2
Chemistry and
Transport of Petroleum
Hydrocarbons
3800 B.C. First documented use of asphalt for caulking reed boats
2.1 INTRODUCTION
An understanding of the chemistry and transport of petroleum hydrocarbons provides
the foundation for forensically reviewing information dealing with petroleum hydro-
carbon contamination. This chapter provides basic terminology and concepts asso-
ciated with the transport and fate of crude oil and refined products in the subsurface.
2.2 CHEMISTRY OF CRUDE OIL
There are over one million types of hydrocarbons in crude oil, ranging from light
gases to heavy residues. No two crude oils are identical. Crude oil is defined by Philip
(1998) as…
…extremely complex mixtures of saturated and aromatic hydrocarbons, ranging from
C
1
to C
100
or higher, plus a wide variety of compounds containing nitrogen, sulfur, and
oxygen. In addition, there is also a fraction called the asphaltene fraction which is
basically insoluble in n-pentane and contains a very complex matrix of high molecular
weight polar compounds.
In most cases, 90 to 98% by weight of crude petroleum consists of hydrocarbons,
while the remaining materials include sulfur, oxygen, nitrogen, and other organic
compounds. Variations in crude oil composition occur due to the nature of the source
of the organic material, the geologic and thermal history, chemical changes that occur
during oil formation and migration, and chemical alteration due to biodegradation,
oxidation, or selective dissolution. Despite wide variations in the chemistry of crude
oil, the elemental compositions fall within a narrow range of elements, as shown on
Table 2.1 (Neumann et al., 1981). Crude oils have normal paraffins (n-paraffins)

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ranging from C
1
to C
40
. Although higher carbon numbers exist in crude oils, most
crude oils fall within the C
5
to C
30
range (Schmidt, 1998).
The predominant hydrocarbon classes that comprise crude oil are straight or branched-
chain alkanes, cycloalkanes, and aromatics. Alkanes (paraffins) are saturated hydrocar-
bons. Linear or normal alkanes (n-alkanes) ranging from C
1
to C
40
have been
identified in crude oil and usually comprise 15 to 20%. In general, the most abundant
alkanes in crude oil are the low-molecular-weight normal alkanes (C
5–10
). Normal
alkanes (n-alkanes) are linear chains of carbons linked by single covalent bonds.
Isoalkanes are hydrocarbons containing branched carbon chains. The highest
concentration of isoalkanes in crude oils is in the C
6
to C
8
range. Crude oil can
contain 10 to 15% isoalkanes.

Cycloalkanes are similar to alkanes except that cycloalkanes consist of rings of
carbon atoms joined by single atomic bonds. Cycloalkanes are abundant in crude oils
and can comprise up to 30 to 40% by weight. The most abundant cycloalkanes (also
called naphthenes) are the single-ring cyclopentanes (C
5
H
10
) and cyclohexanes (C
6
H
12
).
Steranes and triterpanes are complex cycloalkanes often used as markers to identify
the source and age of crude oil (Hughes and Holba, 1988; Seifert and Moldowan,
1978; Stout et al., 1999).
Aromatic hydrocarbons consist of rings of six carbon atoms that are unsaturated
(i.e., they do not contain the maximum number of bonded hydrogen atoms). Aromat-
ics include the BTEX (benzene, toluene, ethylbenzene, and total xylenes) and poly-
nuclear aromatic compounds (PNAs). Aromatic hydrocarbons contain carbon atoms
linked with double bonds, the simplest being benzene (C
6
H
6
). Each hydrogen atom
on the aromatic ring can be replaced with an alkyl group (CH
3
) which results in
compounds such as toluene with one alkyl group attached to the benzene ring.
Benzene rings can be linked to other benzene rings to form compounds such as
biphenyls or terphenyls. When two or more benzene rings are fused, polynuclear

aromatic hydrocarbons (also known as polycyclic aromatic hydrocarbons, or PAHs)
are formed (see Section 4.10 in Chapter 4). Polycyclic aromatic hydrocarbons are
compounds that originate from crude oil and many pyrolysis processes. Polycyclic
aromatic hydrocarbons are of concern because of their genotoxic properties. Naph-
thalene (C
10
H
8
) is a lower molecular weight example and is generally considered to
be a polycyclic aromatic hydrocarbon, although it has only two aromatic rings. Other
non-hydrocarbon components in crude oil include sulfur, oxygen, and nitrogen.
TABLE 2.1
Elemental Composition of Crude Oil
Element Composition (%)
Carbon 84–87
Hydrogen 11–14
Sulfur 0–3
Nitrogen 0–1
Oxygen 0–2
©2000 CRC Press LLC
Sulfur is typically the most abundant element and may be present in several forms,
including elemental sulfur, hydrogen sulfide, mercaptanes, and thiophenes (i.e.,
hydrogen molecules with bonded sulfur atoms). The sulfur content in most crude oils
varies from about 0.1–3% for some of the heavier oils to 5–6% for bitumen. Sulfur
does not decompose during the distillation process. The majority of sulfur is, there-
fore, present predominately in the higher molecular weight fractions and becomes
concentrated in the higher weight refined products. The analysis of the sulfur content
of crude and refined products, such as diesel, can be used to provide evidence to
distinguish between multiple sources. The sulfur content of a petroleum hydrocarbon
is determined using standards such as American Society for Testing Materials

(ASTM) D-124, D-1552, and D-4294.
Oxygen reacts with hydrocarbons to form compounds such as phenols, cresols,
and xylenols. Nitrogen can bond with hydrocarbon molecules in crude oil to form
small concentrations of pyrrole, pyridine, and quinoline. Metals are present in crude
oils, although usually in small amounts. Metals can occur as inorganic salts, metallic
soaps, and organometallic compounds. In some instances, sodium arsenite and
arsenic trioxide are added to oil pumping wells to inhibit corrosion (Rohrbach et al.,
1953; Wellman et al., 1999). The presence of arsenic in crude oil may, therefore,
provide a means for identifying the origin of the crude oil.
2.3 CHEMISTRY OF REFINED PRODUCTS
The chemistry of a refined petroleum product is the result of the composition of the
crude oil and the refining process. The term “refined products” refers to those
petroleum hydrocarbons that are blended and to which additive packages are in-
cluded. Examples of refined products include gasoline, aviation fuels, jet fuel, and
the newer formulations of diesel fuels (Harvey, 1998). Major refinery processes that
affect product chemistry are (Speight, 1991):
• Separation of the crude oil into various fractions
• Conversion of marketable portions of the crude oil
• Finishing of the various product streams
Separation and removal of the various portions of crude oil have historically been
accomplished via distillation. The three products created via distillation are naphtha,
middle distillates, and residual hydrocarbons. Naphtha, with a boiling range of 90 to
190∞C, includes gasoline, which is further processed for octane improvement. The
middle distillate fractions are separated into kerosene (light-end) and diesel range
(heavy-end) products The light-end middle distillates (boiling ranges from 150 to
260∞C) include kerosene, mineral spirits, Stoddard solvent, jet fuels, and diesel No. 1.
Stoddard solvent was used extensively in the first half of this century for degreasing
but was replaced by chlorinated solvents such as trichloroethylene due to the poten-
tial fire hazards associated with Stoddard solvent (Stewart et al., 1991). Examples of
heavy-end products are Bunker fuels, heavy fuel oils, and asphalt. Examples of chro-

