressures were typical
of true reservoirs suggests vertical transport rates of several meters
(tens of feet) per day, clearly greater than the distances of migration
dictated by the diffusion mechanism alone (Jones and Thune, 1982).
The sharp and often linear nature of anomalies suggests that faults and
fractures play an important part in the movement of these gases. Major
linear features discernible on satellite images, as well as other remotely
sensed media, from Patrick Draw, Wyoming, show such a relationship (Richers
et al., 1982). The Lost River, West Virginia, Geosat study (Matthews et
al., 1984) shows anomalously high soil gas values in relation to linear
features on imagery. There are anomalously high gas values along faults
in the San Joaquin Basin and in the Wyoming-Utah Overthrust Belt (Jones
and Drozd, 1983).
The Russians have shown that the magnitude of soil gas values on faults
increases dramatically shortly after an earthquake in which fault movement
is involved (Zorkin et al., 1977). An extensive study, involving 105 observation
wells, 3 meters to 5 meters deep, was set up over the Mulchto oilfield
in northeastern Salchalin. A total of 3,700 samples were collected and
analyzed over a four month period with the most active wells sampled daily.
The results from this study provide impressive evidence for the tectonic
relationship of this leakage gas flux (Fig.
5-7). This study leaves no doubt that faults and fractures provide
the main control on the effusion of gases from the subsurface.
Diffusion, on the other hand, is a slow and widely dispersive process.
Antonov et al. (1971) measured hydrocarbon diffusion coefficients for
a variety of rock types from several hydrocarbon provinces in the former
USSR. They discovered that the coefficients of diffusion vary over a wide
range (from 10-3 to 10-8 cm2/s) depending on the particular lithology
and geologic conditions.
The time required for diffusion to occur can sometimes be restrictive.
Table 5-IV shows that the
time required not only often exceeds the age of the hydrocarbon accumulation,
but also quite often exceeds the age of the host rock. If this were the
dominant process for migration, then the appearance of soil gas anomalies
in the near subsurface would indicate only very shallow accumulations.
If a non-steady state exists, where the hydrocarbon signal observed represents
only 0.001 times the steady state signal, then these times could be reduced
by a factor of 25 times that of the steady-state model. Table 5-IV shows
some of the times that this scenario would require. However, diffusion
can still be considered as a potential secondary process in microseepage.
Sokolov et al. (1965) calculated diffusion to be sufficient to have resulted
in the dissipation of oilfields formed in the Palaeozoic, although to
what extent, if any, this has occurred is not known. Furthermore, if any
such fields had leakage along faults and fractures or due to erosion of
the seal, diffusion might not be able to bring about accumulation before
much faster effusive loss caused depletion. Diffusion of benzene into
brines adjacent to accumulations has been demonstrated and used as an
exploration tool by Zarella et al. (1967).
In productive basins the process of diffusion from both source rocks and
reservoirs may be responsible for observed elevated background concentrations
which have no apparent relationship to the known accumulations. Alternately
the presence of free hydrocarbons effusing outward and upward in areas
of microfractures and dispersed by groundwater flow could similarly account
for this background. If diffusion were the responsible mechanism, then
one might expect broad anomalous zones, with localized effusive "spikes"
superimposed on the background. Starobinetz (1983) listed as typical examples
of diffusion the studies of Driepro-Douetsk and Anuddria grabens.
Aside from the potential of diffusion for producing a broad dispersive
background, it would also be expected to alter the composition of the
gases detected in surface methods. Starobinetz (1983) notes that not only
can diffusion affect composition, but two additional processes have a
similar effect. These are chromatographic separation and selective adsorption.
An example of such chromatographic separation is shown in Fig.
5-8 (Sokolov, 1971 b) which shows the results of a mixture of methane
and benzene injected into the bottom of a hand-bored 6-metre deep well.
Samples of subsoil air were taken periodically from observation wells
1 meter to 2 meters deep, resulting in the obvious separation shown in
Fig. 5-8. Indeed these processes have been cited by detractors of surface
prospecting as evidence that the technique is not a valid means of searching
for subsurface hydrocarbons deposits, arguing that pulses (non-steady
state) of gases will have a different composition from their source because
of the chromatographic separation. The example shown in Fig.
5-9, taken from an artificial underground coal gasification experiment
near Rawlins, Wyoming (Jones and Thune, 1982), shows that such effects
are only temporary. In this experiment, a pulse of gas travels from a
retort at a depth of 180 meters (600 feet) and migrates vertically and
laterally to a series of observation wells 5.5 meters (18 feet) deep.
As shown in Fig. 5-9, although the first gas to be seen in high concentrations
is methane, the compositional separation does not last more than a few
days before equilibrium is achieved when all the migrating gases have
ultimately reached the surface.
As to the second point, if selective adsorption is occurring, the volumes
of material escaping over geologic time should ultimately saturate (poison)
the adsorber such that no additional material can be adsorbed, or at best,
material is exchanged in a steady-state. The result will be a gradual
return of the signal to the original composition. This is clearly shown
in a study by Zorkin et al. (1977).
There is, however, one important area where diffusion may be responsible
for compositional changes; near the soil-air interface. Methane should,
due to its lightness and zero net dipole moment, be preferentially lost
(followed perhaps by ethane). This would possibly result in an oilier
gas signal at the surface. This could be countered by the production of
biogenic methane which might partially compensate for this loss.
The most important of the direct techniques shown in Fig. 5-6 involve
the measurement of light hydrocarbons, methane through butane. Because
of their volatility, these light hydrocarbons are generally found in the
free pore space. The seepage of hydrocarbons into the near-surface environment
above the water table must involves transport through both water-filled
and air-filled pores. Sampling these pore gases is obviously one of the
most fundamental concepts. However, gases can be bound in the sediment
matrix. This latter possibility leads to the development of some disaggregation
and desorption extraction techniques.
Discussion of sampling techniques must involve both "free" and
"bound" gases. To facilitate this discussion the collection,
measurement and analysis of light (C1-C4) hydrocarbons will be broken
into two main categories each with two subcategories: (1) free gas, which
can be vapor or dissolved gas; and (2) bound gas, which can be adsorbed
gas or chemi-adsorbed gas.
Gases in the free pore space can be found either in the vapor state or
dissolved in water. Extensive research at Gulf Research and Development
Company has demonstrated that the "free" and "dissolved"
gas seeps yield comparable compositional results, both to one another
and to their associated reservoirs when they are properly collected and
analyzed (Teplitz and Rodgers, 1935; Jones, 1979; Janezic, 1979; Mousseau
and Williams, 1979; Weismann, 1980; Drozd et al., 1981; Williams et al.,
1981; Jones and Drozd, 1983; Richers, 1984; Price and Heatherington, 1984;
Matthews et al., 1984; Jones et al., 1984). This documentation even extends
to numerous observations over artificial underground gas generation and
storage reservoirs (Jones and Thune, 1982; Jones, 1983; Pirkle and Drozd,
Sampling of vapor can be extended to any depth above the water table by
analyzing the exhaust air from an air-drilled well. Complications occur
because of dilution effects by the air injected for drilling and by the
additional fact that the drill bit disaggregates and liberates rock or
matrix gas in the process of drilling the hole.
Dissolved gases must be extracted from the aqueous system before analysis.
This is usually accomplished by a simple gas-water partition into a vapor
phase followed by standard headspace measurement techniques (McAuliffe,
1966). Alternatively a so-called "stripper" continuously partitions
the dissolved gases into a carrier gas which is then sent to a gas chromatograph
for analysis (Mousseau and Williams, 1979; Aldridge and Jones, 1987).
These separations are aided by the very low solubility of the light hydrocarbon
Standard mud gas logging is one variant of dissolved gas analysis conducted
on deeper drill holes. A gas trap is deployed in the return mud system
for extracting the dissolved and free gases. Compositional information
obtained from mud logging gas is useful for predicting the composition
of a potential reservoir (Pixler, 1969). These same ratios have been found
to be indicative of oil versus gas potential from surface seeps observed
from 12-feet deep soil gas measurements or from analysis of gases dissolved
in the shallow groundwater (Jones and Drozd, 1983).
Bound gas, which is adsorbed on both the organic and inorganic matter
contained in the sediment by means of physiochemical binding, introduces
new complexities into defining the appropriate sample for analysis. The
difficulty with defining this bound gas is forced by the reality that
rocks and/or sediments contain gases of multiple origins. By their very
nature, sediments contain both migratory (epigenetic) and indigenous (syngenetic)
gases. Migratory gases (biogenic and thermogenic) have migrated to the
surface from a deeper, more concentrated source.
Indigenous gas is related to biogenic, diagenetic and thermogenic generation
within the rock sampled at the surface and to recycled materials which
may contain some physically transported hydrocarbons tightly bound in
inclusions or other interstitial sites within the sediment matrix. The
nature of the bonding of the hydrocarbons to the grain surfaces leads
to two categories, adsorbed and chemi-adsorbed. These form an important
part of this discussion because of misnomers involved with the use of
the word "adsorbed".
True adsorbed gases are by definition bound to the surfaces of sediment
or rock particles. As defined by Greenland (1981) adsorption is the process
by which a chemical species passes from one bulk phase to the surface
of another, where it accumulates without penetrating the structure of
the second phase. Because the light hydrocarbons are so labile, they do
not strongly adhere to surfaces and are easily desorbed if the source
of these gases is removed. The gas must be replenished by continuous migration
in order to maintain the presence of adsorbed gases on the available surfaces.
Bound within the rock matrix, or within certain minerals (calcite, oxide
coatings, etc.) gases are chemi-absorbed. They can be removed only by
a chemical attack which completely dissolves the rock or sediment matrix.
Sometimes these more tightly bound gases not only include indigenous gases,
but also might integrate the signal over time, mixing the products of
"dead" or "non-active" seepage with those gases actively
migrating today. The non-active seeps are often coupled to the lithologies
of transported, non-residual sediments (Richers et al., 1986). These last
considerations provide two of the main reasons why "free" and
"chemi-adsorbed" gases are often found to have no obvious spatial
Any prospector would generally agree that it is desirable to measure only
the gas which has migrated from depth, since this is clearly the gas signal
which is related to buried reservoirs. The difficulty in doing this begins
with choosing the method of sample collection, because there are few sample
collection techniques which do not mix the syngenetic and epigenetic gases.
Both "free" and "adsorbed" hydrocarbons can often
be related to a migratory source, and thus can yield useful exploration
information. The free gases appear to be dominated by the migratory gases,
unless samples are taken within an outcropping source rock. In addition,
the free gases also contain any biological gases which, because of their
recent generation, also occur in the free state. If source rocks or recycled
source rock materials are present near surface, then the "adsorbed"
gases can obtain a major contribution from these sources. Exclusions are
often provided by sampling in areas where calcite concretions have been
deposited from carbon dioxide generated by biological oxidation of seepage
hydrocarbons. This is one reason why adsorbed gas has been successful
in marine offshore environments. A good example is provided by studies
of the Green Canyon macroseeps (Anderson et al., 1983; Pirkle, 1985).
If one can assure that only migratory gas is measured, then the type of
gas measured is unimportant. Including indigenous (syngenetic) gas results
in misleading measurements. This is believed by the authors to be one
of the primary causes of failure in the application of surface geochemical
prospecting. Failure to collect a properly distributed data set can be
equally misleading and result in an incorrect interpretation, since interpretations
will always be the educated guesses of an explorationist.
Any measurement on a real-world sample is always a combination of the
free and bound gas sample types. This is because the process of taking
the gas sample generally requires that the sediment or rock system is
disturbed by some mechanical means which creates the mixing of these sample
types. Because of this unavoidable interaction, we have recognized the
need to consider an intermediate sample collection technique which measures
the more loosely bound gases liberated into a container containing the
Typical "headspace" sampling is potentially flawed because of
the obvious losses encountered in transferring a core to a sample container.
This is further compounded by the difficulty in achieving a rapid and
total equilibration of the core gases into the headspace. An alternative
technique for measuring the loosely sorbed gas has been proposed by Hunt
and Whelan (1979), in which the headspace equilibrium is obtained mainly
by mechanical disaggregation and heat. In our opinion, this disaggregated
gas should more properly be called "adsorbed" gas. The truly
"free" gas is always lost (or at least greatly diminished in
volume) from any sample of core which is brought to the surface for collection
and handled before being put into a sample container (Sokolov, 1971 b).