matograms for mineral oil, Stoddard solvent, and kerosene are shown in Figure 2.1.
©2000 CRC Press LLC
FIGURE 2.1 Chromatograms of mineral oil, Stoddard solvent, and kerosene. (From Bruya,
J., Chromatograms, Friedman and Bruya, Seattle, WA, 1999. With permission.)
©2000 CRC Press LLC
Heavy-end middle distillates with boiling ranges of 190 to 400∞C are processed
to produce diesel fuel No. 2 and heating oils (Kaplan et al., 1995). Table 2.2
summarizes key distilled products, their distillation temperature range, and carbon
range (Galperin, 1997; Schmidt, 1998). While the distillation temperature and Ameri-
can Petroleum Institute (API) gravity of hydrocarbons provide useful information in
the refining process, they can provide corroborative evidence in distinguishing
among multiple sources of fuel releases. API gravity is defined in Equation 2.1 as:
API gravity = 141.5/P – 131.3 (Eq. 2.1)
where P is the specific gravity of the crude oil or refined product at 60∞F. Evidence
used to distinguish among sources of diesel, gasoline + diesel + jet fuel, and gasoline
at a refinery is shown in Figure 2.2 as a function of API gravity. The API gravity of
each of the various fuels stored at the refinery were known, thereby providing a
baseline for comparison.
The use of the distillation temperature of a fuel to distinguish among multiple
sources (degraded gasoline and a gasoline + diesel + jet fuel mixture) is shown on
Figure 2.3. For the free product samples collected from the groundwater table shown
in Figure 2.2, the initial boiling point (IBP) and final boiling point (FBP) of the fuels
were known, thereby allowing correlation of the IBP and FBP of the samples to
specific locations on the refinery.
The evolution of crude oil refining over time has resulted in different products
and blends of refined product. The unit process and the waste streams from these
processing changes are helpful in age-dating a product and/or bracketing a time
frame when certain refinery processes and their associated waste products were
produced. Table 2.3 summarizes some of the key historical changes in petroleum
refining (Gibbs, 1990; Harvey, 1998).

2.3.1 GASOLINE
Gasoline is composed of low-boiling hydrocarbons in the C
5
to C
10
–C
12
range that are
ignitable in an internal combustion engine. On a chromatograph, fresh gasoline
TABLE 2.2
Distillation Temperature and Carbon Range of Distilled Products
Distillation Temperature
Product (C∞) Carbon Range
Gasoline 30–200 C
5
–C
10/12
Naphtha 100–200 C
8
–C
12
Kerosene and jet fuels 150–250 C
11
–C
13
Diesel and fuel oils 160–400 C
13
–C
17
Heavy fuel oils 315–540 C

19
–C
25
Lubricating oils 425–540 C
20
–C
45
©2000 CRC Press LLC
exhibits an asymmetric distribution pattern from the CH
1
(methylcyclohexane) to
CH
7
(a heptylcyclohexane) range, with the CH
2
peak being the most abundant and
the peaks CH
2
to CH
7
decreasing rapidly in intensity (Galperin, 1997). Gasoline has
a boiling-point distribution from about 120 to 400∞F. As a result of the preferential
partitioning of low-boiling-temperature compounds found in gasoline, the concentra-
tion of the BTEX components can be as high as 1 to 4% for benzene and 3 to 20%
for toluene.
Gasoline blending has changed, in part, to create fuels with different octane ratings.
Examples of gasoline grades are summarized in Table 2.4 (Harvey, 1998). Gasoline
blends often reflect the level of refining. A premium-grade gasoline, for example, is a
FIGURE 2.3 Use of initial (IBP) and final boiling point (FBP) temperatures to identify fuel
types.

FIGURE 2.2 Use of API gravity to distinguish between fuels.
©2000 CRC Press LLC
more tightly regulated blend than a mid-grade or regular gasoline. Chromatograms
of gasoline grades and blends are shown in Figure 2.4 (Zemo et al., 1993).
Changes in the octane ratings of different gasoline grades include a 65 to 75
octane rating in 1910, an average octane rating of 82 in 1946, and an average octane
rating of 96 in 1968 (Gibbs, 1990). The significance of these different gasoline grades
and octane ratings over time is that it is unlikely that forensic testing can identify a
gasoline grade once it has entered the subsurface. Compounds used to provide higher
octane ratings, however, can be identified on a chromatogram. Examples include iso-
octane, toluene, ethylbenzene, xylenes, and trimethylbenzene. For example, a pre-
mium-grade, 1994 gasoline tends to have a high percentage of iso-octane and
aromatics. The greater the combined percentage of iso-octane and aromatic com-
pounds, such as toluene, the higher the octane and fuel quality and, therefore, the
more likely it is that the product was refined and blended.
TABLE 2.3
Chronology of Key Changes in Petroleum Refining in the U.S.
Date Key Refinery Process
1910 Straight run (distilled) products produced; 65–75 octane rating
1913 Dubbs thermal cracking process introduced
1920 Coking introduced
1923 Lead introduced in gasoline to minimize backfiring
1926 Lead anti-knock additive introduced
1928 Lead scavengers ethylene dibromide and ethylene dichloride introduced
1929 Regular and premium gasoline sold
1936 Fluid catalytic cracking introduced
1938 Alkylation introduced
1940 Reforming introduced
1959 Hydrocracking introduced
1970–74 More olefins added to gasoline

1980 Lead regulations
1990 Advent of environmental regulations of sulfur, aromatics, and oxygenates
TABLE 2.4
Grades of Gasoline
Leaded Gasoline Unleaded Gasoline
Super premium leaded Premium or supreme unleaded
Premium or supreme leaded Mid-grade unleaded
“Super regular” leaded Regular unleaded
Regular leaded
Economy leaded
Regular low lead
©2000 CRC Press LLC
Refined gasoline contains olefins (alkenes and alkynes), while crude oils and
virgin naphthas do not. As a result, olefins are useful for distinguishing between
refined and crude oils. Olefins are products of the catalytic cracking process. Olefins
are identified on chromatograms as a cluster of small peaks to the right of the C
6
peak
(Schmidt, 1998). Alkynes (acetylenes) are also not normally found in crude oil.
Another indicator used to distinguish between refined and unrefined products is the
FIGURE 2.4 Gasoline chromatograms. (From Zemo, D. and T. Graf, in Proc. of the 1993
Petroleum Hydrocarbons and Organic Chemicals in Ground Water: Prevention, Detection,
and Restoration, November 10–12, Houston, TX, Ground Water Management Book 17,
National Ground Water Association, Dublin, OH, 1993, pp. 39–54. With permission.)
©2000 CRC Press LLC
presence of methylcyclohexane (MCH). Methylcyclohexane is abundant in unre-
fined gasoline range hydrocarbons and naphthas. In general, the greater the concen-
tration of methylcyclohexane, the less the product has been refined, as well as the
lower the octane rating of the gasoline.
2.3.2 DIESEL

Diesel consists of hydrocarbons in the C
11
to C
18–27
range. Depending on the grade of
diesel, it contains a high concentration of cycloalkanes and smaller amounts of
aromatic compounds (i.e., BTEX). Diesel tends to have greater concentrations of
polycyclic aromatic hydrocarbons than does gasoline. The changing formulation of
diesel provides opportunities for dating a release. Prior to 1975, diesel was primarily
straight chained, while post-1975 diesel was thermally cracked. This distinction can
be determined analytically with only several milliliters of product, thereby providing
a bracket of time when the product was available. Chromatograms of a diesel fuel No.
1 and No. 2 are shown in Figure 2.5.
FIGURE 2.5 Chromatograms for diesel fuels No. 1 and No. 2. (From Bruya, J., Chromato-
grams, Friedman and Bruya, Seattle, WA, 1999. With permission.)
©2000 CRC Press LLC
Diesel is available in various grades. Diesel, kerosene, and the lighter distillates
contain various amounts of the BTEX aromatics up to 1500 parts per million (ppm)
(Dunlap and Beckmann, 1988). The composition and characteristics of diesels and
middle distillate products are described in Table 2.5 (Havlicek, 1986; Kaplan et al.,
1995; Kaplan and Galperin, 1996). A petroleum forensic laboratory to needed to
distinguish between fuels that are similar. Figure 2.6 illustrates chromatograms for
jet fuel No. 4 (JP-4) and jet fuel No. 5 (JP-5) to show the chromatographic similarity
of these two fuels (Bruya, 1999).
TABLE 2.5
Products, Synonyms, and Characteristics of Diesel and Jet Fuels
Product and
Synonym(s) Composition and Characteristics
Diesel No.


1 Similar in composition to a blend of kerosene and diesel No. 2. Diesel No. 1 is
manufactured in cold climates and is also sold in warm climates when a refinery
desires to blend its kerosene with more expensive diesel No. 2. Diesel No. 1 exhibits
an alkylcyclohexane pattern on a mass chromatograph in the range from CH
1
to
CH
14
, with a maximum at CH
5
.
Diesel No. 2 Automotive diesel. Straight-run or catalytically cracked petroleum distillate with a
typical carbon range of C
8–9
to C
24–27
and a boiling range of approximately 163 to
382∞C. Includes straight-run kerosene, middle distillate, hydro-desulfurized middle
distillate, and light catalytically and thermally cracked distillates. Formulated for
use in atomizing-type burners. BTEX components can be present in small amounts.
Using gas chromatography/mass spectrometry (GC/MS), diesel No. 2 shows a
range of alkylcyclohexanes from CH
1
to CH
14
,

maximizing around the CH
9
and

CH
10
peaks. Characterized by a smooth n-alkane distribution pattern.
Diesel No. 4 Railroad diesel. A straight-run or cracked petroleum distillate with a typical carbon
range of C
11
to C
30
. Used without preheating in commercial or industrial burners
that can accommodate a higher viscosity diesel such as diesel No. 4.
Diesel No. 5 A fuel comprised primarily of straight-chained hydrocarbons. Diesel No. 5 is a
residual fuel that often requires preheating for handling.
Bunker C (heating A residual fuel used in commercial and industrial heating. Bunker C requires
preheating for storage and for burning. Sulfur is often found in higher concentra-
tions than in other diesels, unless they are deliberately extracted. Bunker C is the
primary fuel for steam-powered ships and for onshore power-generation plants and
is primarily a mixture of diesel No. 1 and No. 2 and residual oil. Bunker C is a
distillation residue of crude oil and contains biomarkers such as terpanes and
steranes. Bunker C has a hydrocarbon range from C
9
to about C
36
and a boiling point
range of about 340 to 1050∞F.
Kerosene A straight-run distillate with hydrocarbons in the C
9/10
to C
16
range. A light-end
middle distillate used in vaporizing-type burners where the fuel is ignited by contact

with a heated surface or radiation. Consists primarily of paraffins with smaller
amounts of naphthalene and aromatic hydrocarbons. The carbon distribution peaks
around C
12
to C
13
. It is similar in composition to JP-5 and JP-6 jet fuels.
oil or diesel No. 6)
(No. 1 fuel oil)
©2000 CRC Press LLC
2.4 CHEMICAL REACTIONS
IN THE VADOSE ZONE
The physical transport of crude oil and refined products through the subsurface is a
function of product chemistry, the hydraulic conductivity (K) of the soil or rock, and
the presence of a driving mechanism such as rainfall, ponded water, or leakage from
an underground storage tank. An understanding of the relationship between a con-
taminant and the media through which it is transported is used to estimate the relative
Stoddard solvent Used as a drycleaning solvent and paint thinner and in printing inks, certain
adhesives, and some photocopy toners. It consists primarily of nonanes with smaller
amounts of alkylbenzenes. Synonyms include mineral spirits, light petroleum naph-
tha, drycleaning safety solvent, petroleum solvent, varnoline, and spotting naphtha.
Registered trade names include Texsolve S
®
and Varsol 1
®
(ATSDR, 1995). The
boiling range is between 220 and 300∞F. Stoddard solvent exhibits an alkyl-
cyclohexane pattern upon GC/MS in the CH
2
to CH

9
range, with the distribution
maximizing at CH
5
.
Petroleum naphtha Naphtha exhibits an alkylcyclohexane pattern in the CH
1
to CH
6
range that maxi-
mizes at CH
3
.
Jet fuels:
JP-1 Military-grade distillate with a flash point of 95∞F.
JP-4 (Jet B) Military-grade distillate with a flash point of –10∞F and a boiling range of 48 to
270∞C. Contains about 65% gasoline and 35% light distillates. Most of the
volatile gasoline hydrocarbons are absent, and the iso-octane content is generally
below 1%. On a chromatogram, it looks like a light-kerosene and/or gasoline
blend with a considerable amount of aromatic compounds. Using GC/MS, it
demonstrates a distribution pattern in the CH
1
to CH
9
range.
JP-5 (Jet A1) A U.S. Navy distillate with a flash point of 95∞F and a boiling range of 150
to 290∞C. JP-5 has a low freezing point and high flash point for use by carrier-
based aircraft for long-range flights. JP-5 has an alkane distribution pattern in
the kerosene range with a maximum around C
11