Typical losses are shown in Table
This mechanical disaggregation gas has been usefully applied as a bridge
to relating the free and bound gas (Richers et al., 1986). Simple mechanical
disaggregation always liberates a considerable volume of gas, which if
handled properly has a predictably oilier composition than the associated
free gas. This change in composition, created by fractionation of the
lighter components, is demonstrated in later examples under case studies.
The hydrocarbon flux near to the surface varies according to the supply
of hydrocarbons and whether local chemical and biological conditions favor
their preservation or breakdown. In addition, hydrocarbon magnitudes at
any given location vary with time because of displacement by wind, rain
and barometric pumping (Wyatt et al., 1995).
In a very extensive review, Price (1985) suggested that surface bacterial
activity can totally obliterate the gases in a microseep. That this is
not typically the case has been demonstrated by extensive research over
both macroseeps and microseeps (Jones, 1984). However, bacterial activity
does probably contribute to the noisy appearance of soil gas seepage.
An example of gas flux related to barometric pumping has been demonstrated
over an underground propane storage reservoir. This mined cavern is about
60 meters (200 feet) deep. In order to observe the gas flux related to
atmospheric phenomena, plastic ground sheets about 1.5 x 1.5 meters (5
x 5 feet) were buried along their edges to contain any gas flux. The variation
with rainfall is shown as vertical bars in Fig.
5-10. A very large seepage anomaly is shown by the dashed line at
the right edge of the first bar. The rain probably displaced the gas in
the ground and caused it to come up underneath the ground sheet. However,
the same effect is not repeated every time it rains. Around the 19th,
20th, 21st and 22nd days of the month very small barometric changes were
observed. Nevertheless, small barometric lows have clearly-expressed gas
flux increases. Thus falls in barometric pressure lead to a gas flux that
escapes into the atmosphere. This escape occurs despite the extensive
microbiological activity that has developed over this cavern.
As shown in Fig. 5-11, a propane
profile collected over the top of the cavern requires a log scale to illustrate
the enormous range in gas leakage flux. An interesting secondary observation
taken from this example is the obvious color changes noted on the soil
cores. These chemical changes are related to hydrocarbon seepage and might
be used as an additional exploration tool to provide evidence of where
the gas leakage has occurred around any type of storage cavern. The soil
changes from red-brown to green-black directly over the top of the cavern,
where the largest seepage anomalies occur.
Thus the main difficulty with atmospheric sampling is created by meteorological
changes which can greatly displace and dilute the seepage emissions. Although
it occurs on a different order, it has become clear that the stress fields
in the earth can also influence this gas flux.
The fact that earthquakes may sometimes be preceded by geochemical anomalies
was discovered at about the same time in Japan (Okabe, 1956) and the then
USSR (Fursov et al., 1968). Earthquake prediction studies in Russia, Japan,
and China include extensive geochemical measurements. Chinese geochemical
data are reported to have contributed, at least partly, to the successful
prediction of several strong earthquakes (Press, 1975). In contrast, the
Earthquake Hazards Reduction Program in the United States emphasizes mainly
Limited programs using radon for earthquake prediction began in the United
States about 1975, at about the same time as Gulf Research and Development
Company first made measurements on light hydrocarbons, helium and hydrogen
on the San Andreas Fault in the Cholame Valley in California (Jones and
Drozd, 1983). This study confirmed that helium is a deep basement or tectonic
indicator which is commonly independent of oil and gas deposits. This
is clearly illustrated in Fig.
5-12, in which helium anomalies appear to be associated with the San
Andreas fault and with two other deep basement faults. The proposed deep
fault on the west flank of the Lost Hills oilfield also acts as a common
migration pathway for hydrocarbon gases (Fig.
5-13). This initial study, and the joint research program subsequently
initiated by Gulf Research with the Cal-Tech earthquake radon program,
was designed to obtain data concerning the rates of change of gas flux
associated with tectonic stress in the Earth.
Numerous other examples of gas flux related to earthquakes have been reported,
for example, by Kartsev et al. (1959), Fursov et al. (1968), Elinson et
al. (1971), Sokolov (1971 b), Eremeev et al., (1972 Orchinnikov (1972),
Zorkin (1977b), Melvin et al. (1978, 1983), Wakita et al. (1978, 1980),
Barsukov et al. (1979), Borodzich (1979), Mamyrin (1979), King (1980b),
Reimer (1980), Shapiro et al. (1981, 1982),) Mooney (1982) and Pirkle
and Jones (1983). Particularly intriguing examples have been published
by Antropov (1981) of atmospheric methane flux related to petroleum deposits
(Fig.5-14) and seismic shock
(Figs. 5-15 and 5-16).
These measurements were made with adsorption-type gas lasers: one type
makes point measurements of the sample in an adsorption tube (Iskatel-2);
the other (Luch) measures the specific gas adsorption a long path length
There are a variety of sample collection and hydrocarbon analysis methods
used in geochemical surveys for oil and gas deposits. In the case of free
gas, samples are collected either in atmosphere or, more usually, within
the soil. For the bound case soil or rock is collected and the gas is
liberated by one of several methods. In practice, however, it is rarely
possible to determine solely free gas or solely bound gas.
The detection of hydrocarbons above the ground surface offer obvious advantages:
continuous sampling, no permit requirements, access over rough and hostile
environments, large areas covered rapidly. A drawback is that diffusive
and convecting mixing in the atmosphere decreases the signal strength
with distance from the sediment or soil surface. Nevertheless, the capability
of detecting gases in the atmosphere has seen significant developments
over the past 10-15 years. Research has resulted in the development of
approaches based on microwave energy, infrared lasers and adsorbed hydrocarbons
on aerosols carried into the atmosphere by thermals.
The microwave approach has been developed by Owen (1972), Gournay et al.
(1979) and Thompson (1981). Although Thompson (1981) has stated that "conclusive
proof does not exist that the gases being detected by the sensor are low
molecular weight hydrocarbons and nothing else", he has published
numerous positive case studies relating the response of one of these instruments
to soil gas probe anomalies (Burson and Thompson 1985). Additional technical
difficulties result from the fact that microwave adsorption energy levels
represent rotational energy in the molecule. Deactivation of rotational
energy by collisions can occur rapidly at atmospheric pressure, causing
the molecule excited by the microwave energy to lose its adsorbed energy
in a non-emission mode, thus reducing the signal-to-noise ratio. This
coupled with the low concentrations of hydrocarbons in the atmosphere
has meant that the technique has not been extensively tested as an exploration
Remote monitoring of the gas composition of the atmosphere with laser
sources has been actively pursued for over a decade, with systems actually
built and used for nitrogen dioxide, sulphur dioxide, ozone, carbon dioxide,
ethylene, ammonia, hydrazine, hydrogen fluoride and methane. A small mobile
laser system capable of measuring methane and ethane in the atmosphere
has been developed (at Stanford Research Institute for the Gas Research
Institute) for detection of natural gas pipeline leaks (Van de Laan et
al., 1985). Another laser technique, based on established physical principles,
is LIDAR, which stands for light detection and ranging. The technique
uses light from a tuneable infrared CO2 laser to selectively detect methane
and heavier gases by adsorption. The technology was reviewed by Grant
and Menzies (1983). Briefly, laser light is pulsed into the atmosphere
and aerosols, liquid droplets and gaseous molecules scatter or adsorb
the light in different ways. Some portion of the scattered light returns
to its point of origin, where a telescope-like receiver channels it to
a photodetector, which produces an electrical signal proportional to the
optical radiation received by the telescope. The length of time between
transmission and reception indicates from what distance the light was
scattered and the intensity of the electrical signal indicates the concentration
of the particles or molecules being monitored. The development of an airborne
or truck-mounted system capable of range resolving the location and concentrations
of an atmospheric gas cloud will provide an extremely efficient and cost-effective
exploration tool for detecting both macroseeps and microseeps in frontier
The third atmospheric technique analyzes the residual liquid and/or condensate
hydrocarbon traces on aerosols carried into the atmosphere by thermals
(Barringer, 1981). The aerosols are created by gas bubbles which exsolve
into the atmosphere from the sea in areas where microseeps create gas
bubbles which reach the sea surface. The aerosols are concentrated from
large volumes of air and collected by an airborne cyclone sampler carried
aboard an aircraft which is flown at 30 meters (100 feet) above the sea
surface. Hydrocarbons adsorbed on the aerosols are measured by an Flame
Ionization detector which yields a total hydrocarbon signal. This system
is claimed to produce direct vertical anomalies over reservoirs at depth.
This technology appears reasonable for detection of seepage which is large
enough to produce free gas bubbles, but for feeble seepage (i.e., below
water solubility levels) the effectiveness would seem to be reduced by
dispersion due to underwater currents.
The hydrocarbon gases migrating through soil pore spaces are not dissipated
and diluted to the same extent as those in the atmosphere. There are,
however, problems posed by the very low levels of hydrocarbon gases and
by the diurnal "breathing" of many near-surface soils. In order
to overcome these problems, soil gas techniques which integrate the hydrocarbon
signal were introduced by Pirson (1946), Horvitz (1950), Kartsev et al.
(1959), Karim (1964), Heemstra et al. (1979), Hickey (1983), Hickey et
al. (1983) and Klusman and Voorhees (1983).
Karim (1964) published data on laboratory adsorption studies for light
hydrocarbons using activated charcoal, molecular sieve (diatomaceous earth)
and silica gel. As shown in Table
5-VI, these procedures greatly increase the concentrations available
for analysis, but selective adsorption severely affects the relative compositions
of the individual gases. The lightest gases are obviously not as effectively
trapped by adsorption techniques as are the heavier, less volatile components.
This is particularly true for methane and ethane. The adsorption capacity
of the substrates are also strongly reduced by moisture content, which
may vary from site to site, particularly since the sampling is conducted
in the ground where moisture content varies more rapidly than in the atmosphere.
Klusman and Vorrhees (1983) introduced a variation of this technique which
uses sample collection on charcoal wire over extended collection times,
followed by analysis using a quadrupole mass spectrometer. The advantages
cited are lower field expenses, increased field mobility, improved signal-to-noise
ration and negation of barometric and other meteorological factors. Major
drawbacks are that the most mobile light gas are not collected by the
charcoal wire, so that the samples comprise mainly the intermediate to
heavier molecular weight components, which include butane through gasoline
and diesel. Multivariate statistical techniques are required to interpret
the large number of mass peaks recorded, which includes both parent and
multiple daughters. In some cases qualitative information based on fragment
patterns of the adsorbed compounds is possible (Fig.
5-17). However, different molecular species and their fragment patterns
overlap; for example, propane and carbon dioxide have identical masses
(44) and thus cannot be separated. The exploration value of these data
lies in the demonstrated presence of reservoir-type hydrocarbons at the
surface and the composition noted in the lighter to heavier fragment patterns.
The difficulty in interpreting this particular type of data is further
compounded by its application in the upper soil zone where the most active
plant and microbiological activity takes place. Many organic and inorganic
compounds(humic acids CO2, N2O, NO2, etc.) are produced in this zone,
all of which are rapidly adsorbed by activated charcoal. These compounds
are present in macro concentrations (parts per thousand to percent) and
produce fragment patterns which overlap the much lower concentrations
of hydrocarbons, which are generally in the ppm range.
Another consideration in using adsorbers is the residence time required
for the collector in the soil medium. Care must be taken to ensure that
the entire survey area is sampled for the same time interval. Also, each
region has its own unique flux rate which will affect the results. In
a region with a low flux, the collectors should be left buried in the
soil for a longer period of time than collectors in a region of higher
flux. An orientation survey should always be designed to establish the
proper length of time required to obtain valid data prior to conducting
a large scale survey.
Although the concept and approach of this technique are excellent, it
does not integrate the flux of hydrocarbons heavier than butanes during
the one to two weeks for which the collectors are left in the soil. Hydrocarbons
heavier than butanes are liquids, and do not migrate more than a few centimeters
during the short collection period. It may be equally effective to place
a soil sample in a jar with the collection wire; the collection efficiency
could probably even be increased by heating the sample jar.
Direct sampling of free soil gas requires that a sampling probe be inserted
into the ground to collect a soil gas sample. The deeper the penetration,
the more difficult and expensive the procedure becomes, eventually requiring
that analysis be conducted on drilling fluids or rock samples recovered
from a hole. Deeper holes almost always encounter water, which also influences
the collection of free gases, forcing one to analyze the gas content of
some type of recycled water or mud system which is used to drill the hole.