. Using GC/MS, a distribution
pattern in the kerosene range (CH
1
to CH
9
) is discernible, with a noticeable
difference in the maximum peak of distribution with CH
5
for JP-5 and CH
4
for
Jet A.
JP-6 (Jet A) Military-grade distillate with a flash point of 100∞F. Preferred for short- and
medium-range aircraft flights.
JP-8 A military aircraft fuel with a distribution pattern around C
10
or C
11
. On a GC/MS,
an asymmetric distribution pattern is observable in the CH
1
to CH
14
range.
TABLE 2.5 (cont.)
Products, Synonyms, and Characteristics of Diesel and Jet Fuels
Product and
Synonym(s) Composition and Characteristics
©2000 CRC Press LLC
mobility and distribution of the contaminant. Contaminant properties impacting the

mobility of a chemical through the unsaturated zone and saturated zones include its
Henry’s Law constant, vapor pressure, density, solubility, and viscosity. If the
petroleum hydrocarbon has a significant volatile component, vapor transport of the
compound can be important.
The chemical and physical interaction of petroleum hydrocarbons in the subsur-
face is important in understanding the mobility of the compound. Commonly
encountered interactions include sorption, oxidation/reduction processes, chemical
precipitation, ion exchange, hydrolysis, biological mediated reactions, and cosolva-
tion.
FIGURE 2.6 Chromatograms of JP-4 and JP-5. (From Bruya, J., Chromatograms, Friedman
and Bruya, Seattle, WA, 1999. With permission.)
©2000 CRC Press LLC
2.4.1 HENRY’S LAW CONSTANT (K
H
)
The Henry’s Law constant (K
H
), also known as the air/water partition coefficient, is
the ratio of the partial pressure of a compound in air to its concentration in water at
a given temperature. The Henry’s Law constant is, therefore, a measure of the
propensity of a compound to volatilize as it migrates through the soil (see Chapter
1, Section 1.3.3).
As the Henry’s Law value increases, the amount of the contaminant in the soil
vapor phase increases. Compounds with high Henry’s Law constants (e.g., butane,
hexane, and benzene) are more amenable to soil gas surveys and remediation via
vapor extraction than compounds with low values.
For the lower alkanes (methane through hexane), the dimensionless Henry’s Law
constant ranges from about 30 to 70 which means that, in equilibrium, 30 to 70
molecules of these alkanes are present in the soil vapor for every molecule that
dissolves into the groundwater. For the BTEX constituents, the Henry’s Law constant

is about 0.25, which means that one molecule of BTEX exists in the soil vapor for every
four that dissolve into the water. As a result, a soil vapor survey is about 200 times more
likely to detect the lower alkanes than BTEX compounds (Hartman, 1998).
2.4.2 LIQUID DENSITY
The relative density (also called specific gravity) of a substance is defined as the ratio
of the density of the substance to the density of distilled water (a mass-to-volume
ratio). The density of distilled water at a standard temperature and pressure is 1.0 g/
mL. Specific density is a unitless measurement but is dependent on the temperature
of the substance at the time of measurement. Light non-aqueous phase liquids
(LNAPLs) have densities less than 1.0, while dense non-aqueous phase liquids
(DNAPLs) have densities greater than 1.0. Most crude, residual, and used oils are
LNAPLs with densities from about 0.6 to 1.0 g/mL.
A contaminant’s density is important, especially when the contaminant enters the
capillary fringe (that partially saturated area above the groundwater table). Liquids with
densities greater than 1.0 (e.g., coal tar) have a greater probability of “sinking” into
groundwater than do liquids with densities less than 1.0 (gasoline, diesel, Stoddard
solvents, mineral oils), which tend to “float” on the water table. BTEX (benzene,
toluene, ethylbenzene, and xylene) compounds are lighter than water, while polycyclic
aromatic hydrocarbons (PAHs) such as anthracene, chrysene, fluorene, naphthalene,
phenanthrene, and pyrene are heavier than water. The term PAH is synonymous with
polynuclear aromatic hydrocarbons (PNAs). These chemicals are often classified as
carcinogenic — benzo(a)pyrene, benzo(a)anthracene, benzo(b)fluoranthene,
benzo(k)fluoranthene, benzo(g,h,i)perylene, chrysene, dibenzo(a,h)anthracene, and
indeno(1,2,3-c,d)pyrene — and noncarcinogenic — naphthalene, acenaphthylene,
acenaphthene, fluorene, phenanthrene, anthracene, fluoranthene, and pyrene.
Hydrocarbons with a high specific gravity are transported vertically in the
unsaturated zone due to gravity and capillary forces. If the volume of high-specific-
gravity hydrocarbons released is large, the hydrocarbons will be vertically transported
©2000 CRC Press LLC
through the soil and groundwater due to density. This phenomenon is known as

density flow. Upon entering the groundwater, these hydrocarbons migrate as a
function of specific gravity and less by advection (the mass transport of groundwa-
ter). Table 2.6 lists the densities of several light and dense hydrocarbons (API, 1989,
1994, 1995; Dragun, 1988).
2.4.3 SOLUBILITY
The solubility of a compound is the saturated concentration of the compound in water
at a known temperature and pressure. The more soluble the compound, the greater
the fraction that dissolves into the soil pore water or groundwater. BTEX compounds
TABLE 2.6
Density of Selected Light and Dense Hydrocarbons
Density (g/cm
3
)
Hydrocarbon 25∞C15∞C
Coal tar 1.028 —
Bunker C (No. 6 fuel oil) 0.969 0.974
No. 5 fuel oil 0.917 0.923
Styrene 0.907 —
No. 4 fuel oil 0.898 0.904
Lube oil (gear oil) 0.883 —
Lube oil (crankcase oil, new) 0.878 —
Lube oil (crankcase oil, used) 0.885 —
North Sea crude 0.8–0.88 —
Benzene 0.874 —
10W40 engine oil 0.866 —
Toluene 0.865 —
Kerosene 0.849 0.839
No. 2 fuel oil 0.840 0 866
Light heating oil 0.82–0.86 —
Marine diesel 0.862 —

Diesel fuel — 0.827
Mineral spirits 0.793 —
Soltrol 0.789 —
Jet fuel 0.77–0.84 —
JP-4 0.755 —
JP-5 0.788 0.844
JP-7 0.779 —
JP-8 0.840 —
JP-A 0.775 —
JP-B 0.757 —
Gasoline 0.720 0.729
Naphtha (petroleum ether) 0.640 —
©2000 CRC Press LLC
are so frequently encountered in groundwater in part due to their high solubility.
Benzene, for example, was detected 23% of the time at 888 Superfund sites based on
a total of 466 chemicals tested for, as of October 1986. Toluene and xylene were detected
27% and 13% of the time, respectively. Toluene was the second most frequently
encountered contaminant, second only to trichloroethylene (TCE; 1100 mg/L at
20∞C) (Siegrist, 1993). Table 2.7 lists those highly soluble compounds in an API PS-
6 unleaded gasoline along with their estimated percent by weight (API, 1985, 1994).
Compounds with high water solubilities tend to desorb from soils, are less likely
to volatilize from water, and are susceptible to biodegradation. Compounds with low
solubilities tend to sorb onto soils and volatilize more readily from water and are
more likely to enter the groundwater. The water solubility of a compound varies with
pH, the presence of inorganic salts, and the presence of organic carbon. Solubilities
of pure phase compounds in water at three temperatures are summarized in Table 2.8
(Havlicek, 1986; Polak and Lu, 1973; Rossi and Thomas, 1981).
BTEX solubility in water is dependent on the nature of the multi-component
mixture, such as gasoline, diesel, or crude oil. The solubility of a constituent within
a multi-component mixture may be orders of magnitude lower than the aqueous

solubility of the pure chemical constituent in water (Odencrantz et al., 1992). The
weight percent and mole fraction of the BTEX components as functions of the
mixture are also important. Table 2.9 presents the calculated effective solubility of
BTEX compounds in gasoline, diesel, and a California crude oil (API, 1985; Metcalf
and Eddy, 1993).
2.4.4 VISCOSITY
Viscosity is the property of a substance to offer internal resistance to flow. An ideal
fluid is one that is devoid of viscosity. A similar but different term is “kinematic
TABLE 2.7
Highly Soluble Components of Gasoline
Compound Percent in Gasoline by Weight
Benzene 1.94
Toluene 4.73
Ethylbenzene 2.0
o-Xylene 2.27
p-Xylene 1.72
m-Xylene 5.66
2-Butene 0.315
a
2-Pentene 0.435
a
Butane 3.83
1,2,4-Trimethylbenzene 3.26
Pentane 3.11
a
Average of cis- and trans
©2000 CRC Press LLC
viscosity” which is the viscosity of the substance divided by its density. The viscosity
of a liquid usually increases with decreasing temperature, though in some complex
mixtures there is a discontinuity in the temperature/viscosity relationship. These

discontinuities occur where there is a large change in viscosity over a very narrow
temperature range. The simplest and most widely used determination of viscosity is
American Society for Testing Materials (ASTM) Standard Method D-445 as de-
scribed in Equation 2.2.
m = p r
4
P/8Nl (Eq. 2.2)
where
m = quantity discharged in units of time.
r=tube radius.
P=pressure difference between the ends of a capillary tube.
N=coefficient of viscosity.
l=tube length.
TABLE 2.9
Effective Solubility of BTEX Components in Gasoline,
Diesel, and Crude Oil
Effective Solubility (ppm)
Compounds Gasoline Diesel California Crude Oil
Benzene 44.39 8.83 0.70
Toluene 26.54 3.25 1.54
o-Xylene 3.26 1.39 0.25
m-Xylene 8.45 1.44 0.26
p-Xylene 3.25 1.82 0.32
Ethylbenzene 2.87 0.55 0.74
TABLE 2.8
Solubility of BTEX Compounds and MTBE
Solubility at 0∞C Solubility at 20∞C Solubility at 25∞C
Compound (ppm) (ppm) (ppm)
Benzene (C
6

H
6
)—1780 1760
Toluene (C
6
H
5
CH
3
) 724 515 573
Ethylbenzene (C
6
H
5
CH
2
CH
3
) 197 153 177
m-Xylene (C
6
H
4
(CH
3
)
2
) 196 158 146–173
o-Xylene (C
6

H
4
(CH
3
)
2
) 142 152 213
p-Xylene (C
6
H
4
(CH
3
)
2
)— — 180–200
MTBE ((CH
3
)
3
C(OCH
3
)) — — 48,000
©2000 CRC Press LLC
While diesel and gasoline viscosities are similar, crude oil has a wide range of
viscosities. For example, the viscosity of a Prudhoe Bay crude oil in Alaska is 73.5
Saybolt units, while a Kern River crude oil from Bakersfield, CA, is greater than
6000 Saybolt units. The viscosity of refined petroleum products varies from about
0.25 to more than 50,000 cPa at 15∞C. An approximate correlation between specific
gravity and viscosity for refined products is described in Equation 2.3.

h
ro
= 8.28r
ro
(9.5)
(Eq. 2.3)
where
h
ro
= ratio of the kinematic viscosity to water.
r
ro
= specific gravity of the refined produced.
As a basis of comparison, the kinematic viscosity for water at 20∞C is 0.01 cm
2
/sec,
while benzene has a kinematic viscosity of 0.00721 cm
2
/sec. Pure benzene flows
about 40% faster than water through identical porous media.
The kinematic viscosity is called dynamic or intrinsic viscosity. Infiltration
velocities are often approximated as a proportionality that is inverse to the kinematic
viscosity. For example, a crude oil can migrate 3 to 35 times slower through soil than
water (Dragun, 1988).
The kinematic viscosity of a hydrocarbon is affected by temperature. For crude
oil, this effect can be several orders of magnitude. Table 2.10 summarizes the
kinematic viscosity of selected heavy fuel oils for two temperatures (API, 1989,
1994; Dragun, 1988). A decrease in viscosity increases the flow rate of a hydrocarbon
through a porous media. During the natural weathering of petroleum products,
viscosity tends to increase sharply.

TABLE 2.10
Kinematic Viscosity of Refined Products
Product Kinematic Viscosity at 10∞C Kinematic Viscosity at 100∞

C
(cSt)
a
(cSt)
a
Gasoline 0.61–0.85 <0.40
Diesel 2.7
b
—
Kerosene 2.3
b
—
JP-4 1.1–1.8 0.47–0.64
No. 1 fuel oil 2.2–4.2 0.7–1.0
No. 2 fuel oil 3.0–8.0 0.85–1.3
No. 4 fuel oil 30–100 2.5–4.8
No. 5 light fuel oil 130–400 5.5–8.0
No. 5 heavy fuel oil 500–1200 9.0–13
No. 6 fuel oil 1500–30,000 15–50
a
One centistoke (cSt) = 1 ¥ 10
6
m
2
/sec.
b