Although sampling from holes of any depth is possible, for simplicity
two free soil gas techniques will be discussed and compared (as case studies):
shallow probes (Matthews et al., 1984) which penetrate to 1.2 meters (4
feet); and auger holes (Jones and Drozd, 1983) which are 3.5 meters (12
feet) deep. These methods differ mainly in terms of resulting soil gas
sample. The shallow-probe samples are influenced more by closer proximity
to the atmosphere and the soil/air interface, where the boundary conditions
Numerous sample collection methods have been devised for extracting near-surface
soil gas samples. Any suitable mechanical device having a small internal
volume can be used to collect the sample. Because the probe sampling port
must be forced into the soil, some soil grains are shattered by the necessary
mechanical force; many laboratory studies have shown that gas is almost
always liberated by this process (Collins, 1983). If the probe volume
is very small relative to the dimensions of the sample hole, then the
magnitude of the collected sample will be dominated by the gas liberated
by crushing. In such cases the volume of available gas will rapidly deplete
as the soil gas is aspirated from the hole. This effect can be reduced
by collecting a larger volume of soil gas, thereby incorporating a large
portion of the natural free soil gas into the sample measured, as compared
to that gas liberated by forcing the probe into the ground.
One method of collecting gases with a shallow probe system that has proven
to be simple and relatively reliable was developed by Burtell (1988).
This probe system consists of separate devices for sampling and for creating
the probe hole. The device used to make the hole is a pounder bar 1.2
meter (4-feet) long and 1.3 centimeter (1/2 inch) in diameter, with a
sliding hammer which is used to pound the bar into and out of the ground.
The soil gas probe consists of a short hollow tube, tightly enclosed by
a concentric sealing tube of the same diameter as the pounder bar, which
is inserted into the ground through the hole made by the pounder. A hand
pump or syringe is used to evacuate the residual atmospheric gases from
the hollow probe before the soil gas sample is collected. The soil gas
sample is collected in a 125 ml glass serum bottle with an aluminum crimp
top securing a butyl rubber stopper. The sample bottle is evacuated just
before the sample is collected in order to reduce the possibility of contamination
and to eliminate atmospheric dilution effects. A sample of the soil gas
is drawn into the evacuated bottle. Additional soil gas is then pumped
under pressure into the sample container.
Probe sampling using this or any similar portable design can be used in
a variety of geologic terrains within the limits of surface geologic features.
Since an effective soil gas survey measures gas concentrations which have
migrated into the soils, it is important that sample locations be placed
in areas with at least one meter of residual soil. Alluvial and glacial
deposits can also be sampled in most areas, provided there is not active,
high volume, sediment deposition (which would require a deeper sampling
method). Water-saturated soils and mud should be avoided because the wet
sediments clog the sampler and if the open pore spaces normally present
in the soil are reduced by water, then the amounts of free soil gas are
much lower than in non-saturated soils.
Shallow probe techniques are prone to near-surface lithologic, meteorological
and barometric effects. This means that one must be careful in interpreting
background values since the absence of an anomaly in a prospective or
producing area may be related to lithology, rainfall, meltwater or barometric
pumping. Areas containing anomalous high gas contents, on the other hand,
are almost always real seeps, since active flux is necessary to overcome
these dilution effects.
Shallow probes have been used successfully at Lost River in Hardy County,
West Virginia, Patrick Draw in Sweetwater County, Wyoming (Matthews et
al., 1984; Richers et al., 1982), Arrowhead Hot Springs in San Bernardino
County, California (Burtell, 1988) and on a large number of surveys conducted
throughout the industry. Limited tests by Williams (1985) in the west
Texas Permian Basin suggest that shallow probes are difficult to use in
this area because of impermeable deposits of caliche and thick salt and
anhydrite beds at a depth of about 300 meters. An example of a halo-type
anomaly reported by Williams (1985) is included in his thesis.
Despite these limitations, shallow probe sampling is still worthy of consideration
because of the low sampling cost and ease of access in rugged areas with
limited roads. With this method, small crews of only one or two persons
can obtain large numbers of samples at minimal expense. In addition obtaining
a permit (if required) is usually relatively simple because permitting
authorities tend to classify such surveys as causing minimal environmental
impact. The mobility of the soil gas probe sampling technique opens up
large areas to geochemical exploration that are otherwise difficult to
Another means of obtaining free soil gas data is from auger holes drilled
to 3.5 meters (12 feet). These holes generally yield higher hydrocarbon
concentrations than shallow probes. A fairly extensive research program
at Gulf Research and Development Company established a database for geochemical
exploration using auger holes comprising more than 21,000 analyzes covering
16,000 line km (10,000 line miles) (Jones and Drozd, 1983). The locations
of some of the research surveys are shown by black dots on a map of the
major US basins (Fig. 5-18).
An important aspect of this technique is the data contain compositional
information which not only can be tied to known fields but also is capable
of predicting the oil versus gas potential of an unknown area before drilling.
This predictive capability has proven to be applicable to several other
techniques as well.
A diagrammatic representation of the soil gas sampling procedure used
by Gulf Research and Development Company is shown in Fig.
5-19. Soil gas measurements are made in an auger hole, at least 4
meters (13 feet) deep and typically 8.9 cm (3.5 inches) in diameter. A
probe jacketed with an inflatable rubber packer is placed in the hole.
When inflated, the packer effectively isolates the bottom of the hole
from the atmosphere, so that the sealed base of the hole effectively serves
as the sample container for the liberated gases. Soil gases are then either
pumped into evacuated steel bombs or glass bottles for later analysis,
or pumped directly into an on-site dual-column gas chromatograph for determination
of the light hydrocarbons, helium and hydrogen. A 1 meter alumina-packed
column coupled to a Flame Ionization detector (FID) is used to determine
the hydrocarbon content and a 3 meter molecular sieve column coupled to
a Thermal Conductivity detector is used for the hydrogen and helium determinations.
Carbon dioxide is analyzed continuously using infrared adsorption techniques.
The auger hole technique yields excellent compositional information, even
though the magnitudes are influenced slightly by the mechanical disaggregation
associated with the drilling process. Compositional results for auger
holes are sufficiently important to warrant further discussion here. An
empirically-determined range of soil gas data is shown in Table
5-VII and a small selection of auger hole survey results is shown
in Table 5-VIII. The geochemical distinction between gas-type basins and
oil-type basins was first noted from surveys in the Sacramento and San
Joaquin basins in California. Initial compositional data were gathered
in these two basins in three separate years with excellent repeatability
(Table 5-VIII). Additional
surveys conducted in southwest Texas supported the differences noted in
California. Final confirmation on the oil versus gas predictions was obtained
when numerous surveys were carried out in all three types of productive
areas: gas, gas-condensate and oil. Soil gas data from the Sacramento
dry-gas, Alberta gas-condensate, and Permian basin oil areas were used
to establish statistically valid populations based on histograms that
demonstrate a close association with reservoir gases and gas shows in
Some typical percentages of methane and relative amounts of ethane through
butanes in different types of deposits are given in Table
5-IX. These data, taken from Katz and Williams (1952), show clearly
that methane decreases in the trend from a dry-gas deposit to a typical
low-pressure undersaturated oil deposit containing only dissolved gas
but no gas cap. A better demonstration of this relationship comes from
the study by Nikonov (1971), who compiled gas-analysis data from 3,500
different reservoirs in the United States, Europe and the then USSR, and
grouped them into the populations shown in Fig.
5-20a. Gases from basins containing only dry gas (designated NG) contain
less than 5% heavy homologs, whereas gases dissolved in oil pools (designated
P) contain an average of 12.5% to 15% heavy homologs. The heavy homologs
include ethane, propane, butane and pentane.
Three of the near-surface data sets from Table 5-VIII are particularly
convincing because the soil gas measurements were made in basins that
contained only one type of production. As shown by Figure 5-20b, they
are the dry-gas production of the Sacramento basin (more than 450 sites),
the gas-condensate production in the Alberta foothills (more than 650
sites), and the oil production of the Permian basin (more than 450 sites).
Figures 5-20c, 5-20d and 5-20e show methane content (%C1), the methane:ethane
ratio (C1/C2), and the propane:methane ratio (1000 x C3/C1), respectively
from the soil gas populations over these three basins. These data clearly
demonstrate that the chemical compositions of the soil gases from these
three different areas form separate populations that appear to reflect
the differences which exist in the subsurface reservoirs in these three
basins. This correlation is particularly striking when compared with the
data of Nikonov (1971), shown in Fig. 5-20a.
The use of hydrocarbon compositions in soil gas prospecting requires enough
data to allow statistically valid and separate populations to be defined,
so that a particular geochemical anomaly can be related to a geologic
or geophysical objective or province. A percentage composition based on
only two or three sites having 85% or 95% methane is not sufficient to
define a population. As shown in Fig. 5-20a, considerable overlap exists
among the intermediate gas-condensate and oil-type and gas-type deposits.
In basins having mixed production, prediction of a reservoir gas-to-oil
ratio (GOR) is clearly impossible.
Where seeps contain gases from more than one reservoir, their compositions
may not match those of any of the underlying reservoirs. Mixing of a shallow
oil and a deep gas will generally yield an oily but intermediate-type
composition. Without some knowledge of the reservoir possibilities, this
type of signature cannot be recognized. Nevertheless, the intermediate
nature of the seep will indicate some liquid potential at depth. Thus,
dry-gas basins can be distinguished from basins that have at least some
liquid oil or condensate potential. As suggested by Bernard (1982), the
presence of fairly large ethane-propane-butane anomalies strongly suggests
an oil-related source.
Pixler (1969) found that the gases observed during drilling could distinguish
the type of production associated with the hydrocarbon show during mud-logging
and published the graph shown in Figure 5-20f. Pixler's data were obtained
by monitoring the C1-C5 hydrocarbons collected by steam-still reflux gas
sampling during routine mud logging. Individual ratios of the C2-C5 light
hydrocarbons with respect to methane provided discrete distributions that
reflect the true natural variations of formation hydrocarbons from oil
and gas deposits. Ratios below approximately 2 or above 200 indicated
to Pixler that the deposits were non-commercial. The upper range for these
ratios for dry-gas deposits has been enlarged by Verbanac and Dunia (1982),
who studied more than 250 wells from 10 oil and gas fields. Their data,
shown in Figure 5-20h suggest the following upper limits for dry-gas reservoir
ratios: C1/C2 <350, C1/C3 <900, C1/C4 <1,500, C1/C5 <4,500.
These ratios clearly aid in defining the transition between thermogenic
and biogenic gases. Another empirical rule suggested by Pixler is that
the slope of the lines defined by these ratios must increase to the right;
if they do not, the reservoir will be water-wet and therefore non-productive.
Verbanac and Dunia (1982) suggested that a negative slope connecting individual
ratios may result from fractured reservoir zones of limited permeability.
Auger hole soil gas data for the surveys over the three basins described
above are plotted on a Pixler-type diagram of reservoir gases in Fig.
5-20g. Direct comparison of these two independent data sets is very striking
and proves the concept of migration of reservoired hydrocarbons to the
surface. It is important to note that amounts of migrated gases almost
always decrease in the following order: methane > ethane > propane
> butane. Thus, in a Pixler-type diagram, soil gas data, like reservoir
data, generally plot as line segments of positive slope for the soil gases
to represent a typical migrated seep gas. Exceptions to this order have
been noted where surface source rocks were drilled, which thus far have
yielded ratios with lighter gases depleted in relation to heavier gases.
According to Leythaeuser et al. (1980), this would be expected if gases
in the boundary layer very near the surface followed a diffusion model.
Thus, compositional changes related to diffusion might be expected at
or very near a boundary layer where the hydrocarbon gas concentration
approaches zero. This behavior has been observed when comparing soil gas
probe data measured at very shallow depths (0.3 to 0.6 m, 1 to 2 ft) with
the corresponding data from 4 meter (13 feet) auger holes. The shallow
probe data are always "oilier", indicating preferential loss
of methane and implying diffusion from the 4 meters (13 feet) level to
the surface. If diffusion were the dominant migration mechanism, a chromatographic
effect would be expected for gas that migrated through the Earth. The
fact that the compositions of the soil gas data from auger holes match
the underlying reservoirs confirms that the major migration mechanism
to the near-surface must be via faults and fractures, rather than by diffusion.
The percent-methane compositions from the auger hole surveys conducted
over the Sacramento and San Joaquin basins are plotted in Fig.