Measured at 15∞C.
©2000 CRC Press LLC
2.4.5 VAPOR PRESSURE AND VAPOR DENSITY
Volatilization is the phase change of a compound from a liquid or solid to a gaseous
phase; it is associated with the vapor pressure of the compound. In general, com-
pounds with vapor pressures exceeding 0.5 to 1 millimeter of mercury (mmHg) can
exist in appreciable concentrations as vapor near a free phase product. Hydrocarbons
that volatilize quickly include butane, pentane, hexane, heptane, and octane. The
aromatic BTEX and methyl ethyl benzenes and trimethylbenzenes also volatilize
quickly but at a rate less than the butanes, pentanes, hexanes, heptanes, and octanes.
The loss of BTEX compounds in a sequential order relative to vapor pressure is often
observed in the analytical data at hydrocarbon-impacted sites.
Vapor density is the density of a compound relative to air (e.g., 29 g/mol). Most
petroleum hydrocarbons have densities 3 to 4 times greater than air. The vapor
density is estimated by dividing the molecular weight of a compound by the molecu-
lar weight of air. The molecular weight of benzene is 78 g/mol; therefore, dividing
78 by 29 yields a vapor density for benzene of 2.5. The vapor density for gasoline
is about 3.3. The significance of vapor density is that petroleum hydrocarbon vapors
can migrate through porous soils in the unsaturated zone as a function of vapor
density (Hartman, 1998).
2.4.6 SORPTION
Sorption is the uptake of a vapor or liquid into another material without reference to
a specific mechanism (Chiou, 1989). Sorption encompasses the processes of adsorp-
tion, absorption, ion exchange, ion exclusion, retardation, chemisorption, and dialy-
sis. Of these processes, absorption (the penetration of substances into the bulk of a
solid or liquid) and adsorption (the surface retention of a solid, liquid, or gas
molecules by a solid or liquid) are the most important. This phenomenon results in
a contaminant’s distribution between the solid and liquid phase and relative retarda-
tion of the chemical. The higher the fraction of the contaminant that is sorbed, the less
is available for transport.

The sorption capacity of a compound is described by the term “sorption coeffi-
cient”. The sorption coefficient is the ratio of an adsorbed chemical per unit weight
of organic carbon to the concentration of the contaminant. It implicitly assumes a
reversible process — that is, sorption and desorption occur at the same rate.
2.4.7 RETARDATION
Retardation is the lowering of the average velocity of a contaminant mass relative
to the average (advective) groundwater velocity. Compounds that sorb strongly to
organic carbon material in soils characteristically have low solubilities; compounds
with low tendencies to adsorb onto organic particles have high solubilities. The
affinity of a compound to be sorbed by organic or mineral matter is called the
retardation factor (R). The retardation factor or coefficient is the ratio of the
©2000 CRC Press LLC
concentration of a compound on a solid to the concentration of that compound in
solution.
Laboratory experiments indicate that values for retardation vary widely, depend-
ing on the type of soil and contaminant. Given the uncertainties associated with
calculating R, compounds with values less than 2 can be considered to be moving at
a rate similar to groundwater. Distribution coefficient values can be obtained from
the literature, calculated from the measured organic carbon content in soil, or
measured from laboratory batch sorption or column transport studies. The most
common technique is to measure the organic content of the soil and obtain the soil/
organic carbon partition coefficient (K
oc
) of the chemical from published tables.
Retardation directly impacts the rate at which a hydrocarbon or components of
a hydrocarbon will move in the subsurface. For example, non-BTEX compounds that
are relatively mobile in water (based on their retardation coefficients) include 1,2,4-
trimethylbenzene, naphthalene, 2-methylnaphthalene, cyclohexane, n-hexane, 2,3-
dimethylbutane, and 2,2-dimethylpentane. Compounds that are relatively less mobile
in water values include benzo(a)anthracene, benzo(a)pyrene, 5-methylchrysene, 1-

methylphenanthrene, and dibenzothiophene.
2.4.8 BIODEGRADATION
Biodegradation is the biological transformation of complex substances into simpler
substances by bacteria, fungi, and yeasts. Hydrocarbon biodegradation is accom-
plished primarily by bacteria. Over 200 soil microbial species have been identified
that can assimilate hydrocarbon substrates. Some of these microbes include Pseudomo-
nas, Flavobacterium, Micrococcus, Mycobacterium, Nocardia, and Acinetobacter
(Bowlen and Kosson, 1995; Manahan, 1984).
For most biodegradation pathways, the final degradation products are carbon
dioxide and water, a process called mineralization. It is possible that the final
mineralization products are not achieved and that the degradation results in relatively
stable aromatic hydrocarbons. While a multitude of degradation reactions can occur,
common transformations occur stepwise from end carbons, producing alcohols,
aldehydes, and fatty acids in sequence.
The rate and ability of microbes to degrade hydrocarbons is dependent on the
ability of the subsurface environment to support a healthy community of microbes.
Conditions that influence the rates of hydrocarbon degradation include soil tempera-
ture, soil porosity, soil moisture content, the oxygen content of the particle spaces,
the nutrient content, and fuel type (Kaplan et al., 1995).
The concentrations of nutrients and oxygen required to sustain viable microbial
communities are highly variable. In general, a 1:20 ratio of available inorganic
nitrogen to the petroleum hydrocarbon and a 1:100 ratio of available phosphate to
petroleum hydrocarbons are necessary to support biological degradation of petro-
leum hydrocarbons.
Some generalizations concerning biodegradation are that biodegradation may not
occur if the concentration of the compound is very low and that most organic
©2000 CRC Press LLC
compounds will degrade to some extent. Current research suggests that benzene is
not degraded under denitrifying conditions and that toluene, xylene, and ethylbenzene
degradation are slow (Kao and Borden, 1997). At the Eglin Air Force Base site, the

preferential removal of toluene and ortho-xylene from the BTEX components closest
to the spill was observed. Ethylbenzene and meta- and para-xylene degradation in-
creased after the toluene and ortho-xylene were depleted (Wilson et al., 1994). It was
also calculated that for the BTEX components within the groundwater approximately
1.0 mg of methane was produced for each 1.3 mg of BTEX destroyed. In general, if
the concentration of petroleum hydrocarbons or heavy metal concentrations are in
excess of 25,000 or 2500 ppm, respectively, then the environment is considered
inhibitory or toxic to aerobic bacteria. Biodegradation commences as soon as the
petroleum hydrocarbon is released into the subsurface, with the lower molecular
weight alkanes degraded first, followed by the higher molecular weight compounds.
The temperature of the surrounding soil or groundwater also impacts degradation
rates. Some of the fastest bioattenuation rates of BTEX compounds observed by the
Environmental Protection Agency’s Robert S. Kerr Environmental Research Labo-
ratory in Ada, OK, have been in cases where groundwater temperatures are high (24
to 28∞C).
Biodegradation rates are influenced by the molecular structure of the hydrocar-
bon. Straight-chained saturated hydrocarbons are degraded more readily than aro-
matics (BTEX compounds), which are subsequently degraded more readily than
alicyclics and highly branched aliphatic hydrocarbons. As a result of these hydrocar-
bon degradation sequences, alicyclics and highly branched aliphatics accumulate in
the soil, while the more biodegradable of the compounds in the original product are
not present. In general, the weathering of gasoline, diesel, and Bunker C fuel
proceeds in the following temporal sequence (Galperin, 1997):
1. Abundant normal alkanes
2. Light-end normal alkanes
3. Middle-range normal alkanes, olefins, benzene, and toluene
4. More than 90% removal of the alkanes
5. Alkylcyclohexane and alkybenzenes
6. Isorepnoids and C
0