5-21. There is a decrease from 98% methane in the north of the Sacramento
basin to 90% in the south part, whilst the soil gas over the San Joaquin
basin has 82% methane. These data imply that a soil gas grid would have
defined local differences regionally. Furthermore these geochemical data
are repeatable (Table 5-X);
the percent-methane values on Fig. 5-21 were all determined at least two
or three times over a three-year period and found to be repeatable. Compositional
data have remained repeatable throughout our experience with soil gas
In offshore prospecting "sniffers" have been used to detect
anomalous hydrocarbon concentrations in bottom waters. An extensive review
of the literature was published by Philp and Crisp (1982). Some of the
most significant results reported by Williams et al. (1981) are highlighted
Gulf Research and Development Company designed and operated several marine
seep detectors which were employed aboard various research vessels, such
as the RV Hollis Hedberg and its predecessor the RV Gulfrex. These ships
circumnavigated the globe and conducted extensive detailed surveying in
areas such as the Gulf of Mexico (Mousseau , 1979). The RV Hollis Hedberg
system employed three separate water inlets which, whilst the ship was
underway at normal seismic survey speeds, continuously supplied sample
streams from the near surface, intermediate depths to 135 meters (450
feet) and a deep towed sample inlet at a depth of nearly 180 meters (600
feet). Each sample stream is analyzed for seven hydrocarbon gases once
every three minutes with a sensitivity that depends upon the hydrocarbon
and, for example, is about 5 x 10-11 liters of propane at STP per liter
of seawater. By using multiple depth inlets, surface contamination can
be demonstrated to have no effect on seeps observed by the deep inlet.
At sea "sniffer" geochemical data from a deep tow inlet were
superimposed to scale on a seismic section to aid the explorationist in
making real time evaluations of hydrocarbon potential of structurally
As for surface soil gases, a powerful confirmation of the validity of
marine geochemical data can be shown by the very close agreement between
the composition of component hydrocarbons in production gases and the
composition of seep anomaly gases in the same areas. Figure
5-22 shows the well database used for this confirmation in the Gulf
of Mexico (Rice, 1980). For each of the 32 fields shown on this figure,
the USGS has published the composition of gases produced from predominantly
gas fields, oil fields and combined oil and gas fields or condensate fields.
A crossplot of the compositions of gases from all field types is shown
in Fig. 5-23 (Williams et
al., 1981). The underlying color code on this figure was chosen to distinguish
oil, oil-condensate, gas-condensate and gas production using the Rice
well analysis data as a standard.. The log of the ratio of ethane to propane
and butane is plotted against the log of the ratio of methane to ethane
plus propane. A distinctive compositional clustering of gas anomalies
signifies different kinds of production: oil anomalies occur near the
origin and become gassier as the points move up and to the right in Fig.
5-23. A comparison of 146 sniffer geochemical anomalies from the same
part of the Gulf of Mexico is plotted in Fig.
5-24b for direct comparison with the Rice well data shown in Figures
5-23 and 5-24a. As shown, the overall distribution is very similar to
the well data. Figures 5-24d and 5-24e illustrate the contrast in composition
of dissolved hydrocarbon anomalies from a gas area and an oil area in
the Gulf of Mexico. This type of regional separation was found to be typical
of surveys conducted throughout the world.
The fact that production and surface anomaly gases correspond both onshore
and offshore is significant. It proves that the observational techniques
are valid despite the great variation in these surface environments.
A headspace sampling technique is commonly employed for the analysis of
canned samples from drilling returns and from shallow sediments. In this
technique a controlled volume of sediment is placed in a can or jar filled
with a measured volume of degassed brine. The can is sealed and a measured
volume of brine is displaced with nitrogen to create a known volume headspace.
The can is then allowed to come to equilibrium. The concentration of light
gases can then be measured by syringe injection of a headspace sample
into a gas chromatograph equipped with an Flame Ionization detector.
In order to maintain reproducibility it is important to measure all volumes
accurately. In a typical operation using 500 ml (one pint) cans, the procedure
is to place 300 ml of degassed salt water brine into the 500 ml can and
add sediment until the can is filled to the brim, giving 200 ml of sediment
and 300 ml of brine. The can is sealed and then zero-grade nitrogen is
injected through a prepared septum to displace 100 ml of brine and leaving
the can with a 2:2:1 mixture of 200 ml brine, 200 ml sediment, and 100
Experiments have shown that a fairly long time is required for the adsorbed
sediment gases to completely equilibrate with the headspace. This equilibrium
time is shortened by heating and shaking the cans before analysis. A generally
accepted procedure is to heat the cans for about 12 hours at 60oC to 70oC,
followed by shaking in a paint mixer for five minutes. After heating and
shaking, the cans are allowed to stand for at least five further minutes
to ensure that dissolved gases return to the headspace.
One of the drawbacks to using this technique is the need to freeze the
canned samples if they cannot be analyzed within one or two weeks of their
collection. Failure to follow this procedure can create problems because
of the generation of biogenic gas in the cans or the bacteria oxidation
of the hydrocarbon gases to carbon dioxide.
Hydrocarbon concentration values are reported in terms of ppm by volume
in the nitrogen headspace or as ppm or ppb by weight, normalized to the
weight of sediment. Gases concentrations reported by weight are not truly
representative of the actual gas migrating from depth because some of
the free gas has been allowed to escape during collection and sample preparation.
Furthermore, the sorbed gas is never completely extracted into the headspace,
and may not always reflect the true gas content of the soil.
The headspace sampling technique can yield useful results if sufficient
numbers of samples can be collected to use statistical populations to
suggest anomalous areas. One should always exercise caution, however,
with respect to characterization of gas composition, since evaporation
during the collection stage always occurs, resulting in the relative depletion
of the lighter gases.
Extensive soil gas sampling programs carried out by the petroleum exploration
industry have demonstrated that the crushing and/or disaggregation of
soils (including the action performed in drilling auger holes) is an important
component part of the extraction of gas from the soil. This suggests that
it would be advantageous to employ a soil core disaggregation technique
which would closely mirror the effect of auger hole drilling. A device
developed at Citco and commonly used in both industry and academia for
analyzing well cuttings appears suitable for accomplishing this objective
(Whelan, 1979; Hunt and Whelan, 1979; Whelan et al., 1980). In fact, Richers
(1984) has demonstrated successfully that in some instances, such as at
Rose Hill, Virginia, and in the Western Overthrust Belt, the results obtained
by this technique are in very good agreement with data from auger holes.
The device used in this technique is a small stainless steel ball-mill
containing two stainless steel or ceramic balls which crush and disaggregate
the sample when the ball-mill is shaken (Fig.
5-25). This approach concentrates the loosely bound adsorbed gases
into the headspace of the ball-mill. Because of the equilibrium problem
mentioned above under headspace techniques, this sampler was adapted by
Whelan (1979) and Whelan et al. (1980) to ensure that lithified sediments
and cuttings are completely broken up during analysis. Basically, the
technique is as follows.
A small (but constant) volume of sediment, soil or cuttings is placed
into the mixer cell along with two ceramic or stainless steel ball-bearings,
and water is added to bring the remaining headspace to 10 cc. The mill
is sealed and placed in a SPEX/Mixer-Mill and agitated for about five
minutes. The cell is then immersed into a hot-water bath at 90oC for three
minutes. A 1 ml aliquot of gas-free water is injected into the cell through
a septum-sealed side arm on the cell, and then a 1 ml aliquot of the headspace
is sampled using a locking gas-tight syringe. The sample is then hand
injected into a gas chromatograph equipped with a Flame Ionization detector
for analysis of the disaggregated gases. It is assumed that these gases
represent micopore gas, some free gas and lightly adsorbed gas on the
sample medium surface.
This technique (or modifications of it) has been used in the analysis
of well cuttings and deep sea cores (Hunt and Whelan, 1979), in addition
to surface geochemical prospecting (Richers et al., 1986; Richers and
Initial tests of this method were conducted at Gulf Research and Development
Company for comparison with the auger hole technique and to gain a better
understanding of the relationship between free gas and adsorbed gases
liberated by the drilling process. To be an effective and viable technique,
the disaggregation desorption method must be able to distinguish between
oily and gassy areas. An area known to be predominantly oily, Rose Hill
in Lee County, Virginia, and another known to be predominantly gassy,
the Gulf Research Facility in Pittsburgh, Pennsylvania, were chosen as
initial test sites. Both areas had been sampled previously using the auger
hole technique, allowing the new data to be compared with the established
data sets (Richers, 1984).
The Rose Hill test site includes 126 soil cores of which 51 fall within
300 meters (1,000 feet) of the earlier auger holes. Despite differences
in the sample locations and depths, both techniques correctly identify
the area as oil-prone. Table 5-XI
shows the relationship between the diagnostic gas ratios (Jones and Drozd,
1983) and the results of the two surveys (Richers, 1984). It is obvious
that the ball-mill technique accurately describes the oil-prone nature
of the Rose Hill oil field. However, the data of Table 5-XI suggest a
slight difference the composition of the hydrocarbons detected by the
two techniques. In the auger holes the soil gas is slightly drier (methane-rich)
than the soil gas obtained by ball-mill disaggregation-desorption. This
shift may reflect the preferential loss of methane in the from the shallow
cores compared to the deeper auger holes and the use of core samples instead
of free gas measurements. The other gases are essentially the same in
both techniques: the iC4/nC4 ratio for the disaggregation technique is
0.34, and the auger hole technique yields a value of 0.40; the C2/C3 ratios
are comparable at 1.84 for the disaggregation technique and 1.76 for the
auger hole technique. In addition, the intercorrelation of the various
hydrocarbon gases in the disaggregation data set is higher than that for
the auger hole data. This high degree of correlation among the gases may
reflect a near-equilibrium condition achieved through time for the adsorption-desorption
process in soils. Hence, the signal seen by the desorption technique may
effectively integrate and smooth rapid changes one might expect to see
with a free-gas technique such as auger holes.
At the Gulf Research Facility in Pittsburgh, Pennsylvania, there are two
producing gas wells, and 38 sites were selected to test the ability of
the disaggregation technique to define gassy areas. Not only did the test
yield gassier results than those obtained at Rose Hill, but also the results
were again comparable to those obtained using the auger hole technique.
Table 5-XII is a compilation
of these results. Clearly, the two data sets reflect a more gas-prone
area for Gulf Research Facility than for the Rose Hill area. Although
the data set for the disaggregation technique is only half of the size
of the data set from the auger holes, it still yields useful information
regarding composition of the subsurface reservoirs.
A technique which measures only the most tightly bound gas was originally
developed by Horvitz (1939, 1945, 1950, 1954, 1957, 1965, 1969, 1972,
1980, 1981). In this technique the sample is subjected to acid digestion
under vacuum at an elevated temperature of about 80oC. Further developments
by Debnam (1969) and Horvitz (1972, 1981) involved corrections for lithology
to reduce the effect of acid-soluble minerals biasing the data. Debnam
(1969) noted that soil samples could be dried, pulverized and sieved without
affecting their hydrocarbon content. He also noted that sieving sand samples
to <200 mesh gave analytical values comparable with those produced
by shale samples from the same location. Horvitz developed a wet-sieving
technique to concentrate the analysis on only the clay-fraction of the
McCrossan et al. (1971) evaluated the acid-extraction technique in the
western part of Alberta. This extensive survey of over 4561 samples covering
15 townships concluded that the distribution of anomalous points was random
and was strongly biased by samples rich in carbonate minerals. Adequate
corrections for amounts of acid-soluble material were not successful and
it was concluded that this method could not be used in areas covered by
As early as 1940, Sanderson had discussed a number of factors that affected
adsorption of hydrocarbon gases by soils. He noted that the ability of
the soil to adsorb any gas depends upon the type of gas, the characteristics
of the soil and the conditions under which the soil is exposed to the
gas. Adsorption will depend upon the type and surface area of particles
and their chemical composition. The surface reactivity will be modified
considerably by the presence of previously adsorbed molecules, such as
carbon dioxide, water and mineral ions. The condition of adsorption is
complicated by temperature and pressure and length of exposure time in
addition to concentration and species of gases present. Adsorbed gas data
can, at best, be only approximations of the original mixture of migrated
gases. Another possible problem lies in the quantitative desorption of
the gases from the mineral components of the soil.
Sanderson (1940) observed up to six-fold differences in the ability of
soils to adsorb hydrocarbons in his laboratory. He also noted that the
adsorptive characteristics of the colloidal soil systems would vary slowly
with moisture content, time and season. Of particular significance was
his observation that the adsorptive capacity for hydrocarbons on wet soil
was only a small fraction of that for dry soil. A further complication
is created by near-surface biological activity that creates wide variations
in the content of carbon dioxide, nitrous oxide and other biological gases.
Overcoming all these problems is probably impossible; however, it will
suffice if the gases are liberated in proportion to the amounts present
so that the analytical results bear some relationship to one another,
and allowing identification of potentially prospective areas.
Various other approaches have been devised in attempts to overcome this
problem. Bays (US patent no. 2,165,440) suggested correcting for the sorptive
power of the soils and McDermott (US patent no. 3,120,428) suggested correcting
for the surface area. An alternate technique proposed by Thompson (1971)
used ethylenediaminetetracetic acid (EDTA) at about pH 7 and slightly
heated in order to decompose the carbonate minerals under conditions that
do not release such large quantities of carbon dioxide. Thompson reports
that a comparison on duplicate samples shows that the EDTA technique consistently
releases from 94% to 99.5% of the hydrocarbon gases released by the standard
strong-acid treatment. A further refinement of this method by Thompson
et al. (1974) separates a critical carbonate mineral before analysis.
This critical mineral was almost always found to be dolomite, but occasionally
is other carbonate minerals, such as iron or calcium carbonate. The ratio
of hydrocarbons per unit of critical mineral is then plotted to form a
geochemical prospecting map. This technique was reported to highlight
a salt dome in the Gulf of Mexico on which a major oil discovery was made
after the survey was conducted.
Poll (1975) addressed this problem of lithologic corrections by dividing
data according to desorption efficiencies based on their physiochemical
properties. The first step is to prepare a detailed lithological description
of the samples. This involves a differentiation on sediment lithology,
sample coherence, structure, cementation and mineral types, including
carbonate and sand percentages. This information is used as shown in Fig.
5-26 to classify the samples into homogeneous sets for each of which
the average, or background, gas content is computed. The gas content in
each group is assumed to be distributed according to a Laplace-Gauss law.
Each subset is then assumed to have a uniform efficiency of desorption
and its own background and anomaly threshold. As shown in Fig.
5-27, for calcareous sediments these are very high, due to the effectiveness
of the acid attack. The mean normal standard can be computed for each
set yielding dimensionless values that can be added together for mapping,
regardless of the sediment type. This technique has been applied by Poll
(1975) in the Gippsland Basin and by Devine (1977) and Devine and Sears
(1985, in the Cooper Basin in Australia. Reasonably positive results were
reported in all three cases.
The acid-extraction technique relies on the ability of soil and minerals
to retain hydrocarbons that migrate past them through the soil pore system.
It is therefore not subject to the fluctuation involved in the soil air
system but hopefully represents some averaged or integrated signal over
time. As noted above, the samples must be corrected for lithologic effects
by only making comparisons within a given lithology or by specifically
analyzing certain minerals. Corrections must always be applied because
adsorption occurs in both the fine-grained fractions and in carbonates,
which often release disproportionately large amounts of hydrocarbons.
As an extension of the light hydrocarbon gas analysis, UV fluorescence
spectroscopy can be used to measure the oil potential of near-surface
sediments by analyzing their aromatic hydrocarbons. The method is highly
sensitive and selective method for the analysis of oil components, particularly
those containing one or more aromatic functional groups. Using spectroscopic
scanning, complex molecular aggregates, such as those found in crude oils,
can be rapidly characterized and quantified on the basis of their combined
intensity wavelength distribution or "fingerprint".
The fluorescence spectra of nine crude oils of different gravity are shown
in Fig. 5-27 (Purvis et al., 1977). These two-dimensional fluorograms
were produced by exciting at 265 nm and scanning from 250 nm toward the
red end of the spectrum. The accepted procedure for illustrating the change
in the emission spectrum associated with different gravity crude oils
is to measure the intensity of fluorescence at two wavelengths: 320 nm
for light aromatic compounds; and 365 nm for the heavier, multiple-ring
aromatic compounds. The intensity of the fluorescence emission is proportional
to the quantity of aromatics in the extracted sample. The standard field
method employs a rapid wet extraction process which dissolves loosely
bound trace aromatics into hexane. This extract generally favors the heavy
oil fraction, which is in hydrophobic association with the sediment.
A second phase of in-depth, total scanning fluorometric analysis is often
performed on selected anomalous samples identified by the field fluorescence
or by adsorbed and interstitial gas data. These samples undergo freeze
drying followed by a thorough cyclic extraction in hexane to optimize
recovery of associated sedimentary aromatics (Brooks et al., 1986). The
oil type is then determined by total scanning fluorescence which employs
step-wise scanning of excitation and emission wavelengths to produce a
three-dimensional fingerprint fluorogram (Fig.
Spatial patterns of near-surface hydrocarbon composition and concentration
are prime factors when interpreting the survey results. Results from a
poorly-designed or an uncontrolled survey can be difficult or impossible
to interpret, and can lead to a completely erroneous assessment of the
hydrocarbon potential of an area. An improperly-spaced grid with sample
spacing in excess of target size can result in only the most cursory assessment
of potential, with anomalous areas appearing as localized single-point
anomalies (Matthews, 1996a).
The distribution of sample sites in a geochemical survey is largely governed
by the purpose and budget of the survey. For regional surveys a sampling
density of one sample per 2 km2 to 5 km2 seems adequate. Such a density
still allows for the discrimination of regional ambient backgrounds from
secondary backgrounds. Detailed diagnostic work requires a close-spaced
grid, sometimes with a sample interval of only a few tens of meters.
Regional sampling is generally performed using a modified grid because
a regular grid, on which samples are taken at the intersections of a straight
lines, does not minimize cost or maximize information. We recommend that
sample positions be chosen within grid cells according to ease of access
(minimum cost) and along zones of known or inferred fracturing and faulting
(maximum information). Satellite imagery, aerial photography, seismic
data and other data are useful when attempting to site samples on or near
fractures and faults. The analytical results from a regional survey should
yield some indication of compositional and/or magnitude "sweet-spots",
either as isolated data points or small clusters. If the objective is
merely to evaluate whether a basin has a source section, and general trends
of where it is mature and focused to the surface, a regional study may
be all that is required. A more detailed follow-up survey, however, is
recommended if the objective is to highlight the zones of higher hydrocarbon
One method commonly employed for detailed surveys is to sample seismic
shot holes, further providing a means to easily tie the geochemistry to
subsurface structure. Because seismic lines are not normally placed on
a close-spaced grid, infill sampling between seismic lines is usually
recommended. It should be emphasized that in order to define a target
adequately, approximately 70% of the data should be collected in presumed
background areas beyond the immediate target area. An embarrassingly large
number of surveys have been performed in which sample locations do not
extended more than one or two sites beyond the anomaly. The result of
this misplaced desire to save money is often an ambiguous survey interpretation.
The selection of a technique that is inappropriate for the surface geologic
conditions in part of the survey area can also lead to erroneous results.
An example is the use of the acid extraction technique on glacial till
or acid soils, which normally yield low results. Without regard to the
particular constraints on such data, one could easily overlook a favorable
area. In this case another technique such as free gas would be more representative.
There are many ways to analyze hydrocarbon gas data with no one particular
method being correct or incorrect. Common sense and a deterministic approach
to sound geologic models are the best guidelines. Integration with other
data such as structure, lithology, soil types and hydrogeology, to name
a few, can be most fruitful.
The lack of a model explaining the mechanisms and constraints of hydrocarbon
leakage is often an obstacle to the acceptance of surface geochemical
prospecting (although a similar lack of understanding of the migration
of hydrocarbons from source beds to reservoir has not precluded the acceptance
that migration occurs). Assimilation of the data, however, suggests that
much can be explained by a relatively simple model. The conclusion that
effusion is the dominant mode of migration enables us to use the visual
patterns associated with macroseeps as a basis for our microseepage model.
Link (1952) and Levorsen (1967) have summarized the geologic conditions
and controls on macroseepage. There is no reason to expect that these
controls should not apply as well to microseepage; the only real difference
should be a matter of scale. In addition to seepage directly from exposed
source beds, controls on surface seepage include: (1) the surface exposure
of reservoir beds or porous carrier facies; (2) porosity associated with
unconformities; and (3) surface expressions of faults and fracture systems
that are pervasive to depth. These controls may be summarized as the focusing
of migration along preferred permeability pathways. Horizontal migration
along the pathway is dominated by grain or bed permeability (including
old erosion surfaces and other unconformities), whilst vertical migration
is controlled by cross-stratigraphic discontinuities.
Horizontal pathways deflect the surface location of the anomaly laterally
away from its subsurface origin. Thus if an anomaly is associated with
the surface expression of a porous formation, one should suspect a down-dip
source (or down-groundwater gradient source). The same conclusions can
be inferred for anomalies associated with unconformities, low angle faults,
and listric faults.
Vertical pathways are dominated by the intersection of high angle faults
and fractures with reservoir and carrier beds. In this case the surface
expression of the source of the hydrocarbons will lie directly above,
or only slightly displaced from the source. The presence of multiple,
stacked porous zones also often results in a surface geochemical expression
that is approximately vertically over its subsurface origin.
The role of faults and fractures is particularly important for microseepage
and some further comment is in order. The close association of near-surface
geochemical anomalies with faults and fractures has been pointed out by,
amongst others, Horvitz (1939), Sokolov (1971 b), Richers et al. (1982),
Jones and Drozd (1983) and Matthews et al. (1984). McCrossan et al. (1971)
point to the close association of high concentrations of hydrocarbons
in the surface environment with photolineaments. McDermott (1940) suggests
that the permeability of shale is dominated by microfractures and that
these fractures are preferentially normal to the bedding plane. This potentially
important role of microfractures is emphasized by Rosaire (1938), who
correctly points out that the failure to observe displacement does not
eliminate the existence of a fault or fracture.
The high permeability of fractures causes them to preferentially focus
fluid flow. The effectiveness of fractures as mass transport systems for
fluids is evident from a casual examination of mineralization in fractured
rocks and leakage of groundwater at fracture outcrops. Similarly, these
fractures act as preferential hydrocarbon pathways, focusing their flow
from source beds to surface.
Faults and interconnected fracture systems have a significant effect on
the magnitude and, less commonly, composition of the near-surface gases.
The effect on magnitude is generally to increase concentrations in fractured
areas, whilst the effect on composition theoretically should be preferential
loss of lighter gases compared to heavier gases. In practice, gas compositions
on faults are often lighter or heavier than those at neighboring sites.
This is believed to be controlled primarily by the depth of the fault
and the composition of the subsurface gases it conducts. Thus deep, basement-related
faults are often gassy because they tap deep over-mature sediments. Shallower
faults are often oily because large molecules migrate more easily than
the lighter compounds.
The increase in magnitude in fracture systems can often be abrupt and
localized. It commonly spans several orders of magnitude, going from nil
to macroseep levels in the extreme cases. In an area where there is no
significant source of subsurface hydrocarbons, there are no high magnitude
soil gas signals, even on faults and fractures.
In a hydrocarbon-bearing environment, however, overall high variance in
the data is more often the case, but the anomaly-to-background ratio is
smaller in non-producing areas than in producing areas. Some of these
anomalous zones are associated with preferential leakage directly from
a source bed, while others are from reservoirs. Since some faults and
fractures are sealed locally along their lengths, high magnitude signals
do not occur everywhere along their length. Thus, we often observe "hydrocarbon
spots", similar to the "helium spots" discussed by Wakita
(1978). Naturally, those faults penetrating only source beds will show
a signal that reflects the source beds, whereas those penetrating a reservoir
or both reservoir and source beds will exhibit a larger anomalous signal.
It is not known, however, if one can truly distinguish between the two
types in all instances, although extremely high magnitudes are felt to
be more diagnostic of reservoirs, as seepage volumes are expected to be
larger from reservoirs than from a source bed (Hunt, 1981).
The expectation that all samples in a leaking fracture zone are higher
than those outside the zone is simplistic, and is not always realized
in practice. A faults or fracture is rarely one discrete plane, but zones
of broken or disrupted strata, separated by relatively unaffected competent
strata. It is analogous to a fractured pipe: certain portions of the conduit
are solid, whereas the fractured section is composed of both intact fragments
and cracks. Fluids flowing through the pipe are going to leak in the fractured
areas of the pipe but not in the solid-walled portions. Similarly, even
in the fractured zones, the fragmented areas will leak only through the
fractures, not through the fragments of pipe between the fractures. Extrapolating
this model up to geologic scales, sampling outside the fracture zone is
expected to give values that are typical of the background of the area.