-naphthalene reduction
7. C
1
-naphthalenes, benziothiophene, alkylbenzothiophenes, and C
2
-naphthalenes
8. Phenanthrenes, dibenzothiophenes, and other polynuclear aromatic hydrocarbons
9. Tricyclic terpane enrichment, selective removal of regular steranes, reduction of
C
31
–C
35
homohopanes
10. Increased abundance of tricyclic terpanes, diasteranes, and aromatic steranes
The biodegradation of specific petroleum fractions in a fuel has been proposed
as a means to age-date a hydrocarbon (Kaplan et al., 1995; Morrison, 1997; Raymond
et al., 1976). The basis of this approach is reliance on the biodegradation half-life of
hydrocarbon compounds in the soil or groundwater. The estimated half-life is the
time required for one half of the compound to biodegrade. The rate of biodegradation
is usually expressed in units of g/m
2
day
–1
, g/m
3
year
–1
, mg/day per bacterial cell,
percent of oil removed after a known number of days or weeks, or g/m
3

day
–1
. A
©2000 CRC Press LLC
summary of the half-lives of selected BTEX and polynuclear aromatic hydrocarbon
(PAH) compounds is provided in Table 2.11 (API, 1985; Howard et al., 1991).
2.5 OVERVIEW OF TRANSPORT THROUGH
THE UNSATURATED (VADOSE) ZONE
The unsaturated zone is that portion of the subsurface situated between the ground
surface and first water-bearing formation. Surface releases of hydrocarbons usually
transit this zone prior to entering the groundwater. Physical parameters used to
describe soils and used in petroleum transport calculations include porosity, perme-
ability, hydraulic conductivity, and gas permeability.
The transport of petroleum hydrocarbons through soil can change the hydraulic
conductivity of the native soil, if the hydrocarbons are the primary wetting fluid (as
opposed to water). This can occur with a massive release in which the hydrocarbons
displace the water between the soil grains. It is a physical process and is reversible;
if water subsequently displaces the petroleum hydrocarbons, the hydraulic conduc-
tivity will significantly decrease. These changes usually occur due to the permeation
by nonpolar organics with clay. Typically, these changes are related to the following
mechanisms: dehydration, swelling, flocculation, and macroscopic cracking (Ander-
son et al., 1985; Daniel et al., 1986).
Unsaturated hydraulic conductivity values for the vadose zone are obtained in the
field or laboratory by measuring the hydraulic conductivity of a soil under saturated
TABLE 2.11
Biodegradation Half-Lives of BTEX and PAH Compounds
Biodegradation Half-Life (hr)
a
Compound Soil Groundwater
Benzene (C

6
H
6
) 120–384 240–17,280
Toluene (C
6
H
5
CH
3
) 96–528 168–672
Ethylbenzene (C
6
H
5
C
2
H
5
) 72–240 144–5472
o-, m-, p-Xylene (C
6
H
4
(CH
3
)
2
) 168–672 336–8640
Acenaphthene (C

12
H
10
) 299–2448 590–4896
Anthracene (C
14
H
10
) 1200–11040 2400–22,080
Benzo(a)pyrene (C
20
H
12
) 1368–12,720 2736–25,440
Chrysene (C
18
H
12
) 8904–24,000 17,808–48,000
Fluoranthene (C
10
H
10
) 3360–10,560 6720–21,120
Fluorene (C
13
H
10
) 768–1440 1536–2880
Naphthalene (C

10
H
8
) 398–1152 24–6192
Phenanthrene (C
14
H
10
) 384–4800 768–9600
Pyrene (C
16
H
10
) 5040–45,600 10,080–91,200
a
Measured at 25∞C.
©2000 CRC Press LLC
conditions and then allowing the water to drain from the soil. The resulting graph that
plots the percent moisture vs. soil suction is called a soil moisture characteristic curve.
A dry soil exhibits greater soil suction than a wet soil. A soil characteristic curve enables
calculation of the hydraulic conductivity as a function of soil moisture content.
2.5.1 TRANSPORT THROUGH SOIL
The fundamental principles governing advective (mass) transport of water in soil
generally apply to those for hydrocarbon transport (i.e., gravity and capillarity).
Hydrocarbons move through the soil under a three-phase flow condition, displacing
air and water. Variations in soil permeability result in a deviation from the gravita-
tionally dominated vertical flow; as the hydrocarbon encounters layers of slightly less
permeable materials or materials with smaller pores, it will tend to flow mostly in the
horizontal direction until it encounters a path of less resistance. This conceptual model
is more complex, however, because other transport and transformation processes occur.

If a large volume of gasoline or diesel is released at or near the surface, it initially
tends to infiltrate vertically through the soil. If the volume of release is sufficient to
overcome the residual soil-retention capacity, the migration of the hydrocarbon will
continue until the fluid reaches the capillary fringe, where it accumulates (Bossert and
Bartha, 1984). As the hydrocarbon is transported through the soil, it may encounter less
permeable soils that create a boundary condition; this may result in lateral spreading
until a more permeable horizon is encountered for the hydrocarbon to move vertically.
On a soil particle scale, petroleum hydrocarbon distribution in soil is dependent
on the pore size between the soil grains and the pore pressures of the air, water, and
hydrocarbons occupying these pore spaces. If the hydrocarbon completely saturates
the soil and displaces water in the soil, maximum lateral and vertical spreading will
occur. Gasoline components will also preferentially dissolve from the bulk hydrocar-
bon and migrate at different velocities through the soil (as well as the groundwater).
This phenomenon is called chromatographic separation, which is often observed in
the separation of more mobile compounds such as methyl-tertiary-butyl-ether (MTBE)
moving ahead of the center of mass of a hydrocarbon in groundwater.
2.5.2 COSOLVATION AND COLLOIDAL TRANSPORT
Cosolvation (also referred to as cosolvency) is the enhancement of an otherwise low
mobility compound by its preferential dissolution into an organic solvent. Cosolvation
occurs when a mobile phase is formed from multiple solvents that are miscible in
each other (Kargbo, 1994). The addition of a cosolvent decreases the retardation and
sorption coefficient of hydrophobic organic compounds such as polycyclic aromatic
hydrocarbon compounds. For soils, cosolvation is shown to increase mobility signifi-
cantly only at high cosolvent concentrations, usually greater than about 5% of the
solution (Nkedi-Kizza et al., 1987). Cosolvation has been demonstrated to enhance
the solubilization of sparingly soluble compounds in the pharmaceutical literature
and in soil research (Lane and Loehr, 1992).
©2000 CRC Press LLC
Another example illustrating cosolvation is the detection of the polynuclear
aromatic (PNA) naphthalene and a solvent, such as methanol, at depth. The solubility