Within the fractured sample zone, sample sites may intersect discrete
fractures or encounter coherent blocks between the fractures (Fig.
5-29a). The intensity of fracturing, and hence the probability of
the fractures interconnecting, increases toward the center of the fracture
zone, as shown in Fig. 5-29b. Therefore, samples taken near the center
would be expected to be a mixture of high values (intersecting fractures
that connect), median values (intersecting fractures that do not connect)
and low values (not intersecting fractures). Further from the center of
the fracture zone, the maximum values fall until they merge with those
typical for the background of the area. This distribution of free soil
gas magnitudes as a function of distance from the center of the fracture
zone is shown in Fig. 5-29c (Richers et al., 1986). Disaggregation data
from Patrick Draw exhibit a similar pattern, although the increase near
the center of the fracture zone is not as great; acid extraction data
from this example show no obvious relationship, clearly suggesting that
different analysis techniques are extracting gases from different sources.
The following examples illustrate the means of interpreting what are often
referred to as direct anomalies using preferential pathway models. These
direct anomalies may be either vertically over their subsurface source,
or laterally displaced by varying amounts (Sokolov, 1971 b; Pirson, 1969;
Laubmeyer, 1933). What is generally not realized is that most areas contain
microfractures to the extent that they allow gases to escape vertically.
Using a coal-burn experiment in the central Wyoming coal region, Jones
and Thune (1982) showed that a definite vertical migration component could
be identified. In that experiment, gases formed during combustion appeared
both in soil gases directly above the retort and up-dip along the bedding
planes of the strata involved in the burn. Thus, vertical signals from
a known subsurface origin were shown to exhibit cross stratigraphic migration,
presumably due to the presence of fractures in the system. A second horizontally
displaced component also migrated along the bedding planes at the same
An example of the use of direct anomalies and the preferential pathway
model is shown in Fig. 5-30,
which shows an idealized subsurface cross-section through the Lost River
field in West Virginia along with a propane profile (Matthews et al.,
1984). From this profile and with some knowledge of the geology, it can
be seen that a large anomaly is probably caused by updip leakage of the
fractured Devonian Oriskany reservoir at depth. This outcrop anomaly is
due to updip leakage along the bedding plane of the reservoir facies.
A smaller but significant anomaly is related to leakage from a fault which
strikes along and to the east of the crest of the producing anticline.
Blind drilling on the outcrop anomaly would have resulted in a dry hole,
whereas drilling just west of the fault anomaly would have encountered
the producing structure. Appropriate geological modeling identifies the
location at which to drill.
An alternative to the direct anomaly interpretation method relies on identifying
one of two types of halo: (1) local lows, source background areas surrounded
by highs; or (2) extremely low areas, surrounded by moderate areas of
concentration. These halos are consistent with the initial results obtained
with soil gas analysis techniques (Rosaire, 1938; Horvitz, 1939, 1945,
1954, 1985; McDermott, 1940; Rosaire, et al., 1940), which indicated that
adsorbed and occluded hydrocarbons occur in greater quantities around
the edges of production, whereas relatively lower values are found directly
above production. Halo anomalies have been recognized in many regions
of the former USSR (Kartsev et al., 1959). Horvitz (1969, 1980) has emphasized
that although other hydrocarbon distribution patterns are recognized,
including direct anomalies, the halo pattern continues to be the most
common type found in conjunction with important oil and gas accumulations.
Numerous explanations have been put forth as to why halos form around
hydrocarbon accumulations. Most of these link the phenomena to the impedance
effect of a diagenic mineralization zone overlying the main part of the
petroleum accumulation. Such a zone would tend to reduce the ability of
gases to seep vertically, except along well pronounced fracture systems.
Hence, most transport would be deflected around the edges of the occluded
zone. The occluded zone could form by any number of diagenic processes.
Rosaire (1940) suggested that the greater solubility of carbon dioxide
in petroleum, as compared to water, results in the conversion of bicarbonates
to less soluble carbonates over an accumulation. An initial chimney effect
would result in a greater supply of bicarbonate being present above an
accumulation resulting in the cementation. Rosaire (1940) also proposed
the reduction of sulphates to sulphides over an accumulation. Fenn (1940)
reintroduced another process which was first introduced by Mills and Wells
(1919). This model is based on the evaporation of ground moisture as the
result of gas expansion which results in the subsequent precipitation
of minerals at shallow depths. The origin of the blocked central portion
over an accumulation implies that gas-induced evaporation occurs more
effectively over an accumulation than along its margins. This model is
consistent with results on the variations in unusual chemical and isotopic
compositions of carbonate-cemented surface rocks over oil and gas fields
(Donovan and Danziel, 1977; Donovan, 1974). Stroganov (1969) has confirmed
that the deeper distribution of hydrocarbons only rarely yields a halo
pattern, suggesting the halos have a near-surface origin. Matthews (1985)
suggested that diagenetic blockage related to hydrocarbon emplacement
may originate at intermediate depths and then be exhumed by erosional
Although direct anomalies and halos have conflicting explanations, both
appear to be valid. Indeed, the controversy is significant only if it
is assumed that lateral displacement has not occurred during subsurface
leakage. This is certainly is a valid assumption in some, but definitely
not all, cases. If the halo pattern is interpreted as a subset of several
preferential pathways, one can assume that at least one major flowpath
could become blocked by diagenetic cement, resulting in a bias of leakage,
with a false halo forming as the gases are diverted around this blockage
in an area that previously yielded a direct anomaly. In one study the
occurrence of halos was suggested by adsorbed soil gas samples, whilst
direct anomalies were observed using free soil gas samples (Richers et
al., 1986). One must speculate that these techniques measure different
aspects of the leakage phenomena. For this reason, it is felt prudent
to always collect both types of samples whenever economically feasible.
In addition one would be well advised to incorporate geological and geophysical
data into the model.
A significant portion of near-surface hydrocarbon survey results appear
to be compatible with the mechanisms of macroseepage, particularly leakage
occurring along preferential pathways. Those anomalies seemingly not coincident
with known faults, fractures, unconformities, bedding planes or other
obvious pathways may lie on pathways unrecognized due to limited or incorrect
mapping. Alternatively, some occurrences may represent processes not completely
understood, or processes not validly extrapolated from macroseepage to
The preferential pathway model summarizes the movement of hydrocarbon
fluids through the subsurface to their final destination as a surface
seep, either directly or by way of an intermediate trap. It is certainly
not definitive nor complete, but illustrates some of the challenges confronting
the petroleum geologist in his quest for new resources.
An alternative to modeling hydrocarbon gas migration as a basis for data
interpretation is to decompose data into geochemical populations. On this
basis surface geochemical data can be interpreted with respect to both
composition and magnitude.
The goal of compositional analyzes is to be able to characterize the type
or types of subsurface accumulations present and to be able to predict
the location at which they occur. This can be achieved through using ratios
of the various hydrocarbon constituents that are detected in the soil
gas sample. In general, gas reservoirs are commonly dominated by the presence
of methane, whereas oil reservoirs usually contain additional quantities
of hydrocarbon gases heavier than methane (Nikonov, 1971).
There are three potential origins for gases detected in the near-surface
environment: biogenic, thermogenic (or katogenic) and igneous (including
mantle degassing); and irrespective of the origin, the gases tend to migrate
towards the surface due to pressure and buoyancy effects. Gases from several
sources may mix or undergo other compositional changes such as chromatographic
separation during this migration. Thus the measured compositions may not
always reflect the original subsurface composition. In most areas mixing
presents little problem because gases of thermogenic origin are by far
the most abundant. Furthermore, the tendency for gases of biogenic and
igneous origin to be extremely dry and of a different isotopic composition
from thermogenic gases enables recognition of their presence. Extreme
chromatographic separation may only be recognized by careful isotopic
analysis and through the close comparison of near-surface gas with known
reservoir gas in the region. The presence of gas of igneous origin generally
indicates the occurrence of deep, pervasive faulting, and/or the presence
of igneous activity in the area. This association, as well as the extremely
methane-rich character of such gases, allows for the facile distinction
between gases from thermogenic and igneous sources.
Telegyna and Cherkinskaya (1971) found that the olefin content of soil
gases decreased relative to saturated hydrocarbons until depths of about
300 meters. Experimentally, as illustrated in Table
5-XIII, olefins can be formed from saturated compounds in areas of
low oxygen content (0.5% to 3.2 %). The presence of these olefins may
be biogenic (Smith and Ellis, 1963), although Starobinetz (1976) showed
a linear relationship between the concentrations of saturated and unsaturated
gases derived from the thermogenic alteration of organic matter. Sokolov
(1971 b), among others, suggested a relationship between the generation
of unsaturated compounds and drilling activity.
Gleezen (1985) showed that there is promise in using the olefin contents
of soil gases as a scaling factor to separate seep signals from ambient
signals. He was able to define areas with signatures similar to those
of the reservoired gases. It would appear that in some cases the presence
of olefins may merely represent the breakdown of saturated hydrocarbons
by some yet- undetermined process during the migration of gases to the
surface and/or some activity such as biogenic degradation of the saturates
in the near-surface environment (Telegyna, 1971).
Compositional information in soil gases has been related to subsurface
accumulations through the application of specific ratios (Jones and Drozd,
1983). Methane-dependent ratios (Table 5-VII) are reliable unless multiple
sources of gas are present in the area. An independent methane-rich source
biases an oilier composition toward a drier gas composition. This can
sometimes be overcome by plotting histograms of the compositional data
and noting multiple populations in the data. Another set of diagnostic
ratios that are not methane dependent has also been defined and further
aid in properly defining the true potential of an area (Drozd et al.,
1981; Williams et al., 1981). In general, the agreement between the surface
compositions with reservoir compositions is the strongest evidence that
surface prospecting can accurately define the potential of an area.
In addition to compositional information, soil gas data can yield useful
information according to the presence or absence of anomalously high magnitudes.
To understand the concept of anomalously high magnitudes, one must understand
the general distribution of gases in nature. Basically these can be reduced
to three main populations for any given region.
1) An ambient background population (which represents a detectable level
of non-significant hydrocarbon concentrations). This includes mantle-derived
hydrocarbons, contamination, instrumental noise, sampling error, etc.
2) A source background population representing hydrocarbons derived from
the presence of organic-rich source beds in a region. These are generally
areal in extent, and they may or may not be relatively consistent throughout
the area depending on local geologic variations, regional trends or multiple
3) An anomalous population of higher than normal concentrations of hydrocarbons
that represent the subsurface presence of concentrated hydrocarbons such
as those found in reservoirs.
Ambient levels, by their very nature, are encountered everywhere, and
are always a component of the total soil gas signal regardless of the
overall hydrocarbon potential of an area. Their presence may be due to
natural catagenesis of organically-poor rocks during the processes of
diagenesis and lithification, and can be thought of as being syngenetic.
Another source is the biogenic alteration of organic matter in the near-surface.
Typically, ambient background areas contain a little methane and virtually
no other hydrocarbon gases. An illustration of ambient background levels
is shown after Starobinetz (1983) in Table
Zinger et al. (1983) provides data that are typical of a sourced background
from the Kuybyshev oil-bearing area of the former USSR. Here the methane
content varies between 20% and 57%, with heavier homologues consistently
present. The backgrounds that occur in such areas are considered to be
sourced backgrounds because the effects of the pooled hydrocarbons are
superimposed on the lower sourced background signal.
The anomalous population comprises only a very small portion of the overall
data set, typically only a few percent. Values for these samples generally
are 2-3 times the magnitude of the sourced background. In some instances,
concentrations may reach the percentage level, in which case the locations
border on the macroseepage rather than microseepage. At the other end
of the spectrum are those samples that are 5 or 10 times above the sourced
background concentration. These may represent either a separate population
from the sourced background, or merely high frequency fluctuations in
the sourced background.
There are two fundamentally different approaches to defining anomalous
magnitudes. The tradition technique focuses solely on the distribution
of hydrocarbon concentrations, regardless of location. A magnitude threshold,
or series of thresholds, is chosen and those locations with value above
this threshold (anomalously high concentrations) are identified on a map.
The second technique focuses on the spatial clustering of anomalous stations.
This is accomplished by the identification of regions where the number
of stations with magnitudes above a threshold is statistically significant.
The traditional method of identifying a magnitude threshold has been accomplished
by a variety of techniques. These include: (1) the mean plus two standard
deviation of a normally-distributed data set; (2) arbitrarily selecting
the 90th percentile or 95th percentile, etc., of the data; (3) identifying
the inflection point on a cumulative frequency plot that deviates from
a straight line (Sinclair, 1976).
In the opinion of the authors it is dangerous to select any hard and fast
rule for defining an anomalous population, although the approach of Sinclair
(1976) is the most appropriate for a mixed mode data set. Sample populations
should be normal, or at least log normal, for many of the statistical
tests to be valid, and bias in sample sites should be avoided if possible.
Ideally a training set made up of a data subset with known hydrocarbon
potential should be employed. This gives a means to tie-in data to a known
feature, whether it be a source bed, a reservoir or a barren area. Once
the results are available, a first step is to construct histograms to
determine the spread of the data. The data can then be plotted on cumulative
frequency plots to determine the different populations. Scatter plots
of key components, such as methane versus propane, or iso-butane versus
normal butane, often yield multiple trends for multiple populations in
the data. Pearson correlation analysis also yields useful information
on the "cleanliness" of the data, with single populations generally
showing a high degree of inter-correlation. Filtering or screening the
data according to composition prior to applying statistics is also an
effective means of determining areas of favorable potential.
The method of identifying regions of anomalously high leakage by clustering
(Dickinson and Matthews, 1993) is accomplished by first identifying a
magnitude threshold and a search area. The magnitude threshold, which
is somewhat arbitrary, is used to transform the distribution of magnitudes
in to a binomial population (above the threshold "heads" and
below the threshold "tails"). The size of the search area (the
"cell") is such that it includes 20 or more sample stations
regardless of its location within the surveyed area. Once these parameters
are chosen, the cell is placed at one position on the map, usually in
one corner, and the percentage of heads and the total number of stations
within the cell are recorded. The cell is then translated to a new location
and the same parameters are recorded. This process is repeated until the
entire survey area has been examined. Because the properties of the binomial
distributions are well known, statistical tests of the chance of a particular
cell having a particular percentage of heads can be made and probability
maps contoured. Thus, regions of anomalously high frequency of magnitudes
above the threshold can be identified, and their chance of arising due
to random processes, instead of focused leakage, can be estimated. There
is, however, the risk that information about spatial variability within
a cell is lost and so is the information about the absolute magnitude
of individual samples.
On the basis of anomalous magnitudes, Zorkin et al. (1982) showed that,
in 90% of cases, the soil gas technique correctly identified areas lacking
hydrocarbon potential in Azerbaijan, and correctly identified areas with
hydrocarbon potential in 70% of cases (Table
5-XV). Although the distinction of ambient from secondary background
is often relatively straightforward, the distinction becomes ambiguous
in areas with effective seals, such as stable intracratonic salt basins.
Numerous case histories illustrating the relationship of surface seeps
to their associated production are given in the cited references. Four
surveys, three onshore and one offshore, are selected here to demonstrate
and confirm the compositional relationships defined above. The first onshore
example consists of calibration grids conducted over two fields in the
Neuquen Basin of Argentina, and the second example is a sniffer survey
conducted for calibration proposes over gas productive areas in the High
Island area of the Gulf of Mexico. The two other onshore surveys are located
in the Great Basin of Nevada and in the Overthrust Belt of Wyoming-Utah.
Neuquen Basin, Argentina
Detailed soil gas geochemical surveys were conducted for calibration purposes
over two fields, Filo Morado and Loma de La Lata, in the Neuquen Basin
in Argentina. These two fields were chosen for this calibration study
because of their differences in both reservoir composition and entrapment
Filo Morado is an anticlinal oil field producing from the Agrio Formation
at a depth of 3000 meters (10,000 feet). Loma de La Lata consists of two
stratigraphically-trapped reservoirs formed on a homocline which dips
to the northeast. Oil production comes from the Quintuco Formation at
2000 meters (6600 feet). This reservoir is partially underlain by a separate
gas to gas condensate reservoir producing from the Sierras Blancas formation
at 3000 meters (10,000 feet). The three separate reservoirs from these
two fields provide two oil reservoirs and one gas to gas condensate reservoir
for calibration of the soil gas geochemical data.
The geochemical data come from 239 shallow probe (1.2 meters, 4 feet)
soil gas samples collected on 500 to 1000 meter grids placed directly
over these two fields, with 95 sites over Filo Morado and 144 sites over
Loma de La Lata. The free soil gases were analyzed for methane, ethane,
ethylene, propane, propylene, iso-butane and normal butane by gas chromatography
using a Flame Ionization detector.
In order to illustrate the distribution and compositions of the light
hydrocarbon seepage, compositional dot maps which combine both the light
hydrocarbon magnitudes and compositional information are shown in Fig.
5-31 for Filo Morado and in Fig.
5-32 for Loma de La Lata. Each dot is colored according to the C1/C2
ratio to reflect the composition of soil gases as indicative of oil (green),
gas (red) or intermediate (yellow). The dots, including those at localities
with only background magnitudes, vary in size according to their ethane
The compositional subdivisions are derived from the published literature
(Nikonov, 1971; Jones and Drozd, 1983) and are the same as those shown
in Table 5-VII. The shade of each of the anomaly clusters suggests the
oil versus gas potential of the anomaly according to these empirical divisions
Ratios of methane/ethane, methane/propane and methane/total butanes for
all sites that exceed the median of the data are also shown in Figures
5-31 and 5-32, in order to provide a visual illustration of the composition
of the anomalous data. The bimodal nature of the Loma de La Lata soil
gas data is clearly shown by the red (gas) and green (oil) populations,
whilst Filo Morado stands in stark contrast, with its unimodal oily (green)
population and lack of gas-type anomalies.
Examination and comparison of these ratio plots and dot maps for each
of the two fields indicate that the more anomalous magnitude sites (large
dots) match the composition of the known underlying reservoirs. The areal
groupings and Pixler ratio plots of these specific components with their
appropriate reservoirs lends confidence to the deduction that these soil
gas anomalies are the result of migration of petrogenic hydrocarbons from
the underlying sedimentary sources.
The geochemical soil gas data exhibit clearly defined compositional sub-populations
which match the composition of the underlying reservoirs and change in
direct response to the major structural and/or stratigraphic features
that control the location of the subsurface reservoirs. Predictions of
oil versus gas from these soil gas data are in excellent agreement with
published soil gas and reservoir data (Jones and Drozd, 1983; Nikonov,
1971). A single oil source is predicted at Filo Morado, in agreement with
the known oil field. Much gassier soil gas data is noted over the Loma
de La Lata Field, where there exists an oilfield underlain by a gas to
gas condensate reservoir. However, a very striking change to fairly large
magnitude oil-type compositional anomalies occurs directly over the northwest
portion of the Loma de La Lata Field where the Quintuco oil reservoir
is the only known producing horizon. This change in composition from oil
to gas condensate signatures over the Loma de La Lata Field occurs across
a permeability pinchout at depth, which controls the updip limits of the
deeper gas condensate reservoir.
High Island area, Gulf of Mexico
A marine hydrocarbon seep detection survey was completed over High Island
Blocks 152A and 198A and surrounding areas on April 22-23, 1988, as shown
in the site location tract map on Figure
33a. This study, consisting of 239 miles of sniffer data, was conducted
aboard the RV/GYRE by Texas A&M University, in conjunction with Exploration
Technologies, Inc., using a marine hydrocarbon analytical system originally
designed by Gulf Oil Corporation for use on the RV/Hollis Hedberg. Light
hydrocarbon data were collected continuously along seismic lines of interest
from a water sampling system towed about 30 feet above the bottom of the
sea floor. A total of 52 miles of gridded data (259 analyses) were completed
over the Block 152 study area and a total of 31 miles of gridded data
(129 analyses) were completed over the Block 198 study area at 3 minute
intervals giving an approximate sample spacing of about 1500 feet. Anomaly
compositions are plotted on a marine cross plot in Fig. 33b for comparison
with the calibration cross plots in Figures 5-24 and three regional profiles
are included as Figure 34a,
34b, and 34c to show the magnitude variations along the survey lines.
Survey tracks, as shown on Figure 33a, include a 54 mile long regional
north-south line which extends from Block 198 down to Block 321 in the
High Island South extension. This regional line plotted on Figure 34b,
provides both a calibration data set over the known gas fields and a background
data set which extends between the two gridded blocks. As shown by Figure
34b, background values are observed in Blocks 237, 224, and 223 where
methane drops down to about 100 nl/l, ethane is below 0.70 nl/l, and propane
is below 0.50 nl/l. These thresholds are typical of Gulf of Mexico backgrounds
from previous study data (Mousseau and Williams 1979).
The largest magnitude anomalies observed on this entire survey, are also
noted on this regional line (Figure 34b), where it crosses the center
of Block 268 and traverses the major trend of the known gas producing
fields. Within this producing trend, methane goes over 500 nl/l, ethane
ranges from 1-2 nl/l up to 5 nl/l, and propane rises from 0.50 to 1 nl/l.
In addition, iso and normal butane reached a combined total of about 1
nl/l in anomalies associated with these known gas fields.
The presence of butanes in the sniffer data clearly separates the southerly
gas producing trend from that data gathered to the north of Block 252.
Both the grids over Blocks 152 and 198 and the profile data north of Block
252 as shown by Figure 46A, exhibit a clear lack of propane and butane
anomalies. The presence of mainly methane in the northern areas suggest
that these anomalies are sourced by biogenic gas sources.
Marine compositional crossplots from the anomalies observed in Block 152
and 198, and from the regional profile are shown on Figure 34d for comparison.
All three areas fall exactly as expected, based on the known oil and gas
producing reservoirs within this survey area. As shown by Figure 34d,
both Blocks 198 and 152 are similar to the fairly dry gas type Pleistocene
reservoirs found in West Cameron in the Louisiana offshore and are indicative
of only gas potential. Block 198 sniffer anomalies appear to contain even
drier gas data than Block 152. In contrast, both of these blocks plot
below the cluster associated with the major Pliocene gas producing trend
which lies to the south of Blocks 152 and 198. The increase in ethane,
propane, and butanes in this southern gas producing area suggest that
these gas fields in the southern part of the area surveyed contain Pliocene
gas from a more petrogenic source, whereas the areas to the north appear
to be dominated by biogenic gas sources which don't contain C2 plus components.
It should be noted that the new field discoveries (A-129, A-154 and A-200)
highlighted on Figure 33a were made after the sniffer survey was completed.
The third example cited in this section is an onshore survey conducted
in Railroad Valley, Nevada. This example is abstracted from an integrated
two year (1984-85) remote sensing and surface geochemical research project
which provides an excellent example of the exploration value of combined
remote sensing and geochemical studies in frontier basins (V.T. Jones,
et al. 1985 and S.G. Burtell, et al. 1986). The variability of sample
spacing used over this two year program, coupled with repeated, even closer
detail sampling on grids in 1985 allows a demonstration of the sampling
artifacts that can be created by over interpreting a low density regional
survey. In addition, the repeatability of soil gas surveys are demonstrated
and the compositional correlations of predicting oil versus gas, as shown
in the two previous examples, is significantly extended to differentiating
noncommercial heavy oil deposits from their lighter counterparts, neither
of which contains any significant gas production.
Great Basin, Railroad Valley, Nevada
The first year study in Railroad Valley, conducted in 1984, consisted
of a regional lineament evaluation made from conventional Landsat, Thematic
Mapper (TM), and Synthetic Aperture Radar (SAR), coupled with regional
soil gas probe sampling to identify areas of significant hydrocarbon seepage
(Jones, et al. 1985). Railroad Valley was chosen for this research study
because of the excellent surface expression of structural features, including
both lineaments and circular geomorphic anomalies, which have been used
by Dolly (1979) and Foster (1979) to locate drainage anomalies, interpreted
as reflecting differential subsidence of subsurface structural blocks.
The first three producing fields discovered in Railroad Valley, Eagle
Springs, Trap Spring, and Grant Canyon, occur in circular features mapped
by Dolly and Foster (1979). More recent discoveries in Railroad Valley
have not discounted this proposed association, but has added considerably
to the complexity with the discovery of Paleozoic reservoirs.