of naphthalene in various solvents is as follows: 30 mg/L in water, 77 g/L in ethanol
and methanol, 285 g/L in benzene and toluene, and 500 mg/L in chloroform and carbon
tetrachloride. The presence of methanol and naphthalene at depth would, therefore,
suggest the preferential transport of naphthalene to depth via cosolvation with
methanol. Another example is the release of oxygenated fuels into soil containing
PAHs. The theoretical sorption of a PAH coefficient decreases exponentially as the
fraction of the organic solvent increases (Chen et al., 1977); therefore, the presence of
an oxygenate such as MTBE in the fuel can enhance the transport of PAHs, as well as
benzene, toluene, ethylbenzene, and xylene present in the soil due to cosolvency effects.
2.5.3 RESIDUAL SATURATION
Residual saturation is defined as the fraction of total soil space filled with a liquid due
to capillary forces. As hydrocarbons migrate through soil, a small amount of the total
hydrocarbon mass remains attached to these soil particles via sorption. The hydro-
carbon retained by the soil particles is known as residual or immobile saturation. The
percentage of residual saturation remaining in a soil is dependent on soil moisture
content, soil porosity, and soil texture. The residual saturation for light oil and
gasoline is about 1% of the total soil porosity; for diesel and light fuel oil, 15%; and
for lubricating and heavy fuel oil, about 2%. Residual saturation estimates are
routinely used to estimate the volume of recoverable hydrocarbon in the soil. Re-
sidual saturation values are measured directly by collecting a representative soil
sample and saturating it with the petroleum hydrocarbon of concern, followed by
allowing the soil to drain for several days and then measuring the volume of
hydrocarbon retained by the soil.
The viscosity of a fuel affects its residual saturation. As the viscosity decreases,
the residual saturation concentration decreases (Hoag and Marley, 1986). Theoretical
studies suggest that the residual saturation increases proportionally to the fourth root
of the product’s viscosity. Table 2.12 lists the residual saturation of petroleum
products in soils (Dragun, 1988). Residual saturation is significant because it remains
as a source of contamination via water infiltrating through the soil column coming
TABLE 2.12

Residual Saturation (mg/kg) of Refined Products in Soil
Soil Type Gasoline No. 2 Fuel Oil Lube Oil No. 6 Fuel Oil
Coarse gravel — 800 1600 —
Gravel to coarse sand — 1600 3200 —
Coarse to medium sand — 2800 5600 —
Medium to fine sand 2000 4800 9600 60,000
Fine sand to silt — 8000 16,000 —
©2000 CRC Press LLC
into contact with the residual hydrocarbons. Seasonal changes in groundwater level
can resolubilize residual hydrocarbons into the groundwater, a fact that is reflected
in downgradient monitoring wells as a seasonal trend of high and low concentrations
of BTEX concentrations coinciding with the fluctuating water table.
Residual saturation contamination of soils by hydrocarbons can occur in soil
downgradient of a spill that may be on an adjacent property. This situation occurs
when free product on the water table comes into contact with otherwise clean soils
above it due to a rising water table. When the groundwater drops, the previously
clean soil contains a certain percentage of residual saturation. Previously uncontami-
nated soils now become a source for further contamination. This phenomenon is
important to consider when examining soil gas survey data as indicators of the source
of contamination, especially with shallow groundwater. Soils with residual hydrocar-
bon downgradient of the original spill may volatilize, resulting in the appearance of
a release and/or masking of the original source of the contamination.
2.5.4 VAPOR PHASE TRANSPORT
The volatile component of hydrocarbons (BTEX compounds) often partition into
their gaseous state and are present in the subsurface along with the liquid phase
hydrocarbons. The term “volatile hydrocarbons” refers to those compounds with
vapor pressures greater than 1 mmHg or 0.001 atm. The transport of these gases is
about 100 times faster in soils than in the groundwater and is described in Equation
2.4 by a general form of Darcy’s Law as:
v = –k/m(—P + rg) (Eq. 2.4)

where
v = velocity of laminar air flow through the soil.
k = intrinsic permeability.
m = viscosity.
P = pressure head difference.
r = fluid density.
g = acceleration due to gravity.
The transport of gas occurs due to several transport mechanisms, including
diffusion, convection, and gravity-driven flow; the effective porosity of the soil and
the contaminant’s vapor density are also important. Other factors include air tem-
perature and, for near-surface soil, barometric pressure. In general, molecular diffu-
sion is the dominant transport for the gas phase.
The driving force of convective flow is the gradient of the total gas pressure
which results in the movement of air mass from an area of higher pressure to an area
of lower pressure. In the case of diffusion, the driving force is the partial pressure
gradient of each gaseous component in a gas mixture. It is believed that in most cases
diffusion is the dominant transport mechanism.
©2000 CRC Press LLC
Gravity-driven flow is the tendency of the vapor to move within the vadose zone
as a function of density. The presence of relatively high concentrations of volatile
compounds detected at the bottom of coarse-grained sediments is an example of this
transport mechanism.
The importance of effective porosity for liquids is identical to that for gas; open
space in the soil must be available for the gas to migrate. In sandy soils, as much as
25% of the volume is air; in loamy soils, it is generally between 15 and 20%; and in
clayey soils, the volume of air space is usually below 10% of the total volume.
As vapor density increases, the potential for the gas to move vertically through
the soil column increases. Vapors move through the soil as a function of the
concentration gradient of the contaminant via diffusion as described by Fick’s Law.
The movement is therefore away from areas of high concentration to areas of

low concentration. Another mechanism is temperature; a temperature gradient in the
soil creates a driving force with volatile compounds moving from areas of high to
low soil temperature. Pressure fluctuations due to barometric pressure changes and
wind across the soil surface can also impact the movement and dispersion of soil
gas in shallow soils (Rolston, 1986). The vapor density of a substance is the
mass of vapor per unit volume. Gases that are heavier and lighter than air are listed
in Table 2.13.
A related characteristic is vapor pressure, which is the pressure exerted by the gas
of a substance in equilibrium conditions. Vapor pressure provides a qualitative rate
at which a compound volatilizes from soil. Table 2.14 is a list of vapor densities and
pressures for commonly encountered hydrocarbons (API, 1994; Luhrs and Stewart,
1992). Soil gas surveys using this property to locate sources of soil and groundwater
contamination commonly report the results as parts per billion per volume (ppbv). A
useful conversion is that 250 ppbv is equal to about 1 mg/L in the vapor phase.
While organic contaminants are absorbed onto organic matter, research has
shown that volatile organic compounds in a gas phase can also sorb onto dry soils.
Mineral matter in dry soils, for example, can adsorb TCE from the vapor phase
(Peterson et al., 1988). Research comparing the uptake of volatile compounds onto
wet vs. dry soil shows that vapor uptake on dry soils is greater than for wet soils.
These findings also indicate that vapor uptake is suppressed by the presence of water
TABLE 2.13
Vapor Densities of Gases Relative to Air
Gases Lighter than Air Gases Heavier than Air
Hydrogen Gasoline
Ammonia Chlorine
Acetylene Alcohol
Methane N-gas Acetone
Ethylene Ethylene dibromide
Helium Propane
©2000 CRC Press LLC