Contour maps of the regional methane and propane soil gas data gathered
in 1984 are shown in Figures 35a
and 35b, respectively, along with major structural and geomorphic features
as mapped by Dolly and Foster (1979). Both components exhibit large magnitude
geochemical anomalies which clearly originate at the basin bounding fault
and extend updip onto the adjacent pediment block. A very simplified cartoon,
shown in Figure 36, explains
how this updip migration might occur through fractures and or draped sand
lenses contained within the Tertiary fill.
An alternate approach to contour maps is to generate a color compositional
dot map, as shown in Figure 37,
in which the size of each dot is proportional to the ethane magnitude
and the color is selected from the Pixler ratio plot (see Pixler inset
in upper left corner of Figure 37). Choosing the standard empirical cuts
from Table 5-8 for this data shows that the producing oil fields fall
within the yellow, rather than within the green areas, as would be expected
for the heavy oils produced in Railroad Valley. This color compositional
dot map suggests that it is possible to differentiate between hydrocarbon
type from each site's relative position on these Pixler ratio plots. Eagle
Springs, Trap Springs, and Grant Canyon fields have well controlled intermediate
compositions (yellow dots) while the Currant well area exhibits much lower,
oilier ratios (green dots). Thus hydrocarbon seep compositions observed
in Railroad Valley appear to differentiate productive or potentially productive
reservoirs from non-productive heavy oil accumulations at depth. These
compositional changes are closely related aerially, suggesting that the
compositional changes may occur across geologic boundaries, which control
both the hydrocarbon reservoirs and their associated surface seepage.
The 1984-85 surveys also showed that a large number of high magnitude
seeps occur near to, or on lineaments and lineament intersections in Railroad
Valley (Jones, et al. 1985). This classic relationship reflects one of
the most valuable usages of remote sensing lineament studies in frontier
basins. Preferential location of geochemical samples in the vicinity of
active structural zones and their intersections will usually locate a
large number of the hydrocarbon seeps in any basin. In addition, regions
of intense fracturing which do not exhibit hydrocarbon seepage, strongly
suggests a lack of source potential at depth in such areas.
This combined remote sensing and surface geochemical study in Railroad
Valley also demonstrates a unique surface geochemical expression of one
particular lineament, which appears to have a dramatic effect on the commercial
possibilities for a subsurface oil deposit. The non-commercial Currant
#1 well is located just to the southeast of a NE-SW linear feature, which
crosses the valley through the town of Currant in northern Railroad Valley.
The location of this lineament is obvious on all of the regional remote
sensing products, from conventional Landsat, Thematic Mapper (TM), and
enhanced TM CRT data. Although the lineament is dramatically expressed
both northeast and southwest of Currant, it is not as obvious in the center
of the study area. Even more detailed aerial photography (see Figure
38) yields only a series of fairly short photolineaments, most of
which are drainage segments which are not obviously related to the regional
lineament. As shown by the color compositional dot map in Figure 37, hydrocarbon
seeps to the northwest of the Currant lineament have compositions, as
defined by Pixler ratio plots that are quite similar to the productive
fields in Railroad Valley. Sites southeast of the lineament have a much
oilier signature suggesting a relative depletion of volatiles from the
sources of measured soil gases.
A 400 site detailed grid geochemical survey on 1,000 foot centers was
collected the following year (1985) over this section of the Currant lineament
and further supplemented by aerial photographic studies in an attempt
to characterize the local expression of this regional lineament. An inset
box on the Currant area in Figure 37 shows the location of this second
year study with respect to the 1984 regional survey. High and low altitude
aerial photographic studies reveal that, although the regional feature
is well expressed from TM data, it does not dominate the length, azimuth,
or density of the small scale linear features. The lineament appears only
as a minor group of parallel and subparallel linear features, which are
easily lost in the clusters of more local fracture zones (Figure 38).
The Currant lineament is, however, expressed in gravity data as a trough,
suggesting that it is, in fact, a deep sourced feature of regional significance,
which may influence subsurface fluid and gas migration along or across
Light hydrocarbon soil gas data from the Currant grid area show slight
orientations of anomalous values along the strike of the lineament, however,
it is apparent that the lineament does not control hydrocarbon magnitudes
in this area (Figures 39a
and 39b). Hydrocarbon magnitudes appear to be controlled, to a greater
degree, by the NS and EW small scale linear features (shown on Figure
38), which probably reflect, to some degree, the location of subsurface
structural faults and fault related fracture systems. This relationship
is quite important because structures identified by lineament zones are
generally not the only controlling factor for light hydrocarbon seepage,
but simply provide enhanced pathways of migration for gases and fluids.
The local geologic framework and source potential are the most important
factors for interpreting the relationship of both hydrocarbon seeps and
Compositional data from the Currant grid area adds great insight into
the effect a regional lineament can have on the sources of migrating gases,
even though the lineament is not directly mappable on the local scale.
Regional data from the 1984 Railroad Valley program indicated a compositional
shift across the lineament zone. A methane-ethane crossplot of the 1985
Currant detailed grid data shows two distinct populations, which are separated
areally by the Currant lineament (Figure
40). Pixler ratio plots of anomalous sites support this subdivision
and actually show two distinct populations, with the vast majority of
the gassier sites plotting to the northwest of the lineament (Figure 40a)
on the basin side where deeper sources exist. These two compositional
subpopulations are clearly shown by the yellow to green color change on
the cross plot in Figure 40c, which was first noted in 1984, and confirmed
by the 1985 survey data, as shown in Figure 40. It should be kept in mind
that the color code used for both the dot maps (Fig. 40a) and the cross
plot (Fig. 40c) is determined by plotting the raw soil gas data on the
Pixler diagram. Thus the color compositions are selected to be similar
to analysis of samples from actual producing reservoirs. To have both
spacial and compositional clustering, clearly demonstrates the stability,
and repeatability of light soil gas data if properly collected and analyzed.
This distinct compositional change associated with this regional lineament
suggests that subsurface hydrodynamic processes related to the lineament
may control not only the sources at depth, but also the light hydrocarbon
seepage compositions associated with these potential accumulations at
depth. The lineament may form a barrier to subsurface water flow and divert
fluid flow to the east of the lineament. Oil accumulations east of the
lineament could, therefore, be water-washed, resulting in the non-commercial
heavy oil observed in the Currant #1 well. Potential petroleum reservoirs
west of the lineament may be protected from water-washing, retaining their
volatile constituents, and providing a gassier soil gas signature at the
surface. If this interpretation is correct, it proves the local significance
of this regional lineament system, even though the feature is not immediately
obvious from small scale remote sensing data alone. It is also important
to note that the regional geochemical study conducted in 1984 would not
have been sufficient to support this interpretation, and that close detailed
data gathered in 1985 was required to properly confirm the relationships
between lineaments and hydrocarbon seepage in this case.
It is very important to realize that a regional geochemical survey on
one mile (or even three mile) grids represent a low resolution approximation
to the actual size or shape of any actual geochemical anomaly. As shown
in Figures 39a and 39b, the C1 and C3 detail on 1000 foot centers is very
different from the 1984 regional contour maps. The sharp geochemical boundaries
observed in the 1985 detail study cannot be mapped from the regional 1984
geochemical data. This is shown very clearly in Figure
41, which expands the 1984 propane contour for direct comparison with
the 1985 detailed grid data. Comparison of the magnitudes and compositions
of these two data sets using the color compositional dot maps (see Figure
42) proves that the 1984 data is valid and of good quality. However,
using the 1984 data to draw contours is a serious mistake which results
in an erroneous interpretation as regards the location of this complex
anomaly. The more detailed survey is essential before comparison with
Fracture orientations from the aerial photography overlay define and control
the sharp boundaries of the geochemical anomalies (Jones, et al. 1985).
The Currant lineament cuts right through the center of this major seep
anomaly and appears to have some influence on major fluid flow at depth
(it appears to control the economics of the potential reservoirs). The
shape of the geochemical anomaly is controlled by the bounding fractures,
which are obviously not controlled by this regional lineament.
A comparison of the regional lineaments with the close detailed composite
interpretation from aerial photography shows that the azimuth of the Currant
lineament is expressed only in the short photolineaments. However, the
regional lineament is not obvious from only the short photolineaments
within the valley. Based on just the aerial photography we might suggest
that this lineament is not real; the geochemical data, however, clearly
shows otherwise and clearly shows the value of integrated multidisciplinary
Overthrust Belt, Wyoming-Utah
The final example is one of the largest regional applications of light
gas surface studies ever published. This study, by Dickinson and Matthews
(1993), covers a portion of the Wyoming-Utah overthrust belt with 1890
free soil gas measurements used to investigate 1280 square miles that
includes Clear Creek, Ryckman Creek, and Whitney Canyon-Carter Creek Fields,
in addition to several small fields (Figure
The effective source rocks in the area are believed to be within the subthrust
Cretaceous (Warner 1982). The maturity of these source rocks increases
westward and are responsible for the change in production from mixed oil,
condensate and gas in the east, to dry and wet-gas with some condensate
in the middle, to dry gas in the west.
The compositional information derived from the surface gas study falls
within the gas/condensate-mixed oil/gas classification of Jones and Drozd
(1983). Further, there is a trend towards a more gas prone character from
east to west, in agreement with both the production trends and increasing
source rock maturity. A comparison of the light gas analysis of produced
hydrocarbons with the surface free gases shows that the (C2/C3)x10 values
are in very good agreement for Ryckman Creek and Clear Creek Fields and
in general agreement with respect to the ranges of values for the multiple
reservoirs in Whitney Canyon-Clear Creek Field. The (C3/C1)x1000 ratios,
however, are considerably more methane rich in the surface than in the
subsurface at Ryckman Creek and Clear Creek. This suggests that there
is an independent source of methane in the region that is mixing with
the leakage of the Cretaceous reservoired gases. This independent source
is either absent or much less effective at Whitney Canyon-Carter Creek.
In designing this study, Dickinson and Matthews decided that a sampling
density of two samples per square mile, with approximately uniform distribution
of locations would represent a good compromise between the need for detail
and cost. The regional focus of this study precludes the identification
of all but very broad regions of interest because of the possibility of
the occurrence of single point anomalies due to the coarse sample spacing.
As a result, Dickinson and Matthews developed their cell technique which
we have previously described as an anomaly probability map. Figure
44 shows a composite cell map in which the technique has been applied
to methane, ethane, and propane and the regions where all three of these
gases are above their respective medians has been highlighted. The average
number of sites within a cell was 18. Thus, binomial theory suggests that
cells with more than 75% of the values above the median would be expected
to occur only 5% of the time. The 75% contour line clearly identified
several large areas that occupy more than 5% of the total area. These
regions are statistically anomalous and strongly suggest the occurrence
of above average seepage in these areas. Note the association of these
anomalous areas with Whitney Canyon-Carter Creek, Ryckman Creek and Clear
Creek fields and with the surface trace of the major thrust faults.
If this information had been available prior to the discovery of these
fields, exploration could have been concentrated in the currently productive
region, saving G&G costs and the general type of production and trend
of composition would have been correctly predicted.
Surface and near-surface hydrocarbon occurrences arise as a result of
a complex series of events and interrelationships. Except in rare instances,
surface prospecting cannot reveal the outline of subsurface accumulations,
nor indicate the potential commercial worth of a prospect. It can allow
the explorationist a means to high-grade prospects, but should never be
used as the sole criteria for delineating drilling locations. Surface
soil gas anomalies exist for many understandable reasons, although some
do appear rather random. The interpretation of such data is derived from
the general ability to extrapolate from macroseepage to microseepage,
and the fact that often the surface signal detected is directly correlated
to gross subsurface hydrocarbon composition. Thus surface soil gas prospecting
techniques utilizing hydrocarbons can be a reliable test for indicating
the presence of subsurface hydrocarbon source and/or accumulation.
Present day exploration for oil and gas requires a coordinated effort
based on all useful techniques of geophysics, geology, and geochemistry.
The above discussion on geochemical prospecting techniques are useful
for exploration geologists and geophysicists who wish to enhance their
exploration activities through the use of surface geochemistry. We must
avoid hailing each new technological advance as a panacea, because there
is no direct method for finding oil and gas. Each exploration tool has
its positive and negative points, and it is up to the explorationist to
use these tools properly. The basic program is one of economics in an
era of rising exploration, developing and marketing costs. The function
of an exploration geologist is to increase the odds of drilling a producing
well by every economic means at his command. Given appropriate limitations,
established geochemical prospecting techniques can be applied to aid a
rational exploration program in any basin in the world.
